Section III.C of this preamble presents projections of the emissions changes due to this proposed rule. For this proposal, the EPA did not conduct air quality modeling to determine how these emissions increases could change the ambient concentrations of air pollutants. Making predictions about air quality based solely on emissions changes is extremely difficult because the atmospheric chemistry related to ambient concentrations of PM, ozone, and air toxics is very complex, and the emissions changes are spatially variable. Nevertheless, considering the air quality modeling conducted for recent vehicle rules and the relatively small projected increase in total onroad emissions from this proposal, overall, the EPA expects relatively small changes in ambient concentrations of air pollutants from this proposal. 66

Air pollutants emitted from motor vehicles impact public health, welfare, and the environment. Motor vehicle emissions contribute to ozone, PM 2.5, and air toxics, which are linked to premature death and other serious health impacts, including respiratory illness, cardiovascular problems, and cancer. This air pollution affects people nationwide, especially those who live or work near transportation corridors. Detailed information on the health and welfare effects associated with exposure to pollutants impacted by this proposed rule can be found in sections II.B-D of the LMDV Multipollutant Rule's preamble and Chapter 6 of the LMDV RIA. 67

The EPA sometimes performs air quality modeling to conduct a full assessment of the PM 2.5 -related and ozone-related human health benefits of the Agency's regulatory actions. As discussed in section III.D of this preamble, the EPA did not conduct air quality modeling for this proposal.

The EPA is obligated to present the Agency's best scientific understanding and the implications of that science when developing policies and regulations. However, historically, the EPA's analytical practices may not have presented the full range of uncertainties and associated confidence level regarding the potential benefit estimates from reduction in exposure to PM 2.5 and ozone. In addition, the science regarding the exposure, health effects from exposure, and valuation of reduction in health effects are evolving with better data and methods, especially at low concentrations of PM and ozone. The EPA's use of benefit per ton (BPT) monetized values introduces additional uncertainty. Although developed as a screening tool when full-form photochemical modeling was not feasible, the BPT approach reduces complex spatial and atmospheric relationships and may be more suited to model emissions that are geographically more uniform and the pollutant species are better mixed, thereby adding uncertainty associated with those estimates. Some of the sources of uncertainties include the set of assumptions used in projecting the health impact of reducing PM. These projections are based on a series of models that take into account emissions changes, the resulting distributions of changes in ambient air quality, the estimated reductions in health effects from changes in exposure, and the composition of the population that will benefit from the reduced exposure. Each component includes assumptions, each with varying degrees of uncertainty.

In addition, the EPA historically provided point estimates rather than just ranges of emission-related effects or only quantifying emissions when monetizing proved to be too uncertain. Therefore, to address these concerns, the EPA is refraining from providing primary estimates resulting from changes in PM 2.5 and ozone exposure resulting from changes in direct PM 2.5 , NO X , and VOC emissions but will continue to quantify the emissions until the Agency is confident enough in the modeling to robustly monetize those impacts.

A more robust description of the potential health and welfare disbenefits associated with emissions increases due to the proposal is contained in Chapter 2.3 of the DRIA for this proposed rule.

The EPA is soliciting comment on key aspects of the proposed rule, although the Agency is not limiting comment to these identified areas. To facilitate comment on those portions of the rule, the EPA has indexed each comment solicitation with a unique identifier below ( e.g., “C-1,” “C-2”) to provide a consistent framework for effective and efficient provision of comments. Accordingly, the EPA asks that commenters include the corresponding identifier when providing comments relevant to that comment solicitation. The EPA asks that commenters include the identifier either in a heading or within the text of each comment to make clear which comment solicitation is being addressed. Specifically, the EPA is soliciting comment on the following aspects:

C-1. The EPA requests comment on all aspects of this proposed rule, including all elements of this preamble, the proposed regulatory changes, and the DRIA (including projected impacts), that are not otherwise enumerated below.

C-2. The Tier 3 NMOG+NO X program includes several specific emission bins from which manufacturers must choose when certifying each vehicle family, for example, Bins 20, 30, and 50. All vehicles within a given Bin must have NMOG+NO X emissions below the Bin value, so a Bin 50 vehicle family must all be at or below 50 mg/mile. In the Tier 4 program, the EPA created several additional NMOG+NO X Bins with smaller increments between the Bins. For example, the EPA added Bins 25, 35, 40, and 45. The EPA requests comment on if the Agency should add to the Tier 3 program the additional NMOG+NO X Bins available in the Tier 4 program for MYs 2027 and 2028. Doing so could provide additional flexibility to vehicle manufacturers for demonstrating compliance with the NMOG+NO X fleet average standard.

C-3. The EPA requests comments on the use of the ABT program for NMOG+NO X emissions in MYs 2027 and 2028 and how the use of the ABT program may affect the cost analysis presented here and in the DRIA.

C-4. The EPA requests comments on whether the Tier 3 program should be extended for three MYs, through MY 2029, instead of two MYs.

C-5. The EPA knows that manufacturers have already started certifying vehicles to the interim and final Tier 4 standards. The EPA requests comment on the treatment of MYs 2027 or 2028 vehicles certified to the final Tier 4 standards once the Tier 4 phase-in schedule is revised. The EPA is presenting the following initial framework for this issue:

• Certificates of conformity issued for interim or final Tier 4 vehicles will remain valid throughout their full useful life (FUL). Thus, a manufacturer may keep selling a Tier 4 vehicle under its Tier 4 certificate of conformity.

• The Tier 4 NMOG+NO X sales-weighted values will be combined with the Tier 3 NMOG+NO X sales-weighted values from the same MY.

C-6. The EPA requests comment on any modifications of the Federal OBD requirements needed to support this action for MYs 2027 and 2028 vehicles.

C-7. The EPA requests comment on the economic impacts of potential noncompliance with MYs 2027 and 2028 standards, including costs associated with revised product plans and sunk development costs, to adjust the economic analysis.

C-8. The EPA requests comment on the challenges associated with integrating GPFs on light- and medium-duty vehicles in MYs 2027 or 2028, especially regarding what has changed that renders the extensive public record insufficient to justify manufacturers installing this technology.

C-9. The EPA requests comment on the projected MYs 2027 and 2028 BEV sales estimates used for assessing the cost and emissions impacts of this proposal, as detailed in the Draft RIA.

C-10. The EPA requests comment on whether regulated parties have any significant reliance interests with respect to MYs 2027 and 2028 Tier 4 criteria pollutant standards.

In this action, the EPA is not requesting comment on any provisions of the Tier 4 program for MYs 2029 and later.

Additional information about these statutes and Executive Orders can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders.

This action is an economically significant regulatory action as defined under section 3(f)(1) of Executive Order 12866. Accordingly, it was submitted to the Office of Management and Budget (OMB) for review. Any changes made in response to OMB recommendations have been documented in the docket. The EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis, Revision of Tier 4 Phase-In Schedule for Light-Duty and Medium-Duty Vehicles: Draft Regulatory Impact Analysis (April 2026) EPA Technical Report EPA-420-D-26-001 (“DRIA”) is available in the docket, Docket ID No. EPA-HQ-OAR- 2025-3297. This analysis is described further in section III.B of this preamble. The estimated cost savings presented in Table 13 include the effects of several sources of uncertainty associated with the estimates of costs, such as estimates of BEV market share and variations in catalyst loading in TWCs, which are discussed in Chapter 1 of the DRIA.

This action is expected to be an Executive Order 14192 deregulatory action.

This proposed action does not impose any new information collection burden under the PRA. This proposed action does not change existing information collection requirements.

I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA. In making this determination, the EPA concludes that the impact of concern for this rule is any significant adverse economic impact on small entities and that the Agency is certifying that this rule will not have a significant economic impact on a substantial number of small entities because the rule relieves regulatory burden on the small entities subject to the rule. The regulated entities that are subject to the regulations we are proposing to delay in this proposed rule are vehicle manufacturers and importers. The EPA is certifying that this proposed action would not have a significant economic impact on a substantial number of small entities because the proposed action would relieve regulatory burden on all entities, including all small entities, subject to the current rules. The EPA does not anticipate that there would be any significant adverse economic impact on directly regulated small entities as a result of these revisions. The EPA has therefore concluded that this proposed action would, if finalized, relieve regulatory burden for all directly regulated small entities.

This action does not contain an unfunded mandate of $100 million (adjusted annually for inflation) or more (in 1995 dollars)] as described in UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments. The action imposes no enforceable duty on any State, local, or Tribal governments or the private sector.

This action does not have federalism implications. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.

This proposed action does not have Tribal implications as specified in Executive Order 13175. This proposed action would extend the EPA Tier 3 criteria pollutant standards by two years and amend the phase-in schedule for the Tier 4 criteria pollutant standards. If finalized, it would not have substantial direct effects on Tribal governments, on the relationship between the Federal government and Indian Tribes, or on the distribution of power and responsibilities between the Federal government and Indian Tribes, as specified in Executive Order 13175. Thus, Executive Order 13175 does not apply to this proposed action.

Executive Order 13045 directs Federal agencies to include an evaluation of the health and safety effects of the planned regulation on children in Federal health and safety standards and explain why the regulation is preferable to potentially effective and reasonably feasible alternatives. This action is subject to Executive Order 13045 because it is an economically significant regulatory action under section 3(f)(1) of Executive Order 12866, and the EPA believes that the environmental health or safety risk addressed by this action may have a disproportionate effect on children. Furthermore, EPA's Policy on Children's Health also applies to this action. 68

Children are not expected to experience greater ambient concentrations of air pollutants than the general population. Children are more susceptible than adults to air pollution and children tend to spend increased time outdoors. Children make up a substantial fraction of the U.S. population and often have unique factors that contribute to their increased risk of experiencing a health effect from exposures to ambient air pollutants because of their continuous growth and development. Children are more susceptible than adults to many air pollutants because they have (1) a developing respiratory system, (2) increased ventilation rates relative to body mass compared with adults, (3) an increased proportion of oral breathing, particularly in boys, relative to adults, and (4) behaviors that increase chances for exposure. Even before birth, the developing fetus may be exposed to air pollutants through the mother that affect development when the mother is exposed. A qualitative description of the human health and welfare effects related to emissions changes associated with this proposal is provided in Chapter 2 of the DRIA for this proposed rule.

This action is not subject to Executive Order 13211, because it is not a significant regulatory action under Executive Order 12866.

This action involves technical standards. Therefore, the EPA conducted a search to identify potentially applicable voluntary consensus standards. However, the EPA identified no such standards. Therefore, the EPA has decided to use EPA standards. The following standards appear in the amendatory text of this document: California's 2013 OBD-II and California's 2022 OBD-II. No changes are proposed to this IBR material. California's 2013 OBD-II is referenced in the amendatory text of this document and has already been approved for § 86.1806-17. California's 2022 OBD-II was previously approved for § 86.1806-27, but § 86.1806-27 is proposed to be redesignated as § 86.1806-29.

Statutory authority for this proposed rule is found at 42 U.S.C. 7401-7675, especially 42 U.S.C. 7521.

For the reasons stated in the preamble, the U.S. Environmental Protection Agency proposes to amend parts 85, 86, and 1066 of title 40, chapter I, of The Code of Federal Regulations as follows:

The EPA is proposing this rule to update requirements that apply to wastewater discharges from steam electric power plants, particularly coal-fired power plants. In 2024, the EPA finalized revisions to the technology-based effluent limitations guidelines and standards (ELGs) for the steam electric power generating point source category that imposed stringent requirements on certain wastewaters from these plants, requiring the facilities not to discharge any pollutants or imposing non-zero numerical limitations on pollutants from certain types of industrial wastewaters (89 FR 40198, May 9, 2024) (hereinafter the “2024 ELG”).

Subsequent to promulgation of the 2024 ELG, the EPA became aware of new information regarding the retirement status of a number of plants as well as updates some dischargers have made to their wastewater treatment in place. The EPA also identified a flaw in the baseline utilized by the 2024 ELG as it pertains to unmanaged combustion residual leachate (CRL) by omitting capture and pumping costs, an important component of the technology basis. The EPA's revised analysis presented shows these costs imposed by the 2024 ELG are not insignificant. As such, the EPA is concerned about other cost elements that could be impacted by the Agency's assumptions that 100 percent of the contaminated groundwater could in fact be captured and treated, and the Agency's assumptions regarding power plants' ability to achieve the 2024 ELG numerical limitations. The EPA is also concerned that the 2024 ELG may not have fully accounted for the lack of revenue generated by closed utilities, and thus the lack of funding available, to implement treatment in an economically achievable way. In addition, despite the EPA previously acknowledging very little data that characterizes groundwater laden with unmanaged CRL, commenters have not provided any additional data to help characterize this wastestream. In light of the increasing costs, the EPA is now reconsidering the characterization data gap and how it may impact costs.

In the time following the promulgation of the 2024 ELG, the U.S. has experienced extraordinary increases in energy demand, decreases in energy reserves, difficulties in transmission across the electricity grid, increases in energy prices, and heightened concerns about energy reliability. Consequently, in March 2025, EPA Administrator Zeldin announced that the Agency would reconsider 2024 pollution limitations for coal-fired power plants. The EPA identified additional information that showed that, due to supply chain logistical challenges as well as the unique characteristics of each plant's operational needs, the deadlines to comply with the 2024 ELG were infeasible and impractical on a nationwide basis. In late 2025, the EPA issued a final rule that, in part, extended compliance deadlines for many of the zero-discharge requirements in the 2024 ELG and the deadline for facilities to submit a Notice of Planned Participation for the permanent cessation of coal combustion. These compliance deadline extensions gave utilities and permitting authorities the flexibilities needed to ensure affordable and reliable power (90 FR 61328; December 31, 2025) (hereinafter the “2025 Deadline Extensions Rule”). The 2025 Deadline Extensions Rule did not change the underlying technology bases for the 2024 effluent limitations based on BAT. Subsequent to the 2025 Deadline Extensions Rule, the EPA intended to further evaluate data obtained after the promulgation of the 2024 ELG, as well as data submitted during the 2025 Deadline Extensions Rule public comment period, to determine if further rulemaking for reconsidering the BAT requirements imposed by the 2024 ELG is appropriate.

This proposed rulemaking continues to advance the Trump Administration's commitment to unleash American energy by revising the existing Steam Electric ELG for unmanaged combustion residual leachate to ensure the 2024 ELG does not financially cripple this critical industry or contribute to burdensome energy costs for American families. CRL is leachate from landfills or surface impoundments (collectively called waste management units) that contain coal combustion residuals (CCR). Leachate is composed of liquid, including any suspended or dissolved constituents in the liquid, that has percolated through waste or other materials emplaced in a landfill or that passes through the surface impoundment's containment structure ( e.g., bottom, liner, dikes, berms). CRL is typically managed using a liner and leachate-collection system. The primary function of the leachate-collection system is to collect and convey leachate out of the landfill unit and to control the depth of the leachate above the liner. In contrast, many CCR landfills and surface impoundments also have unmanaged CRL, which is distinct from managed CRL. Unmanaged CRL is leachate that is not captured from a leachate-collection system and instead percolates out of the landfill or impoundment unit and into the subsurface. These CRL wastestreams are defined in the current Steam Electric ELGs, and the EPA is using the same definition of unmanaged CRL as it did in the 2024 ELG.

Unmanaged CRL is a complex wastestream from coal-fired power plants. The extent to which unmanaged CRL exists at any given plant is variable and not well documented, the characterization of the unmanaged leachate significantly varies by location, and unmanaged leachate discharges can fluctuate rapidly and extensively. Additionally, unmanaged CRL is one of the more costly wastestreams for coal-fired power plants to manage effectively because, in addition to the treatment technologies themselves that must be sized to accommodate a large volume of flow, a potentially complex and costly system for extracting large volumes  1 of CRL laden wastewater must be installed. This proposal describes the challenges addressing unmanaged CRL, offers a range of regulatory options based on different known technologies, and solicits comment and data on the availability, performance, feasibility, and costs of each proposed option. This proposal only pertains to unmanaged CRL and does not include any proposed changes to managed CRL requirements imposed by the 2024 ELG.

Entities potentially regulated by this action include:

This table is not intended to be exhaustive but rather provides a guide for readers regarding entities likely to be regulated by this action. This table includes the types of entities that the EPA is aware could potentially be regulated by this action. Other types of entities not included could also be regulated. To determine whether your entity is regulated by this action, you should carefully examine the applicability criteria found in 40 CFR 423.10 (Applicability). If you have questions regarding the applicability of this action to a particular entity, consult the person listed in the FOR FURTHER INFORMATION CONTACT section.

The authority for this rulemaking is the Federal Water Pollution Control Act, 33 U.S.C. 1251 et seq., including the Clean Water Act (CWA) sections 301, 304(b), 304(g), 307, 402(a), and 501(a); 33 U.S.C. 1311, 1314(b), 1314(g), 1317, 1342(a), and 1361(a).

Unless otherwise provided by law, agencies may reconsider past decisions and revise, replace or repeal a decision so long as the agency provides a reasoned explanation and considers significant reliance interests. FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515 (2009); Motor Vehicle Mfrs. Ass'n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 42 (1983); see also Nat'l Ass'n of Home Builders v. EPA, 682 F.3d 1032, 1038 & 1043 (D.C. Cir. 2012) (a revised rulemaking based “on a reevaluation of which policy would be better in light of the facts” is “well within an agency's discretion,” and “[a] change in administration brought about by the people casting their votes is a perfectly reasonable basis for an executive agency's reappraisal” of its policy choices) (citations omitted). As discussed in section I of this preamble above and as described in further detail below, the EPA is reconsidering the 2024 ELG for unmanaged CRL, in part, because the EPA is concerned that the 2024 ELG may not have relied on appropriately up-to-date and complete data in reaching its decision to regulate unmanaged CRL using technology that the EPA now proposes, based upon new and more complete information, is economically unachievable.

Congress passed the Federal Water Pollution Control Act Amendments of 1972, also known as the CWA, to “restore and maintain the chemical, physical, and biological integrity of the Nation's waters.” 33 U.S.C. 1251(a). The CWA establishes a comprehensive program for protecting our nation's waters. Among its core provisions, the CWA prohibits the direct discharge of pollutants from a point source to waters of the United States (WOTUS), except as authorized under the CWA. Under CWA section 402, discharges may be authorized through a National Pollutant Discharge Elimination System (NPDES) permit. 33 U.S.C. 1342. The CWA also authorizes the EPA to establish nationally applicable, technology-based ELGs for discharges from different categories of point sources, such as industrial, commercial, and public sources. 33 U.S.C. 1311, 1314.

Direct dischargers ( i.e., those discharging directly to WOTUS rather than through publicly owned treatment works, or POTWs) must comply with effluent limitations in NPDES permits. 2 Discharges that flow through groundwater before reaching surface waters that are the “functional equivalent” of a direct discharge from a point source to a WOTUS are considered direct discharges and must comply with effluent limitations in NPDES permits. See Cnty. of Maui v. Haw. Wildlife Fund, 590 U.S. 165 (2020). Based upon the applicable effluent limitations guidelines (ELGs) promulgated by the EPA, numeric limitations in NPDES permits are implemented through discharger-specific technology-based effluent limitations (TBELs). CWA sections 301 and 304, 33 U.S.C. 1311 and 1314. If an ELG promulgated by the EPA is inapplicable, then the permitting authority sets TBELs based on its best professional judgment (BPJ). CWA section 402(a)(1)(B), 33 U.S.C. 1342(a)(1)(B); 40 CFR 125.3(c).

The EPA establishes ELGs by regulation for categories of point source dischargers that are based on the degree of control that can be achieved using various levels of pollution control technology. The EPA promulgates national ELGs for major industrial categories for three classes of pollutants: (1) conventional pollutants ( i.e., total suspended solids or TSS, oil and grease, biochemical oxygen demand or BOD 5 , fecal coliform, and pH), as outlined in CWA section 304(a)(4) and 40 CFR 401.16; (2) toxic pollutants ( e.g., toxic metals such as arsenic, mercury, selenium, and chromium; toxic organic pollutants such as benzene, benzo-a-pyrene, phenol, and naphthalene), as outlined in CWA section 307(a), 40 CFR 401.15 and 40 CFR part 423 appendix A; and (3) nonconventional pollutants, which are those pollutants that are not categorized as conventional or toxic ( e.g., ammonia-N, phosphorus, and total dissolved solids or TDS).

The EPA develops ELGs that are technology-based regulations for a category of dischargers and are not based on a discharge's effect on water quality. See, e.g., Sw. Elec. Power Co. v. EPA, 920 F.3d 999, 1005 (5th Cir. 2019) (“[T]he Administrator must require industry, regardless of a discharge's effect on water quality, to employ defined levels of technology to meet effluent limitations.”) (citations and internal quotations omitted). The EPA bases these regulations, in part, on the performance of control and treatment technologies.

There are several TBELs that may apply to a given discharger when issued a NPDES permit under the CWA: four types of standards applicable to direct dischargers, two types of standards applicable to indirect dischargers, and a default site-specific approach. The TBELs relevant to this rulemaking are described in detail below.

Traditionally, the EPA establishes effluent limitations based on best practicable control technology (BPT) by considering the average of the best performances of facilities within the industry, grouped to reflect various ages, sizes, processes, or other common characteristics. The EPA may promulgate ELGs establishing BPT-based limitations for conventional, toxic, and nonconventional pollutants. In specifying BPT, the EPA looks at a number of factors. The EPA first considers the cost of achieving effluent reductions in relation to the effluent reduction benefits. The Agency also considers the age of equipment and facilities, the processes employed, engineering aspects of the control technologies, any required process changes, non-water quality environmental impacts (NWQEIs, including energy requirements), and such other factors as the Administrator deems appropriate. See CWA section 304(b)(1)(B), 33 U.S.C. 1314(b)(1)(B).

BAT represents the second level of stringency for controlling direct discharge of toxic and nonconventional pollutants, after BPT. The U.S. Court of Appeals for the Fifth Circuit has referred to this as the CWA's “gold standard” for controlling discharges from existing sources. Sw. Elec. Power Co., 920 F.3d at 1003. In general, BAT represents the best available, economically achievable performance of facilities in the industrial subcategory or category. Consistent with the statutory language, the EPA considers technological availability and economic achievability in determining what level of control represents BAT. CWA section 301(b)(2)(A), 33 U.S.C. 1311(b)(2)(A). Other statutory factors that the EPA considers in assessing BAT are the cost of achieving BAT effluent reductions, the age of equipment and facilities involved, the process employed, potential process changes, NWQEIs (including energy requirements), and such other factors as the Administrator deems appropriate. CWA section 304(b)(2)(B), 33 U.S.C. 1314(b)(2)(B). The Agency retains considerable discretion in assigning the weight to be accorded each factor. Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1045 (D.C. Cir. 1978). This is especially true for EPA's consideration of NWQEIs. BP Expl. & Oil, Inc. v. EPA, 66 F.3d 784, 801-02 (6th Cir. 1995). Historically, the EPA has generally determined economic achievability on the basis of the effect of the cost of compliance with BAT limitations on overall industry and subcategory financial conditions. BAT reflects the highest performance in the industry and may reflect a higher level of performance than is currently being achieved in the industry as a whole. See, e.g., Sw. Elec. Power Co., 920 F.3d at 1006; Am. Paper Inst. v. Train, 543 F.2d 328, 353 (D.C. Cir. 1976); Am. Frozen Food Inst. v. Train, 539 F.2d 107, 132 (D.C. Cir. 1976). Under this approach, BAT may be based upon process changes or internal controls, even when these technologies are not widespread industry practice. See Id. at 132, 140; Reynolds Metals Co. v. EPA, 760 F.2d 549, 562 (4th Cir. 1985); Cal. & Hawaiian Sugar Co. v. EPA, 553 F.2d 280, 285-88 (2d Cir. 1977). Courts have previously endorsed this approach. See Kennecott v. EPA, 780 F.2d 445, 448 (4th Cir. 1985); see also Sw. Elec. Power Co., 920 F.3d at 1031.

In CWA section 301 and the EPA's implementing regulation at 40 CFR 125.3(a) indicate that technology-based treatment requirements under section 301(b) represent the minimum level of control that must be included in an NPDES permit. See 33 U.S.C. 1311. Where EPA has not promulgated a BPT or BAT-based limitation applicable to a category or subcategory of dischargers discharging directly into a WOTUS, or where such an EPA-promulgated ELG has been remanded by a court or withdrawn by the EPA, the EPA has provided by regulation that such treatment requirements are to be established by the NPDES permitting authority on a case-by-case basis using the permit writer's BPJ. Under the EPA's regulations, these case-by-case TBELs are developed by permit writers on the basis that CWA section 402(a)(1) authorizes the EPA Administrator to issue a permit that will meet either: all applicable requirements developed under the authority of other sections of the CWA ( e.g., technology-based treatment standards, water quality standards, ocean discharge criteria) or, before taking the necessary implementing actions related to those requirements, “such conditions as the Administrator determines are necessary to carry out the provisions of this Act.” 33 U.S.C. 1342(a)(1). The regulation at 40 CFR 125.3(c)(2) cites this section of the CWA, stating that technology-based treatment requirements may be imposed in a permit “on a case-by-case basis under section 402(a)(1) of the Act, to the extent that EPA-promulgated effluent limitations are inapplicable.” Furthermore, 40 CFR 125.3(c)(3) states that “[w]here promulgated effluent limitations guidelines only apply to certain aspects of the discharger's operation, or to certain pollutants, other aspects or activities are subject to regulation on a case-by-case basis in order to carry out the provisions of the Act.” The factors considered by the permit writer are the same as those that the EPA considers when establishing effluent guidelines. See 40 CFR 125.3(d)(1)-( )-3).

On November 3, 2015, the EPA promulgated a rule revising the regulations for the steam electric power generating point source category at 40 CFR part 423. 80 FR 67838 (2015 ELG). The 2015 ELG set the first Federal limitations on the levels of toxic pollutants ( e.g., arsenic) and nutrients ( e.g., nitrogen) that can be discharged in the steam electric power generating industry's largest sources of wastewater based on technology improvements in the industry over the preceding three decades. Before the 2015 ELG, regulations for the industry were last updated in 1982 and contained only limitations on TSS and oil and grease for the industry's wastestreams with the largest pollutant loadings.

Electric utilities, environmental groups, and drinking water utilities filed seven petitions for review of the 2015 ELG in various circuit courts. The petitions were consolidated in the U.S. Court of Appeals for the Fifth Circuit as Southwestern Electric Power Co. v. EPA, Case No. 15-60821. In early 2017, the EPA received two administrative petitions to reconsider the 2015 ELG: one from the Utility Water Act Group (UWAG) and one from the Small Business Administration.

On August 11, 2017, the EPA announced a rulemaking to potentially revise the new, more stringent BAT effluent limitations and pretreatment standards for existing sources (PSES) in the 2015 ELG that apply to flue gas desulfurization wastewater and bottom ash transport water. The Fifth Circuit subsequently granted the EPA's request to sever and hold in abeyance petitioners' claims related to those limitations and standards, and those claims are still in abeyance. With respect to the remaining claims related to limitations applicable to legacy wastewater and CRL, the court issued a decision in 2019 vacating those limitations as arbitrary and capricious under the Administrative Procedure Act and unlawful under the CWA, respectively. Sw. Elec. Power Co., 920 F.3d at 1033. In the case of CRL, the court held that the EPA's setting of BAT limitations equal to BPT limitations was an impermissible conflation of the two standards, which are supposed to be progressively more stringent, and that the EPA's rationale was not authorized by the statutory factors for determining BAT. Id. at 1026. After the court's decision, the EPA announced plans to address the vacated limitations in a later action.

On October 13, 2020, the EPA promulgated the Steam Electric Reconsideration Rule, 85 FR 64650 (2020 ELG). The 2020 ELG changed the technology basis for two wastestreams (FGD wastewater and bottom ash transport water) resulting in revised limitations, created three new subcategories, and revised the technology basis for the voluntary incentives program. The 2020 ELG required most steam electric facilities to comply with the revised effluent limitations “as soon as possible” after October 13, 2021, but no later than December 31, 2025. NPDES permitting authorities established the particular applicability date(s) of the new limitations within that range for each facility (except for indirect dischargers) at the time they issued the facility's NPDES permit.

Environmental groups filed two petitions for review of the 2020 rule, which were consolidated in the U.S. Court of Appeals for the Fourth Circuit on November 19, 2020, as Appalachian Voices, et al. v. EPA, No. 20-2187. An industry trade group and certain energy companies moved to intervene in the litigation, which the court authorized on December 3, 2020. On April 8, 2022, the court granted the EPA's motion to place the case into abeyance as a result of a new rulemaking announced in July 2021. The case remains in abeyance.

On May 9, 2024, as part of a “suite of final rules” imposing new requirements on the power generation sector, the EPA promulgated the Steam Electric Supplemental Rule (89 FR 40198) (2024 ELG). This revision of the regulations at 40 CFR part 423 established a zero-discharge limitation for three wastewaters generated at steam electric power plants: flue gas desulfurization wastewater, bottom ash transport water, and CRL. The 2024 ELG also established non-zero numeric discharge limitations on mercury and arsenic from unmanaged CRL, which is a distinct subset of CRL defined in the ELG to include discharges of CRL that the permitting authority determines are the functional equivalent of a direct discharge to a WOTUS through groundwater or discharges of CRL that have leached from a waste management unit into the subsurface and mixed with groundwater before being captured and pumped to the surface for discharge directly to a WOTUS. These mercury and arsenic limitations also applied to a fourth wastestream called legacy wastewater, which is typically discharged from surface impoundments during the closure process, where those surface impoundments had not commenced closure under the EPA's coal combustion residuals (CCR) regulations under the Resource Conservation and Recovery Act as of the effective date of the 2024 ELG.

As a general matter, the Clean Water Act addresses instances in which there are discharges to the jurisdictional waters of the United States (“jurisdictional waters” or WOTUS). Accordingly, the proposed Steam Electric ELG is designed to address impacts to surface waters ( i.e., a WOTUS) from a subset of leachate from coal-fired electric generating utilities that is discharged to a WOTUS:

o discharges of CRL that are the functional equivalent of a direct discharge to a WOTUS through groundwater; or

o discharges of CRL that have leached from a waste management unit into the subsurface and mixed with groundwater before being captured and pumped to the surface for discharge directly to a WOTUS.

By contrast, the CCR rule deals with the disposal units themselves (where they are located, specific design and operating criteria, structural stability requirements, groundwater monitoring and corrective action, closure of the units, etc.) and primarily with their impacts or potential impacts to groundwater.

Discharges covered by an NPDES permit are excluded from the CCR regulations, because such discharges are not “solid waste” pursuant to RCRA section 1004(27). The RCRA exclusion only applies to “industrial discharges that are point sources subject to permits,” i.e., to the discharges to jurisdictional waters, and not to any activity, including groundwater releases or contaminant migration, that occurs prior to that point. See 40 CFR 261.4(a)(2) (“This exclusion applies only to the actual point source discharge. It does not exclude industrial wastewaters while they are being collected, stored or treated before discharge”). For purposes of the RCRA exclusion, EPA considers the “actual point source discharge” to be the point at which a discharge reaches the jurisdictional waters, and not in the groundwater or otherwise prior to the jurisdictional water. Accordingly, the CCR regulations do not apply to the unmanaged CRL regulated under the proposed Steam Electric ELG.

However, by regulating/preventing the release of leachate to groundwater, or requiring corrective action (remediation) of CCR leachate in the groundwater, the CCR rule may secondarily address impacts to surface waters that:

o would otherwise be addressed by the steam electric ELG proposal, and/or

o fall outside of the proposal, because a permitting authority determines the discharge(s) are not the functional equivalent of a direct discharge to a WOTUS through groundwater, or are discharged to a non-WOTUS.

A number of parties challenged the 2024 ELG in various petitions that were consolidated before the U.S. Court of Appeals for the Eighth Circuit as Southwestern Electric Power Co. v. EPA, No. 24-2123. Some petitioners, in part, alleged that EPA arbitrarily inflated the costs of the zero-discharge option for unmanaged CRL, and thus, improperly concluded that zero-discharge technology is not achievable for the unmanaged CRL subcategory, where that technology is available and achievable for other types of leachate discharges. Conversely, other petitioners alleged, in part, that that EPA acted arbitrarily and capriciously by adopting a new subcategory for discharges of unmanaged CRL without defining the universe of regulated entities, explaining how the technology would apply to the vast range of circumstances involving these kinds of discharges, or rationally determining the economic achievability of these limitations. Following a change in administrations, litigation in these cases has been paused while EPA reconsiders the 2024 Rule.

The EPA has received two petitions for reconsideration of the 2024 ELG, one from the Edison Electric Institute (EEI) and one from UWAG.

EEI is a trade association that represents U.S. investor-owned electric companies. On November 13, 2024, EEI sent a petition to the EPA, which included recommendations to clarify the definition of a “closed waste management unit,” and to clarify that BPJ limitations continue to apply at retired plants and that new effluent limitations for unmanaged CRL do not apply to landfills closed by the 2024 ELGs effective date of July 8, 2024 (DCN SE11943). This petition was updated with a supplemental letter from EEI on May 8, 2025, which reiterated recommendations for CRL applicability and included additional recommendations relating to unmanaged CRL (DCN SE11948).

The UWAG is a voluntary non-profit group comprised of individual energy companies and two national trade associations of energy companies: the National Rural Electric Cooperative Association (NRECA) and the American Public Power Association (APPA). NRECA represents nearly 900 local electric cooperatives across the U.S., serving 42 million people and covering 56 percent of the nation's land area. APPA is the national service organization that represents not-for-profit local, State, or other government-owned electric utilities. On February 21, 2025, UWAG sent the Agency a petition for rulemaking to reconsider and repeal the 2024 ELG, as well as administratively stay the 2024 ELG while it is in litigation (DCN SE11944). The petition requests several reviews of the determinations underlying the 2024 ELG, including the 2024 ELG's findings with regard to unmanaged CRL. The petition further expresses concerns related to the unique engineering challenges of “completely intercepting and capturing any and all CRL leaks, treating them with chemical precipitation to meet the new limit, then discharging the CRL back . . .” and the potentially exorbitant costs to do so (DCN SE11944).

In addition to these two petitions, on April 25, 2025, the EPA received a request from America's Power, a national trade association representing the U.S. steam electric power plants and its supply chain (DCN SE11903A1). The letter requests that the EPA repeal the zero-discharge requirements of the 2024 ELG and return to the 2020 ELG requirements for CRL, flue gas desulphurization wastewater, and bottom ash transport water.

On December 23, 2025, the EPA announced a final rule extending several wastewater compliance deadlines for coal-fired power plants. The final action was published December 31, 2025 (90 FR 61328)  3 and provides electricity producers with more time to comply with the 2020 and 2024 ELG deadlines in light of extraordinary increases in electricity demand associated with the resurgence of manufacturing and the artificial intelligence (AI) and data center revolution, and as necessary to meet the national priorities highlighted in Executive Orders issued by President Trump (a discussion of these Executive Orders may be found in the record (DCN SE12125).

In addition to extending certain compliance deadlines related to zero-discharge standards in the 2024 rule, new provisions in the 2025 Deadline Extensions Rule allow permitting authorities the flexibility to extend certain compliance deadlines on a site-specific basis due, for example, to unexpected electricity demand.

The 2025 Deadline Extension Rule did not change the effluent limitations requirements themselves. However, during the rulemaking process for the 2025 Deadline Extensions Rule, the EPA also requested additional data and information on technologies, performance, and technology-based implementation challenges related to the 2024 ELG. The EPA stated this data would be used to inform a future rulemaking to support practical, feasible, and on-the-ground implementations of wastewater pollution discharge limitations.

As a result of the 2025 data call, the EPA received site-specific performance and costs data from Santee Cooper and Longview Power LLC (EPA-HQ-OW-2009-0819-10769 and EPA-HQ-OW-2009-0819-10702, respectively). Both letters raised concerns that the EPA's costing methodology in the 2024 ELG underestimated costs. The cost methodology has been revised for this proposal.

Legal advocacy groups filed four petitions for review of the 2025 Deadline Extensions Rule in different U.S. Courts of Appeals. Waterkeeper Alliance, et al. v. EPA, No. 26-128 (2d Cir.); Appalachian Voices v. EPA, No. 26-1072 (4th Cir.); Sierra Club v. EPA, No. 26-752 (9th Cir.); Ctr. for Biological Diversity v. EPA, No. 26-426 (9th Cir.). The petitions have been consolidated in the U.S. Court of Appeals for the Second Circuit, and the litigation is ongoing. In re: Environmental Protection Agency, Effluent Limitations Guidelines and Standards for the Steam Electric Generating Point Source Category, Deadline Extensions, 90 FR 61328, Published on December 31, 2025, MCP No. 199 (J.P.M.L. February 10, 2026).

On April 17, 2015, the EPA promulgated the Disposal of Coal Combustion Residuals from Electric Utilities final rule (2015 CCR rule) (80 FR 21302). This rule finalized national regulations to provide a comprehensive set of requirements for the safe disposal of CCR, commonly referred to as coal ash, from steam electric power plants. The 2015 CCR rule established technical requirements for CCR landfills and surface impoundments under subtitle D of the Resource Conservation and Recovery Act (RCRA), the Nation's primary law for regulating solid waste.

As a result of the D.C. Circuit Court decisions in Util. Solid Waste Activities Grp. v. EPA, 901 F.3d 414 (D.C. Cir. 2018) (“ USWAG decision” or “ USWAG” ), and Waterkeeper All., Inc. et al. v. EPA, No. 18-1289 (D.C. Cir. filed March 13, 2019), the Administrator signed two rules: A Holistic Approach to Closure Part A: Deadline to Initiate Closure and Enhancing Public Access to Information (CCR Part A rule) (85 FR 53516, August 28, 2020) on July 29, 2020, and A Holistic Approach to Closure Part B: Alternate Liner Demonstration (CCR Part B rule) (85 FR 72506, December 14, 2020) on October 15, 2020. The EPA finalized several amendments to the 2015 CCR rule, which are relevant to the management of the wastewaters covered by this proposed ELG for unmanaged CRL because these wastewaters have historically been co-managed with CCR in the same surface impoundments.

As explained in the 2015 and 2020 ELGs, the ELGs and CCR rules may affect the same electric generating unit or activity at a plant. Therefore, when the EPA finalized the 2015 ELG and 2015 CCR rule, as well as revisions to both regulations in 2020, the Agency coordinated the ELGs and CCR rules to minimize the complexity of implementing engineering, financial, and permitting activities. Likewise, the EPA considered the interactions of the ELGs and CCR rules during the development of the 2024 ELG. The EPA's analytic baseline includes the final requirements of the 2015 and 2024 ELG and CCR rules using the most recent data provided under the 2015 CCR rule reporting and recordkeeping requirements.

Concurrently with the 2024 ELG, in a separate rulemaking the EPA promulgated in 2024 the Legacy CCR Surface Impoundments and CCR Management Units final rule (2024 Legacy CCR rule). The 2024 Legacy CCR rule established regulatory requirements for inactive CCR surface impoundments at inactive utilities (“legacy CCR surface impoundments” or “legacy impoundments”) (80 FR 21302; EPA-HQ-OLEM-2020-0107; FRL-7814-04-OLEM). EPA refers to these rules collectively as the RCRA CCR regulations throughout the remainder of this preamble.

Many of the technical requirements under the RCRA CCR regulations also have associated internet posting requirements that help ensure transparency and provide citizens with information about CCR units in their state. For example, power companies were required to conduct groundwater monitoring requirements for coal ash impoundments and to make the data publicly available starting in March 2018. The EPA maintains a list of the internet sites for facilities posting RCRA CCR compliance information organized alphabetically by state (DCN SE12100). These data cover over 300 coal plants or offsite coal ash disposal areas, including over 750 individual coal ash ponds and landfills and more than 4,600 groundwater monitoring wells.

The EPA provided general descriptions of the steam electric power generating industry in the 2015 ELG, the 2020 ELG, and the 2024 ELG. The Agency has continued to collect information and update this industry profile. The previous descriptions reflected the known information about the universe of steam electric power plants and incorporated final environmental regulations applicable at that time. For this proposal, the EPA has revised its description of the steam electric power generating industry (and its supporting analyses) to incorporate changes in the plant population and corresponding waste management units, changes in plant retirement status, and updates to wastewater treatment in place. The analyses supporting this proposed ELG rely on an updated baseline that incorporates these changes in the industry and applies the numerical limitations established in the 2024 ELG. The analyses then compare the effect of each of the proposed option requirements for unmanaged CRL to the effect on the baseline (the industry as it exists today with the requirements of the 2024 ELG).

Of the 858 steam electric power plants in the country identified by the EPA, only those coal-fired power plants that discharge unmanaged CRL are expected to incur costs to comply with this proposal. Coal-fired power plants are expected to continue discharging unmanaged CRL from waste management units after ceasing combustion of coal. Such plants may therefore incur costs to comply with this proposal even after retirement.

The EPA determined that between 63 and 111 power plants may be discharging unmanaged CRL based on whether the plants' waste management units are unlined, not clean-closed, or undergoing corrective action. The EPA does not expect that all these landfills and surface impoundments are discharging unmanaged CRL; permitting authorities would ultimately determine whether unmanaged CRL is discharged on a site-specific case-by-case basis. Of these power plants, the EPA has determined that at least seven power plants are currently pumping and treating unmanaged CRL (that is mixed with groundwater) before being captured for discharge directly to a WOTUS. The EPA did not find evidence from available CCR monitoring reports, data reported on installed treatment technologies to meet compliance, or solicited data from industry that additional power plants exist that are pumping and capturing unmanaged CRL at this time. Therefore, these seven plants likely represent the full universe of power plants that are currently pumping and treating unmanaged CRL, and the remaining 104 plants are likely the upper bound number of power plants potentially discharging unmanaged CRL in a manner that permitting authorities could determine are the functional equivalent of a direct discharge to a WOTUS through groundwater. The EPA is only aware of a small number of plants where this determination has been completed. For the remaining plants, the EPA assumes that unmanaged CRL is not currently being pumped and captured and that treatment for unmanaged CRL has not been installed. Therefore, the EPA expects that the costs for treating unmanaged CRL will primarily be incurred by those plants that are determined to be discharging unmanaged CRL as a functional equivalent of a direct discharge, which could include all except the seven plants already directly discharging unmanaged CRL.

Under the 2024 ELG, the EPA defined unmanaged CRL at 423.11(ff), which the EPA is continuing to use without change in this proposal. The 2024 ELG specifies two types of unmanaged CRL that are considered distinct from CRL and defined as: (1) discharges of CRL that the permitting authority determines are the functional equivalent of a direct discharge to a WOTUS through groundwater; or (2) discharges of CRL that has leached from a waste management unit into the subsurface and mixed with groundwater before being captured and pumped to the surface for discharge directly to a WOTUS. This section provides a description of how CRL and other wastewaters are generated at a coal-fired power plant.

When a fossil-fuel plant combusts coal, the plant uses a process called flue gas desulfurization (FGD) to remove sulfur dioxide from the exhaust gases. Whether the flue gas desulfurization process is wet or dry, lime or limestone is used to neutralize the acidic gases. The flue gas desulfurization process produces gypsum as a byproduct and generates wastewater. The pollutants in this wastewater vary primarily depending on the coal used as the fuel source, as well as the type of scrubber, the lime composition, and the gypsum-dewatering system. Flue gas desulfurization wastewater is extremely well characterized as discussed further below. After a complex treatment process, the resulting wastewater is discharged to a WOTUS, reused on-site, or evaporated. At plants subject to zero-discharge requirements, treated flue gas desulfurization wastewater is sent to on-site ponds for storage, reused within the plant for other processes such as ash management, or evaporated with the remaining solids sent to a landfill.

CCR waste management units, including landfills and surface impoundments, are areas used by power plants to store, treat, or dispose of coal ash and related by-products. 4 These waste management units are regulated under RCRA to prevent groundwater contamination. For the purposes of this proposal, surface impoundments are areas designed to store, treat, or dispose of coal ash and wastewater produced by power plants when generating electricity, such as flue gas desulfurization wastewater. The regulatory definition of surface impoundments for purposes of RCRA may be found at 40 CFR 257.53. CCR landfills are defined as “an area of land or an excavation that contains CCR and which is not a surface impoundment, an underground injection well, a salt dome formation, a salt bed formation, an underground or surface coal mine, or a cave.” 40 CFR 257.53. New CCR landfills generally include composite liners and leachate-collection systems. Both types of waste management units can generate wastewater from moisture contained in the material they receive and from precipitation. Wastewater from these waste management units is monitored under various programs, including under the RCRA CCR regulations. For the purposes of assessing unmanaged CRL under this proposed rule the EPA finds that many waste management units have been identified and characterized in public reports available online (see section IV of this preamble for more details).

In addition to the characterization of waste management units, more than 4,600 groundwater monitoring wells have been placed around waste management units under the RCRA CCR regulations, as well as additional monitoring wells attributable to state or local requirements. The RCRA CCR regulations require owners of coal ash units to monitor groundwater for pollutants at least twice a year and annually publish accessible reports detailing the sampling results. These reports must also document statistical analysis, detection monitoring, or corrective actions if levels of ground water contamination are found to be above groundwater protection standards. Thus, the EPA considers that groundwater in the proximity of a waste management unit should be well characterized.

CRL is the wastewater that has passed through coal combustion residuals, generally while the residuals are stored in waste management units. Managed CRL that has been collected from the leachate-collection system of a lined waste management unit is of a finite volume and has characteristics very similar to the wastewater inputs (usually flue gas desulfurization wastewater) to the waste management unit. By contrast, unmanaged CRL is leachate from a waste management unit that is not captured from a leachate-collection system and instead percolates into the subsurface. As discussed earlier, the 2024 ELG defines two situations in which CRL constitutes unmanaged CRL.

Since the promulgation of the 2024 ELG, the EPA has become aware of new information and data demonstrating (1) the existence of an energy crisis, requiring the full use and operation of these steam electric facilities, and (2) changes in the scope of steam electric facilities that plan to remain operational or incur costs under the 2024 ELG.

Much of the information relied upon by the EPA during the 2024 ELG rulemaking process did not anticipate increases in near-term energy demand projections, while more recent information points to an impending, extraordinary spike in energy demand that cannot currently be satisfied by existing power generation. In 2025, the EPA documented several generating facilities that reversed previously announced plans to cease burning coal. Rather, in light of new rising energy demands, these facilities have now decided to continue burning coal.

Additionally, in 2025, the Department of Energy (DOE) issued over a dozen emergency orders to delay the closure of these coal-fired power plants to meet energy demands. For this proposed rule, the EPA expects that even more planned power plant retirements will be impacted and reversed throughout 2026 as a result of the 2025 Deadline Extensions Rule, additional DOE emergency orders will be issued to coal-fired power plants in 2026 and beyond, and that existing coal-fired EGUs will increase coal combusting operations to meet higher energy demands. The EPA further expects that for these reasons, more CCR will be produced and transported to landfills and surface impoundments, and fewer landfills and surface impoundments will be capped or closed. Therefore, the EPA expects discharges of unmanaged leachate to increase relative to the amount of unmanaged CRL discharges anticipated when promulgating the 2024 ELG.

There are certain compositional differences between and among different unmanaged CRL originating from different dischargers and mixed with varying types of groundwater with its own unique characteristics that could affect treatment needs for any single discharger. The 2024 ELG assumed that managed CRL and unmanaged CRL would each contain the same pollutants and could be treated to the same numeric limitations, using the same technology, at similar costs. However, unmanaged CRL, by its very nature, permeates through groundwater and may react with, and be affected by, the distinct characteristics of that groundwater and any existing pollutants found therein.

Unmanaged CRL most notably differs from managed CRL because the wastewater has mixed with groundwater. As a result, the volume and pollutant concentrations of unmanaged CRL are heavily influenced by the ambient groundwater through which it passes. The groundwater may have background levels of various pollutants that are distinct from the leachate, but these background levels vary widely from site to site. For example, total arsenic concentrations are frequently under 1 ug/L in groundwater, but concentrations above 10 ug/L are found in 7 percent of sampled wells (DCN SE12121). Indeed, the contaminated volume of groundwater is variable, the direction of the groundwater flow may change throughout the year, and the characterization of the groundwater is highly site-specific. For example, in coastal plain aquifers, saltwater intrusion drastically changes the salinity in the groundwater, and total dissolved solids in the groundwater can range from less than a few hundred ppm to more than several thousand ppm (DCN SE12122).

The extent to which the pollutants that are known to be present in CRL may change through transport in groundwater and, therefore, the actual chemical composition of unmanaged CRL itself is unclear and may vary considerably from any other unmanaged CRL originating from a different discharger. The precise pollutants and concentrations in unmanaged CRL may even vary across different landfills at the same plant. CRL is enriched in oxyanion-forming elements such as arsenic (As), selenium (Se), boron (B), molybdenum (Mo), and vanadium (V), as well as major ions such as sulfate, chloride, and calcium. These pollutants are highly soluble, weakly sorbed under alkaline conditions, and are generally persistent during subsurface transport. CRL itself is typically alkaline and has a pH of 8-12. Interactions with surrounding groundwaters may change the alkalinity, pH, and redox conditions of unmanaged CRL, which may affect its pollutant concentrations. For example, total arsenic has a median concentration of 22 ug/L in impoundment wastewater and a median concentration of 70 ug/L in CRL (DCN SE12123), but the median total arsenic in the CRL/groundwater mix is unknown. The EPA does not have data documenting technology performance with the CRL/groundwater mixture as compared to FGD wastewater or impoundment wastewater. Several comments on the 2024 ELG pointed out this distinction; for example, most of the total arsenic in CRL at three American Electric Power plants is present as arsenate, which is soluble and will not readily settle out after chemical precipitation (EPA-HQ-OW-2009-0819-10671-A1).

Conditions of the site can also contribute to the high variability of pollutants found in unmanaged CRL. Site-specific properties such as site hydrology, hydraulic conductivity, groundwater plume length and age, background contaminants present in groundwater, relative flows and volumes of contributing groundwater, and biogeochemical properties of soils can contribute to high variability in unmanaged CRL composition, and batch laboratory leachate tests to characterize unmanaged CRL often underpredict contaminant release and fail to capture long-term geochemical processes (DCN SE12124). Field-scale monitoring and modeling may provide site-specific hydrogeological data but vary widely from site-to-site because of variability in local hydrological conditions that cannot be assessed on a national level.

As a result of these pollutant and site variations, pump and capture of unmanaged CRL from the subsurface is difficult and requires a thorough analysis of the wastewater and the site conditions to ensure the maximum amount of unmanaged CRL is captured. Even with site-specific design, a pump and capture system is not guaranteed to collect 100 percent of the unmanaged CRL that has leached into groundwater.

Despite this inherent variability of unmanaged CRL, the EPA made several assumptions about the similarities between FGD wastewater, managed CRL, and unmanaged CRL in the 2024 ELG. In promulgating the 2015 ELG, the EPA first determined that CRL from landfills and impoundments included similar types of pollutants as FGD wastewater, and by extension, to waste management unit wastewaters as discussed above. However, the EPA also determined that the pollutants in CRL could vary more widely in concentrations and volumes compared to those in FGD wastewater. Data from the Electric Power Research Institute (EPRI) on untreated FGD water from 36 power plants showed variability attributed to differences in coal composition, operational conditions at each plant, and water circulation and reuse (DCN SE12101). During development of the 2024 ELG, additional data obtained from EPRI showed wastewater characteristics between CRL and FGD wastewater were similar, but nevertheless varied across CCR waste management units due to different types of fuels burned at the plant, duration of pond operation, addition of bottom ash water, types of air pollution controls employed, and ash types (DCN SE11725). The wastewater characterization in the waste management units had the same pollutants that were in the FGD wastewater, but additional variation was observed due to both the presence of other wastes already in the waste management unit and additional inputs such as bottom ash, precipitation, and storm water. Accordingly, the EPA determined that treatment technologies identified for FGD wastewater were generally applicable to CRL but may in some cases require additional pretreatment or a combination of technologies. Such additional treatment technologies could be necessary because of changes to the oxidation state of some FGD pollutants as they transition to the CCR impoundment. For example, a chemical precipitation system that would be very effective at removing particulate arsenic found in FGD wastewater would be significantly less effective at removing dissolved arsenic or soluble arsenate that may be present in CRL. Additionally, the EPA previously recognized that the characterization of wastewater differs within the layers of a CCR impoundment as it is dewatered and prepared for closure (88 FR 18835). Therefore, treatment requirements at a unit that is in the process of closure may also change as closure progresses.

Despite the complexities discussed above, the EPA conducted its analyses in the 2024 ELG under the assumption that pollutants in unmanaged CRL were similar to CRL. Additionally, the EPA assumed that pollutant removals through chemical precipitation for CRL were similar to that of flue gas desulfurization wastewater. The EPA then assumed that pollutant removals through chemical precipitation of unmanaged CRL were similar to that of managed CRL. While FGD wastewater and waste management unit wastewaters demonstrate similar types and forms of pollutants, the same cannot necessarily be said for unmanaged CRL once it has mixed with groundwater. The EPA is aware that mixing with groundwater may result in departure from what is otherwise a very well characterized set of wastestreams, and the EPA received comments further asserting such.

The 2024 ELG did not rely on any data specific to unmanaged CRL to conclude that unmanaged CRL mixed with groundwater would fall within the same ranges of managed CRL evaluated by the EPA. While the EPA received general comments in the 2024 ELG about the possibility of interactions of CRL pollutants mixed into groundwater, commenters did not provide data to demonstrate that CRL mixed into groundwater might result in pollutant concentrations extending beyond the ranges evaluated by the EPA for FGDFGD wastewater or CRL. Similarly, in petitions received after the 2024 ELG and in the 2025 Deadline Extensions Rule data call, the EPA received no data demonstrating the pollutant concentrations in unmanaged CRL were untreatable by the selected BAT technologies. Instead, comments describe “attenuation,” such as through adsorption. As the EPA noted in the 2024 rulemaking, adsorption and other attenuation processes would be expected to remove pollutants, which means in some cases that chemical precipitation might not be necessary. In other cases, however, additional stages of chemical precipitation treatment may be necessary if the groundwater contains significant concentrations of pollutants from other sources.

In general, control and treatment technologies for some wastestreams have continued to advance. Often, these advancements provide plants with additional or alternative approaches for complying with any effluent limitations. In some cases, these advancements have also decreased the associated costs of compliance. For this proposed ELG, the EPA incorporated updated information and evaluated several technologies available to control and treat unmanaged CRL generated by the steam electric power generating industry. See section VII of this preamble for details on updated cost information.

As described above, in the 2024 ELG the EPA assumed, with little available data, that unmanaged CRL from landfills and impoundments includes similar types of pollutants as both flue gas desulfurization wastewater and managed CRL. As such, the EPA further assumed, with little available data, that certain treatment technologies identified for flue gas desulfurization wastewater and managed CRL could also be used to treat unmanaged CRL. The following describes these potential types of treatment and handling practices for unmanaged CRL:

• Chemical precipitation. Chemicals are added as part of the treatment system to help remove suspended solids and dissolved solids, particularly metals. The precipitated solids are then removed from the solution by coagulation/flocculation followed by clarification and/or filtration. The 2024 ELG focused on a specific design that employs hydroxide precipitation, sulfide precipitation (organosulfide), and iron coprecipitation to remove suspended solids and convert soluble metal ions to insoluble metal hydroxides or sulfides. Chemical precipitation was part of the BAT technology basis for the effluent limitations in the 2024 ELG. While the EPA's historical record shows that chemical precipitation can be a robust process that can treat most pollutants found in the various coal combustion wastestreams and may be effective at treating heavy metals, the limited data available to the EPA shows that leachate from impoundments that mixes with groundwater must be evaluated as a process differently than managed CRL. Chemical precipitation can be readily tailored (such as by adjusting the pH and the dose of the reagents used to convert dissolved substances into solid particles) to meet the variability encountered in CRL wastewater (DCN SE12168).

• High-hydraulic-residence-time biological reduction. The EPA identified three types of biological treatment systems used to treat flue gas desulfurization wastewater: anoxic/anaerobic fixed-film bioreactors (which target removals of nitrogen compounds and selenium), anoxic/anaerobic suspended growth systems (which target removals of selenium and other metals), and aerobic/anaerobic sequencing batch reactors (which target removals of organics and nutrients).

• Low-hydraulic-residence-time biological reduction. This biological treatment system targets removal of selenium and nitrate/nitrite using fixed-film bioreactors in smaller, more compact reaction vessels. The bacteria reduce soluble selenate and selenite to insoluble selenium, which is a filterable solid; nitrate is converted into nitrogen gas. This system differs from the high-hydraulic-residence-time biological treatment system evaluated in the 2015 ELG, in that the low-hydraulic-residence-time system is designed to operate with a shorter residence time (approximately one to four hours, compared to a residence time of 10 to 16 hours for high-hydraulic-residence-time) while still achieving significant removal of selenium and nitrate/nitrite. Both systems are sensitive to high total dissolved solids levels, so proper operation is necessary to accommodate fluctuations in the wastewater.

• Zero-Discharge Technologies

○ Membrane filtration. A membrane filtration system ( e.g., microfiltration, ultrafiltration, nanofiltration, forward osmosis, electrodialysis reversal, or reverse osmosis (RO)) is designed specifically for high-TDS and high-TSS wastestreams. These systems are designed to minimize fouling and scaling associated with industrial wastewater. These systems typically use pretreatment for potential scaling agents ( e.g., calcium, magnesium, sulfates) combined with one or more types of membrane technology to remove a broad array of particulate and dissolved pollutants from flue gas desulfurization wastewater. The membrane filtration units may also employ advanced techniques, such as vibration or creation of vortexes to mitigate fouling or scaling of the membrane surfaces. Membrane filtration can achieve zero discharge by recirculating permeate from a reverse osmosis system back into plant operations.

○ Spray evaporation. Spray evaporation technologies, which include spray dry evaporators (SDEs) and other similar proprietary variations, evaporate water by spraying fine misted wastewater into hot gases. The hot gases allow the water to evaporate before contacting the walls of an evaporation vessel, treating wastewater across a range of water quality characteristics such as TDS, TSS, or scale forming potential. Spray evaporation technologies use a less complex treatment configuration than brine concentrator and crystallizer systems (see the description of thermal evaporation systems) to evaporate water using a heat source, such as a slipstream of hot flue gas or an external natural gas burner. Spray evaporation technologies can be used in combination with other volume reduction technologies, such as membranes, to maximize the efficiency of each process. Concentrate from a reverse osmosis system can then be processed through the spray evaporation technology to achieve zero discharge by recirculating permeate from the reverse osmosis system back into plant operations.

○ Thermal evaporation. Thermal evaporation systems use a falling-film evaporator (or brine concentrator), following a softening pretreatment step, to produce a concentrated wastewater stream and a distillate stream to reduce wastewater volume by 80 to 90 percent and reduce the discharge of pollutants. The concentrated wastewater is usually further processed in a crystallizer that produces a solid residue for landfill disposal and additional distillate that can be reused within the plant or discharged. These systems are designed to remove a broad spectrum of pollutants to very low effluent concentrations.

Additionally, the EPA identified the following potential types of in situ treatment and handling practices for unmanaged CRL in the subsurface that would not be applicable to flue gas desulfurization wastewater or managed CRL. These in situ technologies require careful characterization of site-specific subsurface conditions that may vary widely in terms of biogeochemistry, pollutants present, and facility configurations.

• Impermeable Barriers. Impermeable barriers are underground walls that are designed to prevent or control the flow of groundwater to a certain location. An impermeable barrier placed in the subsurface would prevent the spread of pollutants from discharging to a WOTUS.

• Permeable Reactive Barriers. Permeable reactive barriers (PRB) are permeable barriers containing solid reagents or other reactive materials that are placed into the subsurface. As unmanaged CRL or contaminated groundwaters flow through permeable barriers, pollutants react with the reagents and are subsequently removed or treated.

• Injection. Injection technologies involve injection of liquid reagents or reactive adsorbents into the subsurface. The liquid reagents or adsorbents then react with and subsequently remove pollutants that may be present in unmanaged CRL or contaminated groundwaters. Injection approaches often require careful characterization of site-specific biogeochemical conditions to ensure effective delivery of reagents.

Additional discussion regarding updates to sources of data and new data obtained by the EPA may be found in the record (DCN: SE1210505).

This proposal evaluates three regulatory options and identifies one preferred option (Option 1), as shown in Table VI-1 of this preamble. The three regulatory options address unmanaged combustion residual leachate in different ways and using different technologies and management practices as the basis for doing so. In addition to some specific requests for comment included throughout this proposal, the EPA solicits comment on all aspects of this proposal, including the information, data, and assumptions the EPA relied upon to develop the three regulatory options, as well as the proposed BAT, effluent limitations, and alternate approaches included in this proposal.

This proposal does not seek to define what constitutes the “functional equivalent” of a direct discharge. Moreover, the EPA is not determining that all potential discharges through groundwater from landfills and surface impoundments are the functional equivalent of a direct discharge to a WOTUS. Rather, the EPA is proposing limitations that would apply to any discharge that is the functional equivalent of a direct discharge through groundwater to a WOTUS and, thus, requires an NPDES permit. The threshold standard for the “functional equivalence” determination is outside the scope of this rule. In this proposed rule, the EPA reaffirms its longstanding position, which is consistent with the County of Maui decision: the determination of what constitutes the functional equivalent of a direct discharge is case-specific, and some landfills and surface impoundments may meet the definition of point sources under the CWA.

Thus, to the extent that discharges from landfills, surface impoundments, or other features could be considered the functional equivalent of a direct discharge of unmanaged CRL to a WOTUS, this proposal would inform the permitting authority of the appropriate technology-based effluent limitations that would apply. Determining whether a functional equivalent of direct discharge exists at any particular impoundment or landfill is a task for permitting authorities and outside the scope of this proposed rulemaking.

In all three regulatory options, the EPA proposes to codify additional definitions to clarify applicability of the unmanaged CRL limitations.

• First, for purposes of this subpart, the EPA proposes to define a “closed coal combustion residuals waste management unit” at 40 CFR 423.11(gg) to provide clarity as to which impoundments and landfills meet the criteria of being closed.

• The EPA proposes to further clarify the applicability of the effluent limitations with new provisions at 40 CFR 423.13(l)(3).

○ The first provision states that the effluent limitations in this subcategory do not apply to retired power plants, and that case-by-case BAT limitations based on the permitting authority's best professional judgment (BPJ) continue to apply.

○ The second provision proposes that unmanaged CRL limitations do not apply to landfills closed by the 2024 ELG's effective date of July 8, 2024, and that case-by-case BAT limitations based on BPJ continue to apply. The EPA solicits comment on these additional provisions.

• The EPA proposes a correction to the CFR text at section 423.13(l)(1)(i) where “(1)(2)” was mistakenly printed instead of “(l)(2).”

• The EPA proposes to clarify in section 423.13(l)(2)(ii)(B) that BAT limitations based on BPJ apply to unmanaged CRL generated before the effective date of the ELG.

The following regulatory options apply to the two types of unmanaged leachate as defined in the 2024 ELG:

Discharges of pumped unmanaged CRL: CRL that has leached from a landfill or impoundment into the subsurface and mixed with groundwater, after which it has been captured and pumped to the surface for discharge directly to a WOTUS.

Functional equivalent of a direct discharge of unmanaged CRL: CRL that has been determined, by the permitting authority, to be the functional equivalent of a direct discharge to a WOTUS through groundwater.

Option 1 would rely on discretion of the permitting authority to set case-by-case BAT limitations that apply to functional equivalents of a direct discharge of unmanaged CRL, after evaluating site-specific factors relevant to the treatment to of unmanaged CRL.

This option would provide the greatest flexibility to ensure appropriate technology-based requirements are set while giving appropriate consideration to all site-specific factors impacting a utility's ability to collect and treat unmanaged CRL. This flexibility is appropriate given the fact that permitting authorities (which are typically states) are better situated on a case-by-case basis at the time of permit issuance to assess the difficulty in capturing and treating unmanaged CRL. Similarly, due to the unprecedented, rapidly increasing energy demands throughout the U.S. (as discussed in both the 2025 Deadline Extensions Rule, and section V.A of this preamble), including the extended operations of EGUs due to “must run orders” and the overall need to ensure grid reliability, as well as the resulting likelihood that the 2024 ELG overestimated the number of existing coal-fired power plants that would retire, this flexibility would appropriately allow the permitting authority to select the technologically available and economically achievable treatment method based on plant-specific technological, economic, and other relevant factors.

Over the past decade, whenever the EPA has revised the steam electric ELGs, the Agency has carefully considered the impacts of new requirements on the overall outlook of the industry, including impacts on electricity generation. This proposal continues in that tradition, but is more tailored to the dynamic energy market of today, by providing permitting authorities with the flexibility to make regulatory decisions that reflect the on-the-ground factors that a specific facility may be contending with at the time of issuance or re-issuance of an NPDES permit, and to ensure that proper consideration is given to the unique needs of specific utilities in order to ensure the continued delivery of affordable and reliable power to U.S. families and businesses. While not meant to be a complete list of considerations, the permitting authority should consider the following when evaluating potential model technologies on a BPJ basis:

• site hydrology;

• hydraulic conductivity;

• groundwater plume length and age;

• background contaminants present in groundwater;

• chemical form and concentration of pollutants in mixed CRL and groundwater;

• relative flows and volumes of contributing groundwater;

• biogeochemical properties of soils;

• changes in local energy demand;

• changes in energy costs to consumers;

• non-water quality environmental impacts, such as solid waste generation or air pollution from waste management;

• changes in fuel consumption due to waste management; and

• pending must-run orders or similar demands that a utility stay in operation longer than planned.

Option 1 proposes to maintain the existing 2024 ELG mercury and arsenic limitations applicable to discharges of pumped unmanaged CRL. The technology basis for BAT is chemical precipitation, employing hydroxide precipitation, sulfide precipitation (organosulfide), and iron coprecipitation. For further information on this BAT model technology and derivation of these numeric limitations, see the 2024 Steam Electric ELG Technical Development Document (TDD) (DCN SE11757).

Where discharges of pumped unmanaged CRL are occurring, as of the effective date of this ELG, the EPA proposes the limitations must be met as soon as possible, but no-later-than December 31, 2034. This no-later-than date, which is consistent with the latest compliance date for zero-discharge requirements promulgated in the 2025 Deadline Extensions Rule, is being proposed because it would provide permittees with appropriate time to make comprehensive waste management decisions when evaluating how to most efficiently meet the suite of requirements on coal-fired power plants from effluent guidelines. Discharges of pumped unmanaged CRL that commence after the effective date of this ELG must meet these numeric limitations as soon as possible, but no later than the date unmanaged leachate pumping commences or December 31, 2034, whichever is later.

Option 2 proposes to maintain the existing 2024 ELG mercury and arsenic limitations for functional equivalents of a direct discharge of unmanaged CRL. The technology basis for BAT is chemical precipitation, employing hydroxide precipitation, sulfide precipitation (organosulfide), and iron coprecipitation. For further information on this BAT model technology and derivation of these numeric limitations, see the 2024 Steam Electric ELG TDD (DCN SE11757).

Where such discharges are occurring, as of the effective date of the ELG, the EPA proposes to retain the requirement that these limitations must be met as soon as possible, but no later than December 31, 2029.

Option 2 proposes to also maintain the existing 2024 ELG mercury and arsenic limitations for discharges of pumped unmanaged CRL. The technology basis for BAT is chemical precipitation, employing hydroxide precipitation, sulfide precipitation (organosulfide), and iron coprecipitation. For further information on this BAT model technology and derivation of these numeric limitations, see the 2024 Steam Electric ELG TDD (DCN SE11757).

Where such discharges are occurring, as of the effective date of the ELG, the EPA proposes to retain the requirement that these limitations must be met be met as soon as possible, but no later than December 31, 2029.

Option 3 proposes to establish a zero-discharge requirement on pollutants from functional equivalents of a direct discharge of unmanaged CRL and would establish BAT limitations for mercury and arsenic based on chemical precipitation treatment as an interim step. The BAT basis for functional equivalents of a direct discharge of unmanaged CRL is the implementation of spray dry evaporators, the same as the 2024 ELG specified for (managed) CRL. See the 2024 ELG Preamble for additional detail on this approach.

Where functional equivalents of a direct discharge of unmanaged CRL that have been identified by a permitting authority are occurring as of the effective date of the ELG, the EPA proposes the zero-discharge limitation must be met as soon as possible, but no later than December 31, 2034. For functional equivalents of a direct discharge of unmanaged CRL commencing after the effective date of the ELG, the limitations must be met as soon as possible, but no later than the date unmanaged leachate pumping commences or December 31, 2034, whichever is later. The 2034 date reflects the deadlines established in the 2025 Deadline Extensions Rule and provides flexibility for those plants seeking to combine wastewater flows for more effective and efficient treatment.

Under this option, the EPA proposes to establish a zero-discharge limitation for all pollutants in pumped unmanaged CRL with interim BAT limitations on mercury and arsenic based on chemical precipitation treatment. The BAT basis for discharges of pumped unmanaged CRL is the implementation of spray dry evaporators, the same as the 2024 ELG specified for managed CRL. See the 2024 ELG Preamble for additional detail on this approach.

Where discharges of pumped unmanaged CRL are occurring as of the effective date of the ELG, the EPA proposes the zero-discharge limitations must be met as soon as possible, but no later than December 31, 2034. For discharges of pumped unmanaged CRL commencing after the effective date of the ELG, the limitations must also be met as soon as possible, but no later than the date unmanaged leachate pumping commences or December 31, 2034, whichever is later. The 2034 date reflects the deadlines established in the 2025 Deadline Extensions Rule and furthermore provides flexibility for those plants seeking to combine wastewater flows for more effective and efficient treatment.

The EPA is not proposing to select Option 3 as the preferred option for BAT for both types of discharges of unmanaged CRL because total costs of the option to the industry as a whole are unacceptably high and not economically achievable. As discussed in the Technical Support memo (DCN SE12105), the EPA has revised its cost estimates for this proposal, and the revised cost estimates for spray dry evaporators to achieve zero discharge for both categories of unmanaged CRL are $1.1 billion per year in the lower bound and $2.2 billion in the upper bound (see Table VII-1 and the Technical Support memo (DCN SE12105)).

The costs associated with this option are nearly an order of magnitude higher than total costs of the 2024 ELG to the industry for controlling all of the remaining end-of-pipe discharges from every other wastestream combined. In 2024, the EPA estimated that the total annualized costs to the industry of zero discharge could be as high as $3.69 billion. At that time, EPA determined these costs were unreasonable. With the revised economic analysis in this proposed rule, the EPA has determined that the annualized cost for the zero-discharge option in the 2024 ELG was likely an overestimation of costs; however, despite more representative cost calculations supporting this proposal, the EPA still proposes that the costs to achieve zero discharge ($1.1 to $2.2 billion) are unreasonable. Costs are one of the statutory factors that the EPA must consider, and courts have found that the EPA may properly rely on costs in rejecting potential BAT technologies. See e.g., BP Expl. & Oil Inc. v. EPA, 66 F.3d 784, 799-800 (6th Cir. 1995). For further discussion of costs and economic achievability, see the Technical Support memo (DCN SE12105).

In addition to the unacceptably high costs of Option 3, the EPA has identified several other areas where the cost analysis was unable to account for potentially significant expenditures by a permittee, which would further exacerbate the economic impacts of this option. Most notably, the duration of the discharges in question and the need for treatment beyond the operating life of a regulated utility may significantly increase cost burdens for this option. The EPA is concerned that the 2024 ELG did not fully account for the lack of revenue generated by closed utilities, and thus the lack of funding available, to implement treatment in an economically achievable way. Typically, ELGs no longer apply after an entity ceases the industrial operation generating pollutant discharges; however, given the nature of unmanaged CRL, and the influence contaminated groundwater has on the volume and duration of this wastestream, unmanaged CRL discharges that require treatment could incur costs associated with wastewater treatment operations long after the associated utility has retired and ceased generating electricity and revenue. Economic achievability assessments to support ELGs typically evaluate the compliance costs with respect to revenue and closures of facilities due to compliance costs, which would lend itself to further determine these costs are economically unachievable for any facility that has already closed and has no revenue to support these compliance costs. The increased cost of meeting zero-discharge limitations in unmanaged CRL may be unacceptable in light of the unique position of retired facilities with no revenue with which to support costs associated with such limitations.

Furthermore, the EPA acknowledges that the 2024 ELG record describes a spray dry evaporator employed to achieve zero-discharge of legacy wastewater at the Boswell Energy Center in Cohasset, Minnesota (DCN SE11621A1). The 2024 ELG concluded that the spray dry evaporator was not technologically available for this subcategory. In particular, many facilities will dewater and close their ash impoundments after the facility ceases generating electricity or combustion of coal. Without electricity production, there is no slipstream of flue gas with which to operate the same type of evaporator system that is achieving zero discharge at Boswell. No new information is available that rebuts this conclusion. For this reason, the EPA proposes that for facilities that do not have the same plant-wide configuration as Boswell, zero-discharge of unmanaged CRL may not be technologically available. In other instances, the facility may be unable to operate zero-discharge technologies during a planned or unplanned outage (DCN SE 1210303). The EPA has been unable to identify a basis for further subcategorization that would address the many differences between individual plants.

As another potential basis supporting the EPA's proposal to reject Option 3 as BAT, the EPA has looked carefully at the feasibility of a zero-discharge standard in light of the unique nature of unmanaged CRL discharges and the influence contaminated groundwater has on the volumes and durations of these wastestreams, which may pose unique challenges for demonstrating the capabilities of zero-discharge technology.

In the 2024 ELG analysis, the EPA made the assumption that the pollutants in unmanaged CRL were similar to (managed) CRL, and by extension also similar to FGD wastewater. Accordingly, the EPA assumed zero-discharge technologies identified for CRL and FGD could reasonably be applied to unmanaged CRL. The EPA is aware of at least one plant that as employed a zero-discharge technology for all wastestreams at the plant, including unmanaged CRL.

In the 2024 ELG, the EPA did not have performance data demonstrating that the volume of unmanaged CRL as estimated for costing purposes to be pumped from groundwater would result in zero-discharge of all pollutants from unmanaged CRL that is a functional equivalent of a direct discharge (as identified by a permitting authority). As the EPA did not receive or identify performance data to the contrary, the EPA, despite the lack of data, found in the 2024 ELG that discharges of pumped unmanaged CRL could meet a zero-discharge standard by the application of a pump-and-capture treatment system that includes spray dry evaporators (although this option was rejected due to its high costs). In this proposal, the EPA's updated analysis indicates that a zero-discharge limit is still not economically achievable, and it may not be technologically available as applied to all discharges of unmanaged CRL that are the functional equivalent of direct discharges. The volume and pollutant concentration of these functional equivalent discharges are highly dependent on prior groundwater contamination from surface impoundments or landfills and the depth to the existing groundwater table. Operational conditions, such as the number of times the wastestream needs to be cycled or the accumulation of brine, may vary as a result of fluctuations in the volume required to be treated and changes in pollutant concentrations. Groundwater flows may be variable (such as seasonable aquifer replenishment or due to saltwater intrusion) and the pollutant concentrations may fluctuate such that a volume reduction step or additional storage capacity is needed. The impoundment or landfill may be several miles away from the power plant, requiring additional staff and resources to implement control strategies. On the other hand, under certain conditions, as the EPA acknowledged in the 2024 Rule, absorption and attenuation of pollutants in unmanaged CRL could make treatment easier and, in that case, would likely decrease costs of such treatment. (DCN SE12165). The EPA's cost analysis appropriately reflects the typical range of costs of compliance for the industry nationwide. Nevertheless, these other factors identified above may increase the costs at some sites that markedly depart from the range of costs already considered in the EPA's analysis. As some petitioners have pointed out, completely intercepting and capturing any and all leaks of unmanaged CRL is challenging, if not impossible, for at least some power plants. Even if it were possible to intercept all contaminated groundwater, the energy for evaporation might not be available or could be cost prohibitive.

In summary, it is likely that a subset of utilities subject to a potential zero-discharge requirement would not be able to comply with the requirements, even if they were able to capture and treat the vast majority of a plume before it reaches surface water simply as a function of existing groundwater (previously contaminated with pollutants that resulted from the operation of a generating unit) subsequently reaching a WOTUS in a fashion that a permitting authority determines is still a functional equivalent of a direct discharge of unmanaged CRL. As such, the EPA proposes that setting a broad zero-discharge standard for unmanaged CRL is not only economically unachievable but also has not been demonstrated to be technically feasible for the industry as a whole due to the unique make-up of each unmanaged CRL discharge.

For the 2024 ELG and for this proposal, the EPA evaluated other zero-discharge technologies that could also eliminate the discharge of unmanaged CRL wastewater such as thermal systems. However, the EPA is not proposing to rely upon them as a basis for BAT limitations because they achieve the same pollutant reductions as the proposed Option 3 BAT technology basis (spray dry evaporators) but typically at a higher cost. The EPA has already rejected Option 3 on the basis of high costs. Nevertheless, the EPA solicits comment on the technologies that could constitute an alternative BAT technology basis for unmanaged CRL.

The EPA is not proposing Option 2 as the preferred option for BAT for both types of discharges of unmanaged CRL because total costs to the industry as a whole are unacceptably high and the EPA proposes that these costs are not economically achievable. As the EPA did not receive or identify performance data to the contrary, the EPA assumes that, despite the lack of data, discharges of pumped unmanaged CRL could meet the numeric limitations for mercury and arsenic. However, as discussed in the Technical Support memo (DCN SE12105), the EPA has revised its costs estimate for this proposal based upon a corrected and updated baseline as compared to the one utilized in the 2024 ELG, and the revised total annualized cost estimates for Option 2 is $660 million per year in the lower bound and $1.4 billion per year in the upper bound at 3.76 percent average cost of capital (see Table VII-1 and the Technical Support memo (DCN SE12105)).

These costs are nearly an order of magnitude higher than total costs to the industry to control all of the remaining end-of-pipe discharges from every other wastestream covered by the 2024 Rule combined. The EPA proposes that expecting the industry as a whole to bear these costs is unreasonable. Costs are one of the statutory factors that the EPA must consider, and courts have found that the EPA can properly rely on costs in rejecting potential BAT technologies. See e.g., BP Expl. & Oil Inc., 66 F.3d at 799-800. For further discussion of costs and economic achievability, see section VII.C of this preamble. Overall, the EPA proposes that the increased costs of imposing stringent national effluent limitations under Option 22 (relative to site-specific costs in Option 1) is unacceptable, particularly in light of the unique position of retired facilities with no revenue with which to support costs associated with meeting the effluent limitations that would apply (see section V.C of this preamble).

For the reasons discussed above, the EPA is not proposing Option 2 as the preferred option for BAT because total costs to the industry as a whole are unacceptably high and the EPA proposes that these costs are not economically achievable. In addition, the EPA has identified other sources of uncertainty that could lead to increased costs beyond those included in the revised cost analysis in certain cases, which are discussed below. These potential additional costs add further support for the EPA's proposed finding that Option 2 presents unacceptably high total costs. The Agency solicits comments on the extent to which these additional considerations should factor into the EPA's final rule.

The EPA emphasizes that there is a general lack of detailed characterization data for unmanaged CRL, particularly where leachate has mixed with groundwater. As discussed in section V, while there is an abundance of data characterizing the sources of waste and the wastewater itself in impoundments and landfills, data available on leachate is usually modeled, calculated, or estimated, and the characteristics of leachate likely change the moment it mixes with groundwater or undergoes some other physical or chemical change. Without accurate characterization in hand, it is difficult for the EPA to account for uncertainties in additional costs that may be required to meet broadly applicable technology-based limitations in all cases.

Impoundments and landfills reflect anywhere from years to decades of use, with non-homogenous layers reflecting different coal types, precipitation and stormwater, and in some cases bottom ash. When water seeps through the impoundment and mixes with groundwater, there are changes in the ensuing wastewater, including but not limited to pH, temperature, flow rate, and alkalinity. These parameters can influence the chemical forms of the pollutants that are present (DCN: SE12166).

The EPA notes that in the 2015 ELG rule analysis, the Agency assumed that the pollutants in FGD and (managed) CRL were similar. In addition to FGD wastewater, an impoundment or landfill may also receive FGD leftover materials or residues, fly ash, bottom ash, boiler slag, scrubber residues, and cenospheres. 5 Data available to date show this assumption still holds.

In contrast to (managed) CRL, the EPA finds unmanaged CRL that has mixed with groundwater shows a much higher variability. For example, the pH of coal ash CRL from all coal types ranges from 4.16 to 12.2, with a median of 9.11 (DCN SE11725). Groundwater is usually slightly alkaline and is buffered in the presence of limestone or carbonate. Groundwater can become acidic if it passes through coal, sulfides, organics, or is otherwise affected by certain forms of pollution (DCN SE12120). The EPA has also evaluated facility-specific data showing that pollutants in groundwater laden with CRL, particularly their forms and concentrations, are not always similar to FGD and traditionally managed CRL (DCN SE12167). This is due to both the reaction of the pollutants in CRL with groundwater, and the presence of pollutants in the groundwater itself that may not otherwise be present in the CRL. There is also the possibility, as discussed earlier, of adsorption and attenuation that would change the characterization of unmanaged CRL (DCN SE12165). Although the 2024 Rule acknowledged this possibility and concluded that “to the extent adsorption and other attenuation processes would remove pollutants, this would only make it easier” to achieve the chemical precipitation-based limitations, 89 FR 40251, this does not represent a complete picture of the differences that are expected to exist in unmanaged CRL that has mixed with groundwater and associated difficulties with meeting such limitations. While CRL is typically alkaline, at least three plants have shown arsenate in the unmanaged CRL wastewater (see section V of this preamble). As another example, selenate (selenium VI) favors oxygen-rich, alkaline environments. Analysis of 2025 monitoring data shows untreated CRL has a median pH near neutrality, but it can go as high as pH 9 (DCN SE12135). Should the aquifer be strongly alkaline or weakly buffered, selenate formation cannot be ruled out. To remove selenate in this situation usually requires additional technologies beyond chemical precipitation—which would represent additional costs to a facility—such as biological treatment, membrane filtration (such as reverse osmosis), or ion exchange.

Biological treatment is temperature dependent, pH sensitive, and requires sufficient alkalinity to buffer the system. Biological treatment must also be followed by a disinfection process. If the EPA were to establish chemical precipitation plus membrane filtration as the preferred option, it would cost at least 1.7 times as much as chemical precipitation alone, 6 but in most cases would not remove further pollutants beyond chemical precipitation alone. The 2024 ELG cost methodology shows membrane filtration and ion exchange are more costly than chemical precipitation (DCN SE11724).

Because of the highly unique nature of each unmanaged CRL wastestream and the unsuitability of chemical precipitation to treat all pollutants potentially present in unmanaged CRL that has mixed with groundwater without adding costs beyond what the EPA has already determined to be too costly, the EPA proposes to reject Option 2 in favor of Option 1, which would authorize the permitting authority to establish BAT limitations based on a BPJ determination that is better suited to handle site-specific factors. The EPA solicits data on the characterization of leachate mixed with groundwater and treatment technology performance, including both concentrations and chemical forms of any pollutants.

Another fact that supports the EPA's proposal not to prefer Option 2 is that the volume and pollutant concentrations in the functional equivalent direct discharge are highly dependent on prior groundwater contamination from surface impoundments or landfills and the depth to the existing groundwater table. The 2024 ELG analysis assumed that, once an appropriate volume of groundwater laden with unmanaged CRL was removed from the aquifer, it could be treated to meet the numeric limitations for arsenic and mercury. The 2024 ELG analysis conservatively assumed the groundwater and the unmanaged CRL both had the pollutants found in CRL; i.e., the total volume collected was subject to treatment as if the total volume was CRL. The analysis did not consider whether any remaining pollutants not collected would meet the numeric limitations when the remaining groundwater “daylights” or otherwise meets with surface waters. In other words, at issue here is not whether some of the unmanaged CRL mixed with groundwater can feasibly be collected and treated, rather it is an issue of how much unmanaged CRL mixed with groundwater must be collected before there is assurance that the ELG requirements have been met. Even if most of the unmanaged CRL coming from the landfill or impoundment is captured and treated, there could be ongoing exceedances at the functional equivalent direct discharge point. Therefore, in this case, a subset of power plants subject to numeric limitations for mercury and arsenic would not be able to comply with the requirements, even if they were able to capture and treat the vast majority of a plume before it reached surface water, assuming the permitting authority determines the plant still has the functional equivalent of a direct discharge. Neither the 2024 ELG analysis nor this proposal has data identifying how often these situations would occur. When such situations do occur, however, the volume of groundwater with unmanaged CRL collected is potentially underestimated. This could add significant costs for some plants where the EPA is already proposing the total costs to the industry as a whole are too high. As such, the EPA proposes that broadly setting numeric limitations for unmanaged CRL is not only economically unachievable but also has not been adequately demonstrated to be technically feasible due to the unique make-up of each stream of unmanaged CRL.

In 2009, the RCRA CCR rule survey identified 676 impoundments and landfills across 240 facilities (DCN SE12167). At 95 of those facilities, there is only one impoundment or landfill identified; 581 facilities have more than one management unit. In some instances, multiple impoundments are located adjacent to each other or in an adjoining manner. As discussed in section V, the EPA is further aware of 111 power plants that have management units that are unlined, not-clean closed, or are undergoing corrective action. This reflects the upper bound number of plants that may be determined to have the functional equivalent of a direct discharge. Consistent with the RCRA CCR rule, the analysis supporting this proposal considers the costs for wells, collection, capture, and treatment with chemical precipitation based on the groundwaters' flow and direction, thus intending to capture the primary plume of groundwater laden with CRL (DCN SE12169). The EPA is already aware that, in some cases, the waste management unit (especially landfills) may be located some distance away from the electric generating unit. (DCN: SE12104). However, there are likely instances where more than one impoundment would need to be independently managed and controlled to meet the numeric limitations under Option 2; in this case, the estimated costs are likely understated. There may also be instances where the groundwater exhibits changes in direction and flow to the extent a single system of wells is unable to capture the groundwater laden with CRL; in this case, the costs are also likely understated. In both instances, the applicability of Option 2's numeric limitations is a result of the site-specific determination of functional equivalent of a direct discharge, a decision which is beyond the scope of this proposal. The total costs of Option 2, however, are already high enough that any additional costs would further exacerbate the proposed lack of economic achievability of that option. While the possibility of the costs for collecting, pumping, and treating groundwater could have been underestimated for the 2024 ELG, it was not a concern there because the total costs were not near the range where economic achievability was thought to be an issue.

The EPA is also aware that some facilities may have impoundments or landfills located near more than one aquifer (DCN SE12103). Again, the EPA is not determining here that each impoundment or landfill is located such that where there is a functional equivalent of a direct discharge. However, multiple treatment systems may need to be deployed to meet the proposed limitations, whereas the EPA's cost methodology only presents costs for one treatment system. In light of the revised costs presented in this proposal, the added costs of additional systems could exacerbate the EPA's proposed findings regarding lack of affordability and provide further reason not to prefer Option 2.

Finally, as with Option 3, the duration of the discharges in question and the need for treatment beyond the operating life of a regulated utility may significantly increase the economic impacts of this option. This may provide additional support in favor of rejecting Option 2.

After considering updates to the industry-wide economic analyses, and further analysis of the feasibility of broadly setting numeric limitations on discharges of unmanaged CRL, the EPA is proposing to establish through regulation that, for functionally equivalent direct discharges of unmanaged CRL, BAT limitations must be derived by the permitting authority on a case-by-case BPJ basis. Additionally, the EPA is also proposing to retain the numeric discharge limitations for mercury and arsenic based on chemical precipitation for discharges of pumped unmanaged CRL.

Effluent limitations derived by permitting authorities via BPJ must, by design, be technologically available and economically achievable for a particular facility, after consideration of all appropriate factors (see section IV.B.3 for additional details). In addition, BPJ limitations have the flexibility necessary to consider highly site-specific factors to each individual plant, such as volumes of surrounding aquifers, feasibility of pumping and capturing groundwater, different hydrogeological conditions of the site, and volumes and locations of discharges of unmanaged CRL, all of which are issues that the EPA identified in connection with rejecting Options 2 and 3.

The EPA's proposed preferred option, Option 1, also complies with the CWA section 301 mandate that BAT limitations result in “reasonable further progress” toward the Act's goal of eliminating the discharge of all pollutants because it represents a step beyond the BPT-level of control, which is based on surface impoundments alone. 33 U.S.C. 1311(b)(2)(A). Under Option 1, for functionally equivalent direct discharges of unmanaged CRL, permitting authorities must consider more stringent limitations beyond those based on surface impoundments, including whether such limitations are available and achievable for the particular facility, as determined in accordance with the section 304 consideration factors. Some of the technology options for BAT that the permitting authority might consider are discussed in section V.E of this preamble, and the EPA's record includes potential limitations that could be attained based on these technologies.

The EPA also notes that the BPJ approach provides appropriate flexibility, given the rapidly increasing energy demands across the U.S. and the newfound pressures put upon these utilities to produce inexpensive and reliable electricity (as discussed in both the Steam Electric 2025 Deadline Extensions Rule and in section V of this preamble), including uncertainty surrounding retirements of existing coal-fired power plants, extended operations of EGUs due to “must run orders,” and the overall need to ensure grid reliability.

The EPA is proposing to identify chemical precipitation as BAT for plants with discharges of pumped unmanaged CRL because it is both technologically available and economically achievable for such plants. The EPA identified seven plants with these types of discharges through their corresponding CCR rule Corrective Action Plans pursuant to 40 CFR part 257, subpart D. For these seven facilities, the EPA assumes no additional costs for pumping equipment would be incurred under the proposed options. The EPA did estimate the costs of treatment for these seven facilities using the 2024 ELG cost model for chemical precipitation. Thus, these costs reflect treating a known volume of flow that has been shown to be adequate to meet the proposed numeric effluent limitations for mercury and arsenic. The estimated total annualized cost to industry at 3.76 percent average cost of capital for these facilities is $121 million under Option 1 (see Table VII-1). The EPA proposes that the costs incurred to meet the proposed arsenic and mercury limitations based on chemical precipitation are economically achievable for plants with existing discharges of pumped unmanaged CRL. Finally, for discharges of pumped, unmanaged CRL, chemical precipitation treatment represents reasonable further progress over the BPT-level of control (surface impoundments).

The EPA conducted two main types of analyses: economic impact analysis addressing how many regulated entities are affected, and benefit-cost analysis addressing the social benefits and costs associated with the proposed ELG. This section provides an overview of the methodology the EPA used to assess the social benefits and costs, and the economic impacts and summarizes the results of these analyses. “The Economic Analysis Memorandum for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category—Unmanaged Combustion Residual Leachate” (hereafter, the Economic Analysis memo) in the docket provides additional detail (DCN SE12127).

In developing ELGs, and as required by CWA section 301(b)(2)(A), the EPA evaluates the economic achievability of regulatory options to assess the impacts of applying the limitations and standards to the industry as a whole. For this proposal, the EPA compared the values to a baseline that reflects implementation of existing environmental regulations (as of this proposal), including the 2024 ELG. Like the prior analyses of the 2015, 2020, and 2024 ELGs, the cost and economic impact analysis for this proposed ELG focuses on understanding the magnitude and distribution of compliance costs across the industry. With respect to broader market impacts, because of data and methodological limitations, the EPA conducted a screening analysis that assesses the direction and magnitude of changes relative to other regulations that the EPA determined would have small impacts and be economically achievable. Specifically, the EPA analyzed the ratio of compliance costs to revenue to see how the three main regulatory options change the number of plants and their owning entities that exceed thresholds indicating potential financial strain.

In addition to the analyses supporting the economic achievability of the proposed regulatory options, the EPA conducted other analyses to (1) characterize other potential impacts of the regulatory options ( e.g., on electricity rates), (2) determine the social benefits and costs, and (3) determine broad impacts to small businesses to meet the requirements of E.O.s or other statutes ( e.g., E.O. 12866, Regulatory Flexibility Act, Unfunded Mandates Reform Act).

Compliance costs are the foundation for both economic achievability and the cost side of the benefit-cost analysis. The EPA estimated plant-specific compliance costs to control unmanaged CRL discharges at steam electric plants to which the ELGs apply. The EPA assessed the operations and treatment system components currently in place at a given unit (or expected to be in place because of other existing regulations, including the 2024 ELG and the 2015 CCR rule), identified equipment and process changes that plants would likely make under each of the three regulatory options presented in Table VI-1 of this preamble, and estimated the capital and O&M costs to implement those changes.

Because of uncertainty regarding which steam electric plants have unmanaged CRL discharges and may therefore incur costs to meet effluent limitations in this proposed ELG, the EPA used a bounding approach for developing plant-level costs that considers factors indicative of the potential for an unmanaged CRL discharge to be present, including (1) the presence of landfills or surface impoundments that are not clean closed or composite lined, (2) a total estimated groundwater pumping rate greater than 0.5 gallons per minute (gpm), and (3) whether the facility was undergoing corrective action for groundwater exceedances based on the site's most recent groundwater monitoring reported in the CCR database. The EPA solicits comment on all aspects of its groundwater pumping rates estimates, including the use of single groundwater pumping systems. See the Technical Support memo for additional details (DCN SE12105).

The lower bound scenario considers a population of 63 plants containing waste management units (landfills or surface impoundments) that do not have a composite liner, are not clean closed, and report undergoing corrective action for groundwater exceedances based on the site's most recent groundwater monitoring reported in the CCR database. All waste management units that fit these criteria from these 63 plants were accounted for in the EPA's cost analysis and assumed a separate treatment system for unmanaged CRL. For the upper bound scenario, the EPA considered 111 plants with reported waste management units that are not clean closed or composite lined but did not limit the waste management units to those with corrective action. As a conservative estimate and to better compare the upper and lower bound estimates, the EPA calculated costs for all waste management units associated with the 111 plants and assumed a separate treatment system for each waste management unit. In both scenarios, the EPA identified seven plants where pumping and treatment of groundwater was selected as the corrective remedy. These seven plants only received costing estimates for treatment of unmanaged CRL and did not incur costs for pumping and capturing unmanaged CRL in either the upper and lower bound estimations, whereas the EPA calculated costs for the remaining 56 to 104 plants to include both pumping and treating unmanaged CRL.

Together, the results represent a reasonably estimated range of nationwide costs of treatment for unmanaged CRL, but as discussed in the following paragraphs, it could overestimate costs at some facilities and underestimate costs at others. These modeling assumptions should not be interpreted as a finding that any specific site is subject to the unmanaged CRL limitations. Rather, these assumptions should be considered as assisting in a reasonable estimation of costs nationwide, with actual site-specific costs under- or overestimated. While the EPA believes that using waste management units that have triggered corrective action is a reasonable proxy for estimating waste management units most likely to incur costs associated with unmanaged CRL under this proposed ELG, the EPA notes that a facility in corrective action for its groundwater contamination does not mean that the waste management unit at issue would necessarily be found to be a point source with a functional equivalent of a direct discharge of unmanaged CRL to a WOTUS. Thus, in some cases, these costs will be overestimated for specific facilities. At the same time, it may be possible that unmanaged CRL may be subject to CWA permitting but does not trigger corrective action under the 2015 CCR regulations.

In estimating private compliance costs, the EPA used the estimated weighted average cost of capital for the industry of 3.76 percent to annualize one-time costs and costs recurring on other than an annual basis. For this analysis, the EPA annualized capital costs over the useful life of the longest-lived technology installed at any plant (20 years) and annualized costs incurred on a non-annual, periodic basis using the recurrence period ( e.g., over 6 years for costs incurred every six years). The EPA then calculated total industry costs by summing plant-specific annualized costs.

The cost estimates presented in Table VII-1 are the total annualized compliance costs associated with unmanaged CRL for the industry as a whole. In comparison to similar estimates for the 2024 ELG, the Option 2 costs are higher than those presented in 2024, reflecting the updates to the EPA's cost model and industry profile.

For the assessment of industry costs, the EPA considered costs on both a pre-tax and after-tax basis. Pre-tax annualized costs provide insight on the total expenditure as incurred, while after-tax annualized costs are a more meaningful measure of impact on privately owned for-profit entities because they incorporate approximate capital depreciation and other relevant tax treatments that reduce the net compliance burden on entities that own the plants. Since taxes are transfers, pre-tax costs reflect the real cost to society and are appropriate for benefit-cost analysis. Similarly, after-tax costs are reflective of private costs, which drive private decision-making, and are therefore appropriate for use in economic impact analysis.

The cost estimates shown in Table VII-1 are an intermediate step to producing the estimated incremental costs associated with this proposal relative to the baseline which is full implementation of the 2024 ELG. Table VII-2 summarizes the incremental costs of the three options as compared to baseline; these costs represent the costs of this proposed rule. Relative to the baseline, the preferred proposed ELG (Option 1) results in after-tax annualized savings of $462 million and $1,104 million for the lower and upper bound scenarios, respectively. Option 2 results in no incremental costs because it represents the same technology basis as the baseline.

The EPA may, if new and relevant data are received on this proposed ELG, quantify the costs of any final rule using the same models and methodologies used here and in the 2020 and 2024 ELGs.

The EPA assessed the economic impacts of this proposed ELG on existing EGUs at steam electric plants and the entities that own those plants, based on comparison of costs to revenue. The Economic Analysis memo in the record (DCN SE12127) discusses these methods and results in greater detail.

The EPA conducted the cost and economic impact analyses at both the plant and parent company level. The first level provides insight on the magnitude of compliance costs relative to the plant revenue derived from electricity generation. The second level of analysis adds insight on the impact of compliance requirements for entities that own multiple plants. Having both levels of analysis is important because the impacts could differ between these two levels. The cost and economic impact analyses—at both the plant and parent company level—provide screening-level indicators of the impacts of costs for unmanaged CRL controls relative to historical operating characteristics of steam electric plants incurring those costs ( i.e., level of electricity generation and revenue). The EPA conducted these analyses for baseline and for the three regulatory options presented in Table VI-1 of this preamble, then compared these impacts to understand the incremental effects of the regulatory options in this proposal.

For each of the two levels of analysis (plant and parent entity), the Agency assumed, for analytic convenience, that none of the compliance costs would be passed on to consumers through electricity rate increases and would instead be absorbed by the steam electric plants and their parent entities. This assumption overstates the impacts of compliance expenditures (or cost savings), as steam electric plants that operate in a regulated market may pass on changes in production costs to consumers through changes in electricity prices. If the impacts are found to be economically achievable under the assumption that no costs are passed to consumers, then the impacts will be reduced—and also economically achievable—if entities have the ability to pass along some costs to consumers.

The EPA developed revenue estimates for this analysis using Energy Information Administration (EIA) data. The EPA then calculated the change in the annualized after-tax costs of the three regulatory options presented in Table VI-1 of this preamble as a percent of baseline annual revenues. The after-tax costs incorporate approximate capital depreciation and other relevant tax treatments and are therefore a more meaningful measure of the compliance impacts on privately owned for-profit plants. Cost-to-revenue ratios are screening-level indicators of potential economic impacts. EPA guidance describes certain cost-to-revenue ratios for evaluating small entity impacts under the Regulatory Flexibility Act (RFA) (U.S. EPA 2006). The EPA used this guidance as the basis for also looking at impacts at the level of the plants, following the approach used in previous ELG regulatory analyses. Plants incurring costs below one percent of revenue are unlikely to face economic impacts, while plants with costs between one percent and three percent of revenue have a higher chance of facing economic impacts, and plants incurring costs above three percent of revenue have a still higher probability of economic impact. Under the preferred proposed ELG (Option 1), the EPA estimated that four plants, for both lower and upper bound scenarios, would incur costs greater than or equal to one percent of revenue, including three plants that have costs greater than or equal to three percent of revenue. This represents a burden reduction when compared to the 2024 ELG baseline, for which 33 and 78 plants are estimated to incur unmanaged CRL costs greater than one percent of revenue, for the lower and upper bound scenarios, respectively. The Economic Analysis memo in the record (DCN SE12127) provides results for the other regulatory options the EPA analyzed.

This proposed rulemaking does not cause adverse impacts on small entities. In fact, Option 1, the preferred option, is estimated to result in fewer small entities incurring significant impacts. Between 5 and 11 fewer small entities will experience impacts exceeding one percent of revenue as a direct result of this rule if finalized, and between 4 and 6 fewer small entities will experience impacts exceeding three percent of revenue.

The EPA also assessed the economic impact of the regulatory options presented in Table VI-1 of this preamble at the parent entity level. The screening-level cost-to-revenue analysis at the parent entity level provides insight on the impact at the level of entities that own steam electric plants. In this analysis, the domestic parent entity associated with a given plant is defined as the entity with the largest ownership share in the plant. For each parent entity, the EPA compared the incremental change in the total annualized after-tax costs and the total revenue for the entity to baseline. Following the methodology employed in the analyses for the 2015, 2020 and 2024 ELGs, the EPA considered a range of estimates for the number of entities owning an existing EGU at a steam electric plant to account for partial information available for steam electric plants that are not expected to incur ELG compliance costs.

Like the plant-level analysis above, cost-to-revenue ratios provide screening-level indicators of potential economic impacts, this time to the owning entities; higher ratios suggest a higher probability of economic impacts. The EPA estimated that the number of entities owning existing EGUs at steam electric plants ranges from 209 to 373, depending on the assumed ownership structure of those plants not likely to incur ELG costs and not explicitly analyzed. The EPA estimates that under the preferred proposed ELG (Option 1) and for the lower and upper bound cost scenarios, two parent entities would incur annualized unmanaged CRL costs representing one percent or more of their revenues, with both of these entities incurring costs representing more than three percent of revenue. This represents a burden reduction when compared to the 2024 ELG baseline, for which nine and 22 parent entities are estimated to incur unmanaged CRL costs greater than one percent of revenue, with seven and 11 of these parent entities estimated to incur costs greater than three percent of revenue.

Therefore, this proposed rulemaking does not have adverse impacts on small entities or parent entities and Option 1, the preferred option reduces impacts relative to the baseline option.

The estimated annual costs of the proposed ELG refers to social costs, which are the costs of the proposed ELG from the viewpoint of society as a whole, rather than the viewpoint of regulated plants and owning entities (which are private costs). In calculating social costs, the EPA used the pre-tax costs, as these costs represent the total expenditures irrespective of any adjustments to reflect depreciation and other relevant tax treatments. The EPA tabulated these costs in the year they are estimated to be incurred, which varies across plants based on the estimated compliance year. These estimated annual costs are also the costs used in the benefit-cost analysis.

For the analysis of social costs, the EPA estimated a plant- and year-explicit schedule of technology implementation cost outlays that reflects the “no later than date” for each option. For the baseline and Option 2, the schedule is based on plant owners installing technologies to meet the applicable limitations no later than the end of 2029. For Options 1 and 3, the deadline is December 2034. As described in section 3.1, of the Economic Analysis Memo, the EPA assumed that plants would implement technologies over several years leading to this deadline as their permits are renewed to incorporate the applicable limitations. For the baseline and Option 2, technology implementation years run from 2027 through 2029. For Options 1 and 3, the technology implementation years run from 2030 through 2034. The useful life of the technology extends for 20 years past the last year of technology installation. Thus, the full analysis period for all options for the estimation of social costs is 28 years: 2027-2054. As described further in the Economic Analysis memo to the record (DCN SE12127), the increases in the cost to state governments to develop NPDES permits based on the permitting authority's BPJ instead of the limitations specified in the baseline are small, particularly when compared to compliance costs. Consequently, the social costs are predominantly based on the pre-tax costs estimated for steam electric plants.

Table VII-3 of this preamble presents the incremental total annualized social costs of the three regulatory options, compared to baseline and calculated using three percent and seven percent discount rates. The preferred proposed ELG (Option 1) has estimated social costs savings of $446 million to $1,090 million using a three percent discount rate and $532 million to $1,286 million using a seven percent discount rate.

For each iteration of the model, we first determined which dens were exposed to the specified activities. Dens that were simulated to be within 805 m (2,641 ft) of human activity could be disturbed during all denning periods, while dens within 806-1610 m (2,644-5,282 ft) of human activity could only be disturbed during the den establishment, late denning, and post-emergence periods. If a den was detected during a simulated AIR survey, we excluded it from further disturbance in the denning analysis. However, we allowed for simulated dens to be disturbed before AIR occurred. We identified the stage in the denning period when the exposure to human activity occurred based on the date range of the activities the den was exposed to: den establishment ( i.e., initial entrance into den until cubs are born), early denning ( i.e., birth of cubs until they are 60 days old), late denning ( i.e., date cubs are 60 days old until den emergence), and post-emergence ( i.e., the date of den emergence until permanent departure from the den site). We then determined whether the exposure elicited a response by the denning polar bear based on probabilities derived from the reviewed case studies (Woodruff et al. 2022a), which we updated with data from the dens monitored from 2022 to 2025 using the methods described in Woodruff et al. (2022a).

Specifically, we divided the number of cases that documented responses associated with either a Level B harassment ( i.e., potential to cause a disruption of behavioral patterns), Level A harassment ( i.e., potential to injure an animal), or lethal take ( e.g., cub abandonment) of polar bears by the total number of cases with that combination of period and exposure type (table 5). Level B harassment was applicable to both adults and cubs, if present, whereas Level A harassment and lethal take were applicable to only cubs. We did not consider AIR surveys to be a source of potential impact. In thousands of hours of AIR surveys conducted in northern Alaska over the last decade, we are not aware of a single instance of a polar bear abandoning its den during the early denning period due to an AIR survey overflight. These responses would be readily observable on the aircraft's thermal cameras, and the fact that none have been observed indicates that den abandonment very likely does not occur given the brief duration of the aircraft overflight and the distance and altitude of the aircraft from the den site. Recent peer-reviewed research further supports the model assumption that AIR surveys are not a source of harassment (Quigley et al. 2024).

For dens exposed to activity, we used a multinomial distribution with the probabilities of different levels of take for that period (table 5) to determine whether a den was disturbed or not. If a den abandonment was simulated to occur, a den was not allowed to be disturbed again during the subsequent denning periods because the outcome of that denning event was already determined.

The level of impact associated with a disturbance varied according to the severity and timing of the exposure (table 5). Exposures that resulted in emergence from dens prior to cubs reaching 60 days of age were considered a den abandonment that results in the lethal take of cubs. If an exposure resulted in a Level A harassment during the late denning period, we first assigned that den a new random emergence date from a uniform distribution that ranged between the first date of exposure during the late denning period and the original den emergence date. We then determined whether that den was disturbed during the post-emergence period, but the probability of disturbance was dependent on whether or not a den was disturbed ( i.e., Level A harassment) during the late denning period (table 5). If an exposure resulted in a Level A harassment during the post-emergence period, we assigned the den a new time spent at the den site post-emergence from a uniform distribution that ranged from zero to the original simulated time at the den post-emergence.

Recent research suggests that litter survival is related to the date of den emergence and time spent at the den post-emergence (Andersen et al. 2024), with litters having higher survival rates the later they emerge in the spring, and the longer they spend at the den site after emergence. To determine if dens that were disturbed during the late denning and/or post-emergence period(s) experienced Level A harassment, we relied on estimates of litter survival in the spring following den emergence, derived from the analysis of empirical data on the dates of emergence from the den and departure from the den site (Andersen et al. 2024). These estimates are dependent on the date of emergence and time spent at the den site post-emergence. For each den disturbed during the late denning and/or post-emergence periods, we obtained a random sample of regression coefficients from the posterior distribution and calculated the probability of a litter surviving into the spring post-emergence with the following equation:

These probabilities are based on estimates of litter survival derived from the analysis of empirical data on the dates of emergence from the den and departure from the den site (Andersen et al. 2024).

We developed the code to run this model in the program R (R Core Development Team 2020) and ran 10,000 iterations of the model ( i.e., Monte Carlo simulation) to derive the estimated number of dens disturbed and associated levels of harassment. We then determined the number of cubs that would experience den abandonment, Level A harassment, and Level B harassment, and the number of females that would experience Level B harassment. Table 5 shows the probability of an exposure resulting in the types of harassment of denning polar bears.

We created multiple scenarios in our analysis by generating a variety of combinations of the different confidential survey blocks while adhering to the previously described maximum area of impact within each of the four zones (see Den Simulation ). We used the results of the scenario with the highest level of impact for our estimation of annual harassment. We estimated a rounded mean value of 5 (mean = 4.36; median = 4; 95 percent CI: 1-10) land-based dens in the area of specified activity in SAE's request and within a 1.6-km (1-mi) buffer of the activities, annually. Estimates for different levels of take are presented in table 6. The distributions of Level B harassment, Level A harassment, and lethal takes due to den abandonment were non-normal and heavily skewed, as indicated by markedly different mean and median values. The heavily skewed nature of these distributions has led to a mean value that is not representative of the most common model result.

The median number, which is the midpoint value of a frequency distribution of all model results, of Level B and Level A harassments is both two, and the median number of lethal takes is zero. The probability of one or more takes of denning polar bears occurring in any given year of the proposed ITR by Level B harassment, Level A harassment, or lethal take was 0.73, 0.64, and 0.10, respectively. However, in aggregate across all 5 years of the proposed ITR, the median value for takes of denning polar bears by Level B harassment and by Level A harassment were 11 and 8 respectively.

The median value for lethal take in aggregate remained zero. The probabilities of one or more takes of denning polar bears occurring across the entire 5-year duration of this proposed ITR by Level B harassment, Level A harassment, and lethal take were 0.99, 0.99, and 0.35, respectively. Our estimated number of possibly exposed dens in the area across all 5-years was 19 (mean = 18.99; median = 19, 95 percent CI: 10-30). The activities analyzed for this proposed ITR represent the maximum number of activities that may occur within each year of the 5-year ITR period. Therefore, the actual activity footprint will likely be smaller during each year, which would reduce the probability of take. Due to the low probability of one or more lethal takes occurring either annually (0.09) or in 5-year aggregate (0.35), along with a median value of zero for either time period, we do not anticipate the specified activities will result in lethal take of polar bears. Additionally, mitigation measures, such as the use of handheld and vehicle-mounted forward looking infrared cameras when SAE crews are traversing areas of relief and snow drifts, will be implemented to further reduce the probability of take and minimize impacts to denning polar bears.

In order to conduct this analysis and estimate the potential amount of Level B harassment and Level A harassment, we made several critical assumptions.

Level B harassment is equated herein with behavioral responses that indicate harassment or disturbance, however some portion of animals whose behavioral response indicates disturbance will not experience significant biological consequences. Our estimates do not account for variable responses by polar bear age and sex; however, sensitivity of denning polar bears was incorporated into the analysis. The available information suggests that polar bears are generally resilient to low levels of disturbance. Females with dependent young and juvenile polar bears are physiologically the most sensitive (Andersen and Aars 2008) and most likely to experience harassment from disturbance. Not enough information on composition of the SBS polar bear stock in the specified project area is available to incorporate individual variability based on age and sex or to predict its influence on harassment estimates. Our estimates are derived from a variety of sample populations with various age and sex structures, and we assume the exposed population will have a similar composition and, therefore, the response rates are applicable.

The estimates of behavioral response presented here do not account for the individual movements of animals in response to the specified activities. Our assessment assumes animals remain stationary ( i.e., density does not change). Not enough information is available about the movement of polar bears in response to specific disturbances to refine this assumption.

SBS polar bears create maternal dens on the sea ice as well as on land, and the specified activities may occur on sea ice close to the shoreline. The den simulation used in our analysis does not simulate dens on the sea ice. However, the portions of the sea ice that may be impacted by the specified activities are shore-fast ice, which does not move in a way that creates pressure ridges needed to create sufficient denning habitat.

SAE will conduct archeological surveys, AIR surveys for maternal polar bear dens, seismic surveys, and summer cleanup activities on the North Slope of Alaska for a period of 5 years. A summary of total number of estimated takes by Level B harassment and Level A harassment in any given single year of the total 5-year proposed authorization period is provided in table 5. We used the most impactful take scenarios when generating annual take estimates to provide conservative values. We also explored the potential for lethal take. Lethal take or Level A harassment would not occur outside of denning polar bears because the level of sound and visual stimuli on a polar bear on the surface would not be significant enough to result in injury or death. Denning polar bears, however, may be subject to repeated exposures, significant energy expenditure from den abandonment or departure, or potential impacts to a cub if the den is abandoned or departed prematurely. The probability of greater than or equal to one lethal take of denning polar bears is 0.16 under the most impactful operations scenario in a single year. In addition to annual estimates of take, we estimated the amount and probability of take aggregated across the 5-year period of this proposed ITR. The total 5-year aggregate estimates are provided in table 8. Across the 5-year period of the proposed ITR, the probability of greater than or equal to one lethal take of polar bears is 0.35.

The specified activities evaluated here do not involve production and transportation of large quantities of oil. The FWS previously evaluated the impacts of oil spills on SBS polar bears in the specified geographic region and concluded that only small numbers of polar bears are likely to be affected if a large oil spill occurred and there would be only a negligible impact to the SBS polar bears (2021-2026 Beaufort Sea ITR (86 FR 42982, August 5, 2021)). Additionally, SAE will implement protocols to contain and cleanup spills from oil, fuel, and other hazardous materials to minimize potential impacts to polar bears and their habitat. Therefore, the FWS concludes that the likelihood of a large oil spill occurring due to the specified activities is negligible. If a small spill occurs, the likelihood that it would contaminate areas occupied by large numbers of polar bears is low. If an oil spill does occur, we conclude that only small numbers of polar bears are likely to be affected, and there would be only a negligible impact to SBS polar bears.

For our small numbers determination, we provide a qualitative discussion and incidental take estimates when we consider whether the number of polar bears to be subjected to incidental take is respectively small relative to the population size of the species or stock.

1. The footprint of the specified activities within the specified geographic region is small relative to the range of the SBS stock of polar bears. SBS polar bears range well beyond the boundaries of the proposed ITR region. As such, the ITR region itself represents only a subset of the potential area in which these species may occur. Thus, the FWS concludes that a small portion of the SBS polar bear populations may be present in the specified geographic region during the time of the specified activities.

2. We estimate SAE's specified activities in the specified geographic region will take no more than 15 polar bears during any given year of this proposed ITR, which includes the annual estimated Level B harassment of 11 polar bears on the surface and 2 denning polar bears and Level A harassment of 2 denning polar bears, and no more than a total of 66 polar bears by Level B harassment and 8 polar bears by Level A harassment over the five-year duration of this ITR (see Sum of Harassment from All Sources ). Annual take of 15 animals is approximately 1.7 percent of the best available estimate of the current SBS stock size of 907 animals (Bromaghin et al. 2015, 2021; Atwood 2020) and represents a “small number” of polar bears of that stock. The FWS released a draft stock assessment report (SAR) for the SBS polar bear population on January 2, 2025 (90 FR 114), in which the SBS polar bear stock has changed to 819 bears, largely due to a shift in the border between the SBS and North Beaufort Sea stock. Should this draft SAR be finalized, 15 bears constitute 1.8 percent of the SBS stock. These estimates indicate that the number of polar bears that would be incidentally taken is small relative to the size of the SBS stock.

We propose a finding that take of up to 15 SBS polar bears in any given year by Level B harassment, with a total 74 SBS polar bears in aggregate across the 5-year duration (66 by Level B harassment and 8 by Level A harassment) of this proposed ITR represents a small number of the SBS polar bear stock.

For our negligible impacts determination, we consider the following:

1. The documented impacts of previous activities similar to the specified activities on polar bears, and, taking into consideration the baseline of existing impacts from factors such as oil and gas activities in the area and other ongoing or proposed incidental take authorizations, suggest that the types of specified activities will have minimal effects on polar bears. Additionally, the effects will be limited to short-term, temporary behavioral changes, or minor injury. Furthermore, our analyses do not indicate, nor do we anticipate, any lethal take of polar bears during the 5-year period of this proposed ITR. While we do estimate that up to two cubs may experience a short-term fitness decline in the period immediately following den departure, we also do not anticipate that they will experience long lasting impacts that could significantly impact their health, reproduction, or survival. The limited extent of anticipated impacts on polar bears is unlikely to adversely affect annual rates of polar bear survival or recruitment.

2. The distribution and habitat use patterns of polar bears indicate that relatively few polar bears will occur in the specified areas of activity at any time and, therefore, few polar bears are likely to be affected.

3. SAE has proposed, and would be required to implement, mitigation measures and monitoring designed to reduce the potential impacts of their operations on polar bears. Den detection surveys for polar bears, along with adaptive mitigation and management responses based on real-time monitoring information (described in this proposed authorization), will be used to avoid or minimize interactions with polar bears and, therefore, limit potential disturbance of these species.

We also consider the conjectural or speculative impacts associated with these specified activities. The specific congressional direction described below justifies balancing the probability of such impacts with their severity: If potential effects of a specified activity are conjectural or speculative, a finding of negligible impact may be appropriate. A finding of negligible impact may also be appropriate if the probability of occurrence is low, but the potential effects may be significant. In this case, the probability of occurrence of impacts must be balanced with the potential severity of harm to the species or stock when determining negligible impact. In applying this balancing test, the FWS will thoroughly evaluate the risks involved and the potential impacts on marine mammal populations. Such determination will be made based on the best available scientific information (54 FR 40338, September 29, 1989, quoting 53 FR 8473, March 15, 1988, and 132 Cong. Rec. S 16305 (October 15, 1986)).

We reviewed the effects of the seismic exploration activities on polar bears, including impacts from surface interactions, aircraft overflights, and den disturbance. Based on our review of these potential impacts, past monitoring reports, and the biology and natural history of polar bears, we conclude that any incidental take reasonably likely to occur as a result of specified activities will be limited to short-term behavioral disturbances that would not affect the rates of recruitment or survival for the SBS stock of polar bears.

The potential effects of most concern here, specific to polar bears, is the mortality of polar bear cubs that could result from disturbances during certain periods of the denning season. The FWS estimated that the probability of greater than or equal to one lethal take is 0.09 annually and 0.35 across the 5-year duration of this proposed ITR. Therefore, the FWS does not anticipate any lethal take will occur during the ITR period. If a den is disturbed and lethal take were to occur, this take would be limited to only cubs during the denning period. Impacts to denning females, the demographic group most important to annual recruitment, are limited to take by Level B or Level A harassment. Therefore, the number of potentially available reproductive females that would contribute to recruitment for the SBS stock would remain unaffected if a den disturbance were to result in the mortality of the cubs.

Cub mortality occurs naturally each year. Cub litter survival was estimated at 50 percent (90 percent CI: 33-67 percent) for the SBS stock during 2001-2006 (Regehr et al. 2010), indicating a female may lose her litter for several reasons separate from den disturbance. The SBS stock of polar bears is currently estimated as 907 polar bears (Bromaghin et al. 2015, 2021; Atwood et al. 2020). The loss of one litter ranges from 0 percent (0 cubs) to approximately 0.33 percent (3 cubs) of the annual SBS stock size of polar bears (((0 cubs to 3 cubs) ÷907) × 100≉0 to 0.33). The determining factor for polar bear stock growth is adult female survival (Eberhardt 1990). Consequently, the loss of female cubs has a greater impact on annual recruitment rates for the SBS stock of polar bears compared to male cubs. If a den disturbance were to result in the mortality of the entire litter, the female would be available to breed during the next mating season and could produce another litter during the next denning season.

Based on the projection that zero cub mortality would be associated with these specified activities, and the recognition that even if a den is disturbed, the number of potentially affected cubs would be minimal and the number of reproductive females in the stock would remain the same, the FWS does not anticipate that the conjectural or speculative impacts associated with these specified activities warrant a finding of non-negligible impact or otherwise preclude issuance of this proposed ITR.

We have evaluated the effects of climate change on polar bears as part of the environmental baseline. Climate change is considered as the overall driver of effects that could alter polar bear habitat and behavior. The FWS is currently involved in research to understand how climate change may affect polar bears. As we gain a better understanding of climate change effects, we will incorporate the information in future authorizations.

We find that the impacts of these specified activities cannot be reasonably expected to, and are not reasonably likely to, adversely affect SBS polar bears through effects on annual rates of recruitment or survival. Therefore, the FWS proposes that the total of the taking estimated above and proposed for authorization will have a negligible impact on SBS polar bears.

Based on past community consultations, locations of hunting areas, no anticipated overlap of hunting areas and the specified activities, and the best scientific information available, including monitoring data from similar activities, we propose a finding that take caused by the specified seismic exploration activities in the specified geographic region will not have an unmitigable adverse impact on the availability of polar bears for taking for subsistence uses during the specified timeframe.

While polar bears represent a small portion, in terms of the number of animals, of the total subsistence harvest for the Kaktovik and Nuiqsut communities, the harvest of these species is important to Alaska Natives. SAE will contact subsistence communities that may be affected by its activities to discuss potential conflicts caused by location, timing, and methods of the specified activities. SAE will make reasonable efforts to ensure that activities do not interfere with subsistence hunting and that adverse effects on the availability of polar bears are minimized. The FWS is not aware of any concerns having been voiced by the Alaska Native communities regarding the specified activities limiting availability of polar bears for subsistence uses. However, should such a concern be voiced, SAE's POC, which will identify measures to minimize any adverse effects, will be implemented. The POC will ensure that the specified activities will not have an unmitigable adverse impact on the availability of the species or stock for subsistence uses. The POC provides the procedures addressing how SAE will work with the affected Alaska Native communities and what actions will be taken to avoid interference with subsistence hunting of polar bears, as warranted.

The FWS has not received any reports and is not aware of information that indicates that polar bears are being or will be deterred from hunting areas or impacted in any way that diminishes their availability for subsistence use by the expected level of seismic exploration activity. If there is evidence that these activities are affecting the availability of polar bears for subsistence uses, we will reevaluate our findings regarding permissible limits of take and the measures required to ensure continued subsistence hunting opportunities.

We evaluated the practicability and effectiveness of mitigation measures based on the nature, scope, and timing of the specified activities; the best available scientific information; and monitoring data during industry activities in the specified geographic region. We propose a finding that the mitigation measures included within SAE's request will ensure least practicable adverse impacts on polar bears.

Polar bear den surveys at the beginning of each well survey season, the resulting 1.6-km (1-mi) operational exclusion zone around all known polar bear dens, and restrictions on the timing and types of activities in the vicinity of dens and females with cubs of the year observed during the den emergence period will ensure that impacts to denning females and their cubs are minimized during this critical period. Minimum flight elevations over polar bear areas and flight restrictions around observed polar bears and known polar bear dens will reduce the potential for aircraft disturbing polar bears. Finally, SAE will implement mitigation measures to prevent the presence and impact of attractants in camps such as the use of wildlife-resistant waste receptacles, daily food waste incineration, and storing hazardous materials in drums or other secure containers. These measures are outlined in a polar bear interaction plan that was developed in coordination with the FWS and is part of SAE's application for this ITR. Based on the information we currently have regarding den and aircraft disturbance and polar bear attractants, we concluded that the mitigation measures outlined in SAE's Request (SAE 2025) and incorporated into this proposed authorization will minimize impacts from the specified seismic exploration activities to the extent practicable.

A number of mitigation measures were considered but determined to be not practicable. These measures are listed below:

• Require use of helicopters for AIR surveys —Use of helicopters to survey active dens might lead to greater levels of disturbance and take compared to fixed-wing aircraft. This statement is supported by greater harassment rates for helicopter overflights compared to fixed-wing overflights determined in the aircraft take estimate analysis. Additionally, there is no published data to indicate increased den detection efficacy of helicopter AIR.

• Require optimal weather conditions for AIR surveys —Some restrictions on weather conditions for AIR surveys were included as mitigation measures; however, additional restrictions would not be practicable for the specified activities due to the available timeframe to complete AIR surveys to affect the least practicable adverse impact on polar bears.

• Ground all flights if they must fly below 457 m (1,500 ft) —Requiring all aircraft to maintain an altitude of 457 m (1,500 ft) at all times is not practicable as some operations may require flying below 457 m (1,500 ft) to perform necessary inspections or maintain safety of flight crew. Aircraft are required to fly above 457 m (1,500 ft) at all times within 805 m (0.5 mi) of an observed polar bear unless there is an emergency.

• Require speed restrictions for aircraft operations —Requiring aircraft to operate below a specific speed limit is not practicable as some operations may require speeds above the specified speed limit to maintain safety of the flight crew during various weather conditions. Additionally, aircraft operating at lower speeds may increase the duration of impact and potentially result in greater levels of disturbance to polar bears.

• Spatial and temporal restrictions on surface activity —Some spatial and temporal restrictions of operations were included in SAE's Request; however, additional restrictions would not be practicable for the specified activities based on other regulatory and safety requirements, and the need to acquire enough data to meet project objectives.

• One-mile buffer around all known polar bear denning habitat —One-mile (1.6-km) buffer around all known polar bear denning habitat is not practicable as much of SAE's specified survey area occurs within 1.6 km (1 mi) of denning habitat; thus, to exclude all areas within 1.6 km (1 mi) of denning habitat would preclude surveys from occurring.

• Prohibit driving over high relief areas, embankments, or stream and river crossings —In their request, SAE has committed to avoiding the leeward side of river banks and bluffs, where snow can accumulate and create polar bear denning habitat. Additionally, SAE would use handheld or truck-mounted infrared units to check of polar bears or dens prior to crossing suitable habitat and will place all river crossing at the lowest possible relief point to reduce the possibility of suitable denning habitat being present. To completely avoid these types of areas would likely cause personnel to drive further away from established operational areas and unnecessarily create additional safety concerns. Furthermore, other mitigation measures to minimize impact to denning habitats are included and will minimize the risk imposed by driving over high relief areas, embankments, or stream and river crossings. Lastly, the probability of a den being run over by equipment during the specified activities is exceedingly low each year of the proposed ITR, and this probability will be further mitigated by AIR surveys during the beginning of the specified activities to detect dens within 1.6 km (1 mi) of the activities.

• Use of a broader definition of “denning habitat” for operational offsets —No data are available to support broadening the defining features of denning habitat beyond that established by USGS.

• Prohibit activities within designated critical habitat for polar bears —Critical habitat for polar bears must be considered during the specified activities; however, complete prohibition is not practicable due to the large spatial extent of critical habitat and project objectives.

• Establish corridors for female and cub transit to the sea ice —As no data support the existence of natural transit corridors to the sea ice, establishment of corridors in the proposed ITR area would be highly speculative. Therefore, no mitigative benefit would be realized by their establishment.

• Require third-party neutral marine mammal observers —SAE has committed to conducting polar bear training that meets FWS standards and will use bear guards to monitor for polar bears during project activities. These bear guards will be fully incentivized to diligently monitor for polar bears given inherent safety considerations.

• Require all activities to cease if a polar bear is injured or killed until an investigation is completed —The FWS has incorporated into this proposed authorization reporting requirements for all polar bear interactions. While ceasing all activities may aid in any subsequent investigation, doing so may not be practicable or safe in certain circumstances and, thus, will not be mandated prospectively.

• Require use of den detection dogs —Requiring scent-trained dogs to detect dens is not practicable or safe for this project due to the large spatial extent that would need to be surveyed within seismic survey areas. Additional crew may require additional transit vehicles and accommodations, which could increase disturbance to polar bears.

• Construct safety gates, fences, and enclosures to prevent polar bears from accessing facilities —Constructing safety gates, fences, and enclosures to prevent polar bears from accessing facilities is not practicable due to the short-term and relatively mobile project activities and temporary facilities. SAE will place skirting around elevated facilities to prevent polar bears from accessing these areas.

• Require the use of handheld or vehicle-mounted forward-looking infrared equipment —The efficacy rates for AIR surveys have been found to be four times more likely to detect dens versus ground-based forward-looking infrared (handheld or vehicle-mounted) equipment due to impacts of blowing snow on detection. SAE has incorporated into their mitigation measures the use of handheld or vehicle-mounted forward-looking infrared units when transiting rivers occurring in suitable denning habitat, but it is not practicable to use the equipment during all transit.

• Temporal restrictions after July 1 —While SAE has committed to prioritizing cleanup in coastal areas first to complete them prior to July 1, the overall timing of cleanup activities is dependent upon snow-free conditions, which vary yearly and may not occur before July 1.

The purpose of monitoring requirements is to assess the effects of the specified activities on polar bears, continual verification of ITR compliance, ensure take does not have more than a negligible impact on species stocks, and detect any unanticipated effects on the species or stock. Monitoring plans document when and how polar bears are observed, the number of polar bears, and their behavior during the observation. This information allows the FWS to measure encounter rates, examine trends in polar bear activity and distribution in the industrial areas, and estimate the number of polar bears potentially affected by industrial activities. SAE would report all observations of polar bears. To the extent possible, personnel that encounter polar bears will record group size, age, sex, behavior, duration of observation, and closest approach to human activity.

The FWS would provide SAE with the most recent and up-to-date Polar Bear Observation Form in which to record observations of polar bears. Observations must be reported to the FWS's Marine Mammals Management Office within 48 hours of the observation and submitted to fw7_mmm_reports@fws.gov. Details on monitoring guidelines and reporting requirements can be read below in the rule portion of this document in proposed § 18.172 Monitoring and § 18.173 Reporting Requirements.

If you wish to comment on these proposed regulations or the associated draft environmental assessment, you may submit your comments by any of the methods described in ADDRESSES . Please identify if you are commenting on the proposed regulations, the draft environmental assessment, or both, make your comments as specific as possible, confine them to issues pertinent to the proposed regulations, and explain the reason for any changes you recommend. Where possible, your comments should reference the specific section or paragraph that you are addressing. The FWS will consider all comments that are received by the close of the comment period (see DATES ).

We are required by Executive Orders 12866 and 12988 and by the Presidential Memorandum of June 1, 1998, to write all rules in plain language. This means that each rule we publish must:

(a) Be logically organized;

(b) Use the active voice to address readers directly;

(c) Use common, everyday words and clear language rather than jargon;

(d) Be divided into short sections and sentences; and

(e) Use lists and tables wherever possible.

If you feel that we have not met these requirements, send us comments by one of the methods listed in ADDRESSES . To better help us revise the rule, your comments should be as specific as possible. For example, you should tell us the numbers of the sections or paragraphs that you find unclear, which sections or sentences are too long, the sections where you feel lists or tables would be useful, etc.

We have prepared a draft environmental assessment in accordance with the NEPA (42 U.S.C. 4321 et seq. ). We have preliminarily concluded that the proposed action of issuing an ITR would not significantly affect the quality of the human environment, and, thus, preparation of an environmental impact statement for this incidental take regulation is not required by section 102(2) of NEPA or its implementing regulations. We are accepting comments on the draft environmental assessment as specified above in DATES and ADDRESSES .

Under the ESA (16 U.S.C. 1536(a)(2)), all Federal agencies are required to ensure the actions they authorize are not likely to jeopardize the continued existence of any threatened or endangered species or result in destruction or adverse modification of critical habitat. Prior to finalizing this ITR, if warranted, the FWS will complete intra-Service consultation under section 7 of the ESA on our proposed issuance of an ITR. These evaluations and findings would be made available on the FWS's website at https://ecos.fws.gov/ecp/report/biological-opinion.

It is our responsibility to communicate and work directly on a Government-to-Government basis with federally recognized Alaska Native Tribes and organizations in developing programs for healthy ecosystems. We seek their full and meaningful participation in evaluating and addressing conservation concerns for protected species. It is our goal to remain sensitive to Alaska Native culture and to make information available to Alaska Natives. Our efforts are guided by Executive Order 13175—Consultation and Coordination With Indian Tribal Governments, 512 DM 5— Procedures for Consultation with Indian Tribes, 512 DM 6— Department of the Interior Policy on Consultation with Alaska Native Claims Settlement Act Corporations, 510 FW 1, The Service's Native American Policy, and 510 FW 2, The Service's Alaska Native Relations Policy. We have evaluated possible effects of the specified activities on federally recognized Alaska Native Tribes and organizations. Through the ITR process identified in the MMPA, the applicant has presented a communication process, culminating in a POC if needed, with the Native organizations and communities most likely to be affected by their work. The FWS does not anticipate impacts to Alaska Native Tribes or Alaska Native Claims Settlement Act corporations and does not anticipate requesting consultation; however, we invite continued discussion, either about the project and its impacts or about our coordination and information exchange throughout the ITR/POC process.

E.O. 12866 provides that the Office of Information and Regulatory Affairs (OIRA) in the OMB will review all significant rules. OIRA has determined that this proposed rule is not significant.

E.O. 13563 reaffirms the principles of E.O. 12866 while calling for improvements in the Nation's regulatory system to promote predictability, to reduce uncertainty, and to use the best, most innovative, and least burdensome tools for achieving regulatory ends. E.O. 13563 directs agencies to consider regulatory approaches that reduce burdens and maintain flexibility and freedom of choice for the public where these approaches are relevant, feasible, and consistent with regulatory objectives. E.O. 13563 emphasizes further that regulations must be based on the best available science and that the rulemaking process must allow for public participation and an open exchange of ideas. We have developed this rule in a manner consistent with these requirements.

OIRA bases its determination of significance upon the following four criteria: (a) Whether the rule will have an annual effect of $100 million or more on the economy or adversely affect an economic sector, productivity, jobs, the environment, or other units of the government; (b) whether the rule will create inconsistencies with other Federal agencies' actions; (c) whether the rule will materially affect entitlements, grants, user fees, loan programs, or the rights and obligations of their recipients; and (d) whether the rule raises novel legal or policy issues.

Expenses will be related to, but not necessarily limited to: the development of requests for LOAs; monitoring, recordkeeping, and reporting activities conducted during archeological surveys, AIR maternal polar bear den surveys, seismic surveys, and aircraft-supported cleanup activities; development of activity- and species-specific marine mammal monitoring and mitigation plans; and coordination with Alaska Natives to minimize effects of operations on subsistence hunting. Realistically, costs of compliance with this proposed rule, if finalized, are minimal in comparison to those related to actual archeological surveys, AIR maternal polar bear den surveys, seismic surveys, and aircraft-supported cleanup activities. The actual costs to develop the petition for promulgation of regulations and LOA requests fall short of the “major rule” threshold that would require preparation of a regulatory impact analysis.

We have determined that this proposed rule, if finalized, is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. The proposed rule is also not likely to result in a major increase in costs or prices for consumers, individual industries, or government agencies or have significant adverse effects on competition, employment, productivity, innovation, or on the ability of United States-based enterprises to compete with foreign-based enterprises in domestic or export markets.

We have determined that this proposed rule, if finalized, will not have a significant economic effect on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq. ). SAE and their contractors conducting archeological survey, AIR maternal polar bear den surveys, seismic surveys, and summer cleanup activities on the North Slope are the only entities subject to this proposed ITR. Therefore, neither a regulatory flexibility analysis nor a small entity compliance guide is required.

This proposed rule, if finalized, does not have takings implications under Executive Order 12630 because it authorizes the incidental, but not intentional, take of polar bears by seismic exploration activities and, thereby, exempts SAE from civil and criminal liability as long as they operate in compliance with the terms of their LOAs. Therefore, a takings implications assessment is not required.

This proposed rule, if finalized, does not contain policies with federalism implications sufficient to warrant preparation of a federalism assessment under Executive Order 13132. The MMPA gives the FWS the authority and responsibility to protect polar bears.

In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq. ), this proposed rule, if finalized, will not “significantly or uniquely” affect small governments. A small government agency plan is not required. The FWS has determined and certifies pursuant to the Unfunded Mandates Reform Act that this rulemaking will not impose a cost of $100 million or more in any given year on local or State governments or private entities. This rule, if finalized, will not produce a Federal mandate of $100 million or greater in any year, i.e., it is not a “significant regulatory action” under the Unfunded Mandates Reform Act.

The Departmental Solicitor's Office has determined that this proposed rule, if finalized, will not unduly burden the judicial system and meets the applicable standards provided in sections 3(a) and 3(b)(2) of Executive Order 12988.

This proposed rule contains new information collections subject to approval by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995 (PRA; 44 U.S.C. 3501 et seq. ). All information collections under the PRA require OMB approval. We may not conduct or sponsor and you are not required to respond to a collection of information unless it displays a currently valid OMB control number. We are requesting a new control number for the information collection requirements in this subpart. OMB previously approved the information collection requirements associated with incidental take in the identified subparts and assigned the following control numbers:

• 1018-0070, Incidental Take of Marine Mammals During Specified Activities (50 CFR 18.27 and 50 CFR 18, Subpart J) (expires 08/31/2028), and

• 1018-0203, Incidental Take of Marine Mammals During Specified Activities (50 CFR 18.27 and 50 CFR 18, Subpart L) (expires 08/31/2028).

In accordance with the PRA and its implementing regulations at 5 CFR 1320.8(d)(1), we provide the general public and other Federal agencies with an opportunity to comment on our proposal to request OMB approval of the information collections in this proposed rule. This helps us assess the impact of our information collection requirements and minimize the public's reporting burden. It also helps the public understand our information collection requirements and provide the requested data in the desired format.

As part of our continuing effort to reduce paperwork and respondent burdens, and in accordance with 5 CFR 1320.8(d)(1), we invite the public and other Federal agencies to comment on any aspect of this proposed information collection, including:

(1) Whether or not the collection of information is necessary for the proper performance of the functions of the agency, including whether or not the information will have practical utility;

(2) The accuracy of our estimate of the burden for this collection of information, including the validity of the methodology and assumptions used;

(3) Ways to enhance the quality, utility, and clarity of the information to be collected; and

(4) Ways to minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of response.

Comments that you submit in response to this proposed rulemaking are a matter of public record. Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.

This is a nonform collection. Respondents must comply with the regulations at 50 CFR 18.27, which outline the procedures and requirements for submitting a request. These regulations provide the applicant with a detailed description of information that we need to evaluate the proposed activity and determine if it is appropriate to issue specific regulations and, subsequently, LOAs. The FWS's proposed rule (RIN 1018-BG75) would create a new subpart, 50 CFR part 18, subpart N (SAExploration, Inc., valid for a period of 5 years), which addresses the incidental, unintentional take of small numbers of polar bears ( Ursus maritimus ) during seismic exploration activities on the North Slope of Alaska.

We will use the information collected to verify the findings required to issue incidental take regulations, to decide if we should issue an LOA, and (if an LOA is issued) what conditions should be included in the LOA. In addition, we will analyze the information to determine impacts to polar bears, and the availability of those marine mammals for subsistence purposes of Alaska Natives.

The information collections contained in the newly proposed subpart N described below require approval by OMB:

(1) Application For Regulations (50 CFR 18.27(d)) —Regulations at 50 CFR part 18 require the applicant to provide information on the activity as a whole, which includes, but is not limited to, an assessment of total impacts by all persons conducting the activity. Applicants can find specific requirements in 50 CFR part 18, subparts N. These regulations provide the applicant with a detailed description of information that we need to evaluate the proposed activity and determine whether to issue specific regulations and, subsequently, LOAs. The required information includes:

• A description of the specific activity or class of activities that can be expected to result in incidental taking of marine mammals.

• The dates and duration of such activity and the specific geographical region where it will occur.

• Based on the best available scientific information, each applicant must also provide:

• The anticipated impact of the activity upon the habitat of the marine mammal populations and the likelihood of restoration of the affected habitat.

• The availability and feasibility (economic and technological) of equipment, methods, and manner of conducting such activity or other means of effecting the least practicable adverse impact upon the affected species or stocks, their habitat, and, where relevant, on their availability for subsistence uses, paying particular attention to rookeries, mating grounds, and areas of similar significance. (The applicant and those conducting the specified activity and the affected subsistence users are encouraged to develop mutually agreeable mitigating measures that will meet the needs of subsistence users.)

• Suggested means of accomplishing the necessary monitoring and reporting that will result in increased knowledge of the species through an analysis of the level of taking or impacts and suggested means of minimizing burdens by coordinating such reporting requirements with other schemes already applicable to persons conducting such activity.

• Suggested means of learning of, encouraging, and coordinating research opportunities, plans, and activities relating to reducing such incidental taking from such specified activities, and evaluating its effects.

• Applicants must develop and implement a site-specific (or umbrella plan addressing site-specific considerations), FWS-approved marine mammal monitoring and mitigation plan to monitor and evaluate the effectiveness of mitigation measures and the effects of activities on marine mammals and the subsistence use of these species.

• Applicants must also provide trained, qualified, and FWS-approved onsite observers to carry out monitoring and mitigation activities identified in the marine mammal monitoring and mitigation plan.

This information is necessary so that we can anticipate the impact of the activity on the species or stocks and on the availability of the species or stocks for subsistence uses. Under requirements of the MMPA, we cannot authorize a take unless the total of all takes will have a negligible impact on the species or stocks and, where appropriate, will not have an unmitigable adverse impact on the availability of the species or stocks for subsistence uses. These requirements ensure that applicants are aware of related monitoring and research efforts they can apply to their situation, and that the monitoring and reporting that we impose are the least burdensome to the applicant.

(2) Final Monitoring Report (50 CFR 172(c)) —The results of monitoring and mitigation efforts identified in the marine mammal monitoring and mitigation plan must be submitted to the FWS for review within 90 days of the expiration of an LOA. Upon request, final report data must be provided in a common electronic format (to be specified by the FWS). Information in the final (or annual) report must include, but is not limited to:

• Copies of all observation reports submitted under the LOA;

• A summary of the observation reports;

• A summary of monitoring and mitigation efforts including areas, total hours, total distances, and distribution;

• Analysis of factors affecting the visibility and detectability of polar bears during monitoring;

• Analysis of the effectiveness of mitigation measures;

• Analysis of the distribution, abundance, and behavior of polar bears observed; and

• Estimates of take in relation to the specified activities.

(3) Requests for Letters of Authorization (LOA) (50 CFR 18.27(f) and 18.167) —LOAs, which may be issued only to U.S. citizens, are required to conduct activities pursuant to any specific regulations established. Once specific regulations are effective, the FWS will, to the maximum extent possible, process subsequent requests for LOAs within 30 days after receipt of the request by the FWS. All LOAs will specify the period of validity and any additional terms and conditions appropriate for the specific request. Issuance of LOAs will be based on a determination that the level of taking will be consistent with the findings made for the total taking allowable under the specific regulations.

(4) Polar Bear Den Detection Report (50 CFR 18.170(b)(1)(iv)) —Holders of an LOA seeking to carry out onshore activities in known or suspected polar bear denning habitat during the denning season must make efforts to locate occupied polar bear dens within and near proposed areas of operation. They may use any appropriate tool, such as forward-looking infrared imagery and/or polar bear scent-trained dogs, in concert with denning habitat maps along the Alaskan coast. In accordance with 50 CFR 18.172(b)(1) and (b)(2), LOA holders must report all observed or suspected polar bear dens to us prior to the initiation of activities. We use this information to determine the appropriate terms and conditions in an individual LOA in order to minimize potential impacts and disturbance to polar bears.

Holders of an LOA seeking to carry out onshore activities during the denning season (November-April) must conduct one to three separate surveys for occupied polar bear dens in all denning habitat within 1.6 km (1 mi) of proposed activities using aerial infrared (AIR) imagery. Project areas located in high denning density zones must be AIR surveyed at least three times, project areas in moderate denning density zones must be AIR surveyed at least twice, and anywhere outside of either the moderate or high denning density zones must be AIR surveys at least once. When either one or two AIR surveys are needed the first survey must be flown between November 25 and December 25 and the second survey occurring between December 15 and January 15. In an area where three surveys are required, the additional survey must occur between December 5 and December 31. A minimum of 24 hours is required between completion of previous AIR survey and beginning a new AIR survey.

Flight crews will record and report environmental parameters including air temperature, dew point, wind speed and direction, cloud ceiling, and percent humidity, and a flight log will be provided to the FWS within 48 hours of the flight.

(5) Onsite Monitoring and Observation Reports —The regulations also require that each holder of an LOA submit a monitoring report indicating the nature and extent of all takes of marine mammals that occurred incidentally to the specific activity. Since the inception of incidental take authorizations for polar bears ( Ursus maritimus ), Pacific walruses (walruses) ( Odobenus rosmarus divergens ), and northern sea otters (otters) ( Enhydra lutris kenyoni ), we have required monitoring and reporting during oil and gas industry activities. The purpose of monitoring and reporting requirements is to assess the effects of industrial activities on polar bears, walruses, and otters to ensure that take is minimal to marine mammal populations, and to detect any unanticipated effects of take. The monitoring focus has been site-specific, area-specific, or population-specific. Site-specific monitoring measures animal-human encounter rates, outcomes of encounters, and trends of animal activity in the industrial areas, such as polar bear numbers, behavior, and seasonal use. Area-specific monitoring includes analyzing animal spatial and temporal use trends, sex/age composition, and risk assessment to unpredictable events, such as oil spills. Population-specific monitoring includes investigating species' life-history parameters, such as population size, recruitment, survival, physical condition, status, and mortality.

A. In-Season Monitoring (Activity Progress Reports) (50 CFR 18.172(a)(1))—Activity progress reports. Holders of an LOA must:

• Notify the FWS at least 48 hours prior to the onset of activities;

• Provide the FWS weekly progress reports of any significant changes in activities and/or locations; and

• Notify the FWS within 48 hours after ending of activities.

B. In-Season Monitoring (Polar Bear Observation Reports) (50 CFR 18.172(a)(2))—Holders of an LOA must report, within 48 hours, all observations of polar bears and potential polar bear dens, during any industry activity. Upon request, monitoring report data must be provided in a common electronic format (to be specified by the FWS). Information in the observation report must include, but is not limited to:

• Date, time, and location of observation;

• Number of bears;

• Sex and age of bears (if known);

• Observer name and contact information;

• Weather, visibility, sea state, and sea-ice conditions at the time of observation;

• Estimated closest distance of bears from personnel and facilities;

• Industry activity at time of sighting;

• Possible attractants present;

• Bear behavior;

• Description of the encounter;

• Duration of the encounter; and

• Mitigation actions taken.

(6) Notification of LOA Incident Report (50 CFR 18.172(b))—Holders of an LOA must report, as soon as possible, but within 48 hours, all LOA incidents during any industry activity. An LOA incident is any situation when specified activities exceed the authority of an LOA, when a mitigation measure was required but not enacted, or when injury or death of a marine mammal occurs. Reports must include:

• All information specified for an observation report;

• A complete detailed description of the incident; and

• Any other actions taken.

(7) Mitigation—Interaction Plan (50 CFR 18.170(a)(3) and 50 CFR 18.167(c)(4)) — All holders of an LOA must have an approved polar bear safety, awareness, and interaction plan on file with the FWS's Marine Mammals Management Office and onsite and provide polar bear awareness training to certain personnel. Interaction plans must include:

• The type of activity and where and when the activity will occur ( i.e., a summary of the plan of operation);

• A food, waste, and other “bear attractants” management plan;

• Personnel training policies, procedures, and materials;

• Site-specific polar bear interaction risk evaluation and mitigation measures;

• Polar bear avoidance and encounter procedures; and

• Polar bear observation and reporting procedures.

(8) Mitigation—3rd — Party Notifications (50 CFR 18.170(d)(1))—All applicants for an LOA must contact affected subsistence communities and hunter organizations to discuss potential conflicts caused by the activities and provide the FWS documentation of communications as described in § 18.167.

(9) Mitigation — Plan of Cooperation (50 CFR 18.170(d)(2))—When appropriate, a holder of an LOA will be required to develop and implement a FWS-approved plan of cooperation (POC). The POC must include a description of the procedures by which the holder of the LOA will work and consult with potentially affected subsistence hunters and a description of specific measures that have been or will be taken to avoid or minimize interference with subsistence hunting of polar bears and to ensure continued availability of the species for subsistence use. The FWS will review the POC to ensure that any potential adverse effects on the availability of the animals are minimized. The FWS will reject POCs if they do not provide adequate safeguards to ensure the least practicable adverse impact on the availability of polar bears for subsistence use.

(10) Community Consultation (50 CFR 18.170(d)(1))—Community consultation. Prior to receipt of an LOA, applicants must consult with potentially affected communities and appropriate subsistence user organizations to discuss potential conflicts with subsistence polar bear hunting caused by the location, timing, and methods of operations and support activities. If community concerns suggest that the activities may have an adverse impact on the subsistence uses of this species, the applicant must address conflict avoidance issues through a POC.

Title of Collection: Incidental Take of Marine Mammals During Specified Activities, 50 CFR 18.27 and 50 CFR part 18, subpart N.

OMB Control Number: 1018-New.

Form Numbers: None.

Type of Review: Revision of a currently approved collection.

Respondents/Affected Public: Individuals/households, private sector (oil and gas industry companies), State/local/Tribal governments, and Federal Government.

Respondent's Obligation: Required to obtain or retain a benefit.

Frequency of Collection: On occasion for applications; annually or on occasion for reports.

Total Estimated Annual Nonhour Burden Cost: $50,000 (associated with the polar bear den detection survey and report).

Send your written comments and suggestions on this information collection by the date indicated in DATES to OMB, with a copy to the FWS Information Collection Clearance Officer, U.S. Fish and Wildlife Service, MS: PRB/PERMA (JAO), 5275 Leesburg Pike, Falls Church, VA 22041-3803 (mail); or by email to Info_Coll@fws.gov. Please reference “1018-New/1018-BG75) in the subject line of your comments.

Executive Order 13211 requires agencies to prepare statements of energy effects when undertaking certain actions. This proposed rule provides exceptions from the MMPA's taking prohibitions for entities engaged in specified seismic exploration activities in the specified geographic region. By providing certainty regarding compliance with the MMPA, this proposed rule will have a positive effect on the seismic exploration activities. Although the proposed rule requires an applicant to take a number of actions, these actions have been undertaken by seismic exploration activities for many years as part of similar past regulations. Therefore, this proposed rule is not expected to significantly affect energy supplies, distribution, or use, and does not constitute a significant energy action. No statement of energy effects is required.

For a list of the references cited in this proposed rule, see Docket No FWS-R7-ES-2023-0086, available at https://www.regulations.gov.

For the reasons set forth in the preamble, the FWS proposes to amend part 18, subchapter B of chapter 1, title 50 of the Code of Federal Regulations as set forth below.