Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category-Deadline Extensions

Congress passed the Federal Water Pollution Control Act Amendments of 1972, also known as the Clean Water Act (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 the 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.

Furthermore, the CWA authorizes the EPA to promulgate nationally applicable pretreatment standards that restrict pollutant discharges from facilities that discharge wastewater to WOTUS indirectly through sewers flowing to publicly owned treatment works (POTWs), as outlined in CWA sections 307(b) and (c). 33 U.S.C. 1317(b)-(c). The EPA establishes national pretreatment standards for those pollutants in wastewater from indirect dischargers that may pass through, interfere with, or are otherwise incompatible with POTW operations. Pretreatment standards are designed to ensure that wastewaters from indirect industrial dischargers are subject to similar levels of treatment as those directly discharged and subject to ELGs. See CWA section 301(b), 33 U.S.C. 1311(b). In addition, the EPA has by regulation required POTWs to implement local treatment limits applicable to their industrial indirect dischargers to satisfy any local requirements. See 40 CFR 403.5.

Direct dischargers (i.e., those discharging directly to WOTUS rather than through POTWs) must comply with effluent limitations in NPDES permits. Indirect dischargers that discharge through POTWs must comply with pretreatment standards. Technology-based effluent limitations (TBELs) in NPDES permits are derived from ELGs (CWA sections 301 and 304, 33 U.S.C. 1311 and 1314) and new source performance standards (CWA section 306, 33 U.S.C. 1316) promulgated by the EPA or based on best professional judgment (BPJ) where the Agency has not promulgated an applicable effluent guideline or new source performance standard. CWA section 402(a)(1)(B), 33 U.S.C. 1342(a)(1)(B); 40 CFR 125.3(c). Additional limitations based on water quality standards are also included in the permit in certain circumstances. CWA section 301(b)(1)(C), 33 U.S.C. 1311(b)(1)(C); 40 CFR 122.44(d).

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 BOD5, 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 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 effluent guidelines that are technology-based regulations for a category of dischargers. The EPA bases these regulations on the performance of control and treatment technologies. 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).

There are several TBELs that may apply to a given discharger 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. 1. Best Practicable Control Technology Currently Available

Traditionally, the EPA defines best practicable control technology (BPT) effluent limitations based on 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 BPT effluent 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 EPA 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 impact (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). If, however, existing performance is uniformly inadequate, the EPA may establish limitations based on higher levels of control than what is currently in place in an industrial category, when based on an Agency determination that the technology is available in another category or subcategory and can be practicably applied. 2. Best Available Technology Economically Achievable

BAT represents the second level of stringency for controlling direct discharge of toxic and nonconventional pollutants, after BPT. Courts have referred to this as the CWA's “gold standard” for controlling discharges from existing sources. See, e.g., 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, non-water quality environmental impact (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 EPA 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 the EPA's consideration of non-water quality environmental impact. BP Expl. & Oil, Inc. v. EPA, 66 F.3d 784, 801-02 (6th Cir. 1995). Historically, the EPA has usually 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. 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 common industry practice. See Am. Frozen Food, 539 F.2d at 132, 140; Reynolds Metal Co. v. EPA, 760 F.2d 549, 562 (4th Cir. 1985); Cal. & Hawaiian Sugar Co. v. EPA, 553 F.2d 280, 285-88 (2nd Cir. 1977). Courts have previously endorsed this approach. Kennecott v. EPA, 780 F.2d 445, 448 (4th Cir. 1985); see also Sw. Elec. Power Co., 920 F.3d at 1031.

Section 307(b), 33 U.S.C. 1317(b), of the CWA calls for the EPA to issue pretreatment standards for discharges of pollutants to POTWs (i.e., indirect discharges). PSES are designed to prevent the discharge of pollutants that pass through, interfere with, or are otherwise incompatible with the operation of POTWs. Categorical pretreatment standards are technology-based and are analogous to BAT ELGs, and thus the EPA typically considers the same factors in promulgating PSES as it considers in promulgating BAT. See, e.g., Reynolds Metal Co., 760 F.2d at 553; Chem. Mfrs. Ass'n v. EPA, 870 F.2d 177, 244 (5th Cir. 1989). The General Pretreatment Regulations, which set forth the framework for the implementation of categorical pretreatment standards, are found at 40 CFR part 403. These regulations establish pretreatment standards that apply to all nondomestic dischargers. See 52 FR 1586 (January 14, 1987). 4. Best Professional Judgment

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-promulgated effluent guidelines are not applicable to a non-POTW discharge, or where such EPA-promulgated guidelines have been vacated by a court, the EPA has provided by regulation that such treatment requirements are established on a case-by-case basis using the permit writer's BPJ. Under the EPA's regulations, case-by-case TBELs are developed by permit writers on the theory 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) through (3).

C. 2015 Steam Electric Rule

On November 3, 2015, the EPA promulgated a rule revising the regulations for the steam electric power generating point source category at 40 CFR 423. 80 FR 67838 (2015 rule). The 2015 rule set the first Federal limitations on the levels of toxic pollutants (e.g., arsenic) and nutrients (e.g., nitrogen) that may 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 rule, regulations for the industry had last been updated in 1982 and, for the industry's wastestreams with the largest pollutant loadings, contained only limitations on TSS and oil and grease.

The 2015 rule addressed effluent limitations and standards for multiple wastestreams generated by new and existing steam electric facilities: BA transport water, CRL, FGD wastewater, flue gas mercury control wastewater, fly ash transport water, gasification wastewater, and legacy wastewater. The 2015 rule required most steam electric facilities to comply with the effluent limitations “as soon as possible” after November 1, 2018, but no later than December 31, 2023. Permitting authorities established particular applicability date(s) within that range for each plant (except for indirect discharges, which discharge to POTWs) at the time they issued the plant's NPDES permit. For plants that opted into the 2015 rule's voluntary incentives program (VIP), which gave plants the certainty of more time to meet more stringent FGD wastewater limitations, the compliance deadline was December 31, 2023. 2. Vacatur of Limitations Applicable to CRL and Legacy Wastewater

Electric utilities, environmental groups, and drinking water utilities filed seven petitions for review of the 2015 rule 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 rule: 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 PSES in the 2015 rule that apply to FGD wastewater and BA 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 particular, the court rejected the EPA's BAT limitations for each wastestream set equal to previously promulgated BPT limitations based on surface impoundments. In the case of legacy wastewater, the court held that the EPA's record did not support BAT limitations based on surface impoundments. Id. at 1015. 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.

D. 2020 Steam Electric Reconsideration Rule

On October 13, 2020, the EPA promulgated the Steam Electric Reconsideration Rule, 85 FR 64650 (2020 rule). The 2020 rule revised requirements applicable to existing sources for FGD wastewater and BA transport water. Specifically, the 2020 rule made four changes to the 2015 rule. First, the rule changed the technology basis for control of FGD wastewater and BA transport water. For FGD wastewater, the technology basis was changed from chemical precipitation plus high hydraulic residence time biological reduction to chemical precipitation plus low hydraulic residence time biological reduction.

This change in the technology basis resulted in less stringent selenium limitations and more stringent mercury and nitrogen limitations. For BA transport water, the technology basis was changed from dry-handling or closed-loop systems to high-recycle-rate systems, allowing for a site- specific purge not to exceed 10 percent of the BA transport system's volume. Second, the 2020 rule revised the technology basis for the VIP for FGD wastewater from vapor compression evaporation to chemical precipitation plus membrane filtration. Third, the 2020 rule created three new subcategories for high-flow facilities, low-utilization electric generating units (EGUs), and EGUs permanently ceasing coal combustion by 2028. Facilities or units in these subcategories were subject to less stringent limitations: high-flow facilities were subject to FGD wastewater limitations based on chemical precipitation; low-utilization EGUs were subject to FGD wastewater limitations based on chemical precipitation and BA transport water limitations based on surface impoundments and a best management plan; and EGUs permanently ceasing coal combustion by 2028 were subject to FGD wastewater and BA transport water limitations based on surface impoundments. Finally, the 2020 rule 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. Facilities opting into the VIP were given until December 31, 2028, to meet the revised FGD wastewater limitations. 2. 2020 Rule Litigation

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 is still in abeyance.

E. 2024 Supplemental Steam Electric Rule

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 rule). This revision of the regulations at 40 CFR part 423 established a zero- discharge limitation for three wastewaters generated at steam electric power plants: FGD wastewater, BA transport water, and managed CRL. The 2024 rule also established non-zero numeric discharge limitations on mercury and arsenic on 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 (i.e., “unmanaged” CRL). These mercury and arsenic limitations also apply to a fourth wastestream called legacy wastewater, which is typically discharged from surface impoundments during the closure process, where those surface impoundments have not commenced closure under the EPA's coal combustion residuals regulations under the Resource Conservation and Recovery Act as of the effective date of the 2024 rule. The 2024 rule eliminated the 2020 rule's separate standards applicable to two subcategories of facilities or units (high-flow facilities and low-utilization EGUs), while retaining the 2020 rule's subcategory for EGUs permanently ceasing combustion of coal by 2028. The 2024 rule also established a new subcategory for EGUs permanently ceasing combustion of coal by December 2034, as well as a requirement for dischargers to post reporting and recordkeeping documentation to a publicly available website. For indirect discharges, the 2024 rule established PSES that are the same as the BAT limitations. Pretreatment standards are directly enforceable and apply no later than May 9, 2027.

In this final action, the EPA is not changing the underlying BAT bases in the 2024 rule, nor is the Agency altering the rule's annual pollutant loadings and environmental impacts; however, as the Agency has previously announced, it is considering further rulemaking to modify the 2024 rule's underlying technology bases and associated limitations or standards. Due to the postponement of these loadings and impacts, the EPA has conducted an analysis showing the changes in costs and benefits due to discounting, but given the limited scope of this current rulemaking, it has not at this time updated its other primary analyses from 2024. 2. 2024 Rule Litigation

A number of parties challenged the 2024 rule 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. On August 27, 2025, the court granted the EPA's request for an abeyance and ordered the Agency to file a motion to govern further proceedings within 30 days after publication in the Federal Register of a final deadline-extension rule. 3. Administrative Petitions for Reconsideration of the 2024 Rule

The EPA has received two petitions for reconsideration, 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 that included recommendations primarily related to CRL applicability (DCN SE11943). This petition was updated with a supplemental letter of EEI priorities on May 8, 2025, which reiterated recommendations for CRL, and which also included discussion of extending the deadlines in the 2020 and 2024 rules (DCN SE11948). With respect to the 2024 rule's permanent cessation of coal combustion by 2034 subcategory, EEI recommended extending the NOPP deadline from December 31, 2025, to December 31, 2029, to provide more time to address load growth challenges. EEI also recommended extending the zero-discharge compliance dates of the 2024 rule. Finally, EEI recommended that the EPA extend the generally applicable 2020 rule deadlines for BA transport water and FGD wastewater to at least December 2027 to allow units to transfer out of the 2028 cessation of coal combustion subcategory and, instead, install technologies to meet the 2020 rule's requirements, and thereby continue to operate and produce power past 2025.

UWAG is a voluntary nonprofit group composed 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 EPA a petition for rulemaking to reconsider and repeal the 2024 rule, as well as administratively stay the 2024 rule while it is in litigation (DCN SE11944). The petition requested several reviews of the determinations underlying the 2024 rule, including the 2024 rule's determination that zero-discharge technology is available and economically achievable to treat FGD wastewater and CRL. The UWAG petition correspondingly advocated for postponement of all compliance dates in the 2024 rule.

In addition to these two petitions, on April 25, 2025, the EPA received a request from America's Power, a national trade association representing U.S. steam electric power plants and their supply chains. The letter noted an estimated 29 coal-fired EGUs have committed to retire by 2028 and, in light of emerging challenges to grid reliability, urged the EPA to release these units from their retirement commitments as quickly as possible (DCN SE11903, SE11903A1). America's Power also made recommendations for revisions to the 2020 and 2024 rules.

While the EPA was aware of the general subjects raised in these petitions when finalizing the 2024 rule, as discussed below, load growth and power demands are much higher than predicted just a year and a half ago, and reliability and resource adequacy concerns have only intensified. Forecasts not available at the time of the 2024 rule, and certainly not available for the 2020 rule, warrant additional consideration with respect to the various deadlines discussed in section VII of this preamble. These factors and new information have been evidenced and recognized through numerous reports from and actions by the Federal Energy Regulatory Commission (FERC), the North American Electric Reliability Corporation (NERC), grid operators, grid reliability experts, the power industry, utility groups, and regulatory agencies, as described in greater detail in section V of this preamble. 4. NOPP Submission Extension Requests

Stakeholders, including grid operators, grid reliability experts, trade associations, and utilities, have raised concerns that a significant number of facilities need more time to understand how their operations fit within a changing landscape of local and regional demand that is untethered from rapidly approaching compliance timelines crafted under different demand assumptions used in the 2024 rule. This includes, among other decisions, whether to avail themselves of the compliance pathway for EGUs seeking to retire or convert to alternative fuel sources by December 31, 2034, by the current NOPP submission deadline of December 31, 2025.

Under these circumstances, the 2024 rule's December 2025 NOPP submission deadline conflicts with the Administration's priorities of ensuring reliable and secure domestic sources of energy to meet demand, as outlined in the Executive Orders section below.

Upon taking office, President Trump issued key executive orders to unleash America's affordable and reliable energy and natural resources, including to support the ongoing adoption and development of cutting- edge technologies. These executive orders took steps to encourage the increase of coal generation to expand domestic energy and avoid shutting down steam electric power plants, which could place the electricity grid at risk, to the extent permitted by law. In accordance with these orders, the EPA has reviewed the relevant issues and information referenced previously relating to the burden of existing compliance deadlines and other issues as part of this rulemaking.

Executive Order 14156, Declaring a National Energy Emergency, invokes emergency authorities to accelerate domestic fossil fuel production and infrastructure expansion, citing energy reliability, affordability, and national security concerns. 90 FR 8433 (January 29, 2025).

Executive Order 14154, Unleashing American Energy, directs Federal agencies to review and remove, as appropriate and to the extent permitted by law, regulatory roadblocks to energy development within the U.S., including by streamlining permitting processes and reconsidering previous mandates related to climate and renewable energy. 90 FR 8353 (January 29, 2025). It also directs agencies to review and revise, as appropriate and to the extent permitted by law, existing regulations to identify those that impose undue burdens on development or use of domestic energy resources. Id.

Executive Order 14261, Reinvigorating America's Beautiful Clean Coal Industry and Amending Executive Order 14241, affirms that clean coal resources will be critical to meeting the rise in electricity demand due to the resurgence of domestic manufacturing and the construction of artificial intelligence (AI) data processing centers, and encourages the utilization of coal to meet growing domestic energy demands while ensuring Federal policy does not discriminate against coal production or coal-fired electricity generation. 90 FR 15517 (April 8, 2025).

Executive Order 14179, Removing Barriers to American Leadership in Artificial Intelligence, seeks to ensure the rapid pace of U.S. adoption and development necessary to maintain American dominance and global leadership in AI. 90 FR 8741 (January 31, 2025).

The CWA requires the EPA, in developing effluent limitations guidelines and pretreatment standards, to consider a number of different factors. 33 U.S.C. 1314(b)(2)(B). The EPA has considerable discretion in evaluating these relevant factors and determining the weight given to each in reaching its ultimate BAT determination. Texas Oil & Gas Ass'n v. EPA, 161 F.3d 923, 928 (5th Cir. 1998). Likewise, the EPA has significant discretion in weighing the statutory factors to re-evaluate the policy arguments supporting the 2024 rule. Clean Water Action v. U.S. EPA, 936 F.3d 308, 315 (5th Cir. 2019) (quoting Nat'l Ass'n of Home Builders v. EPA, 682 F.3d 1032, 1038, 401 U.S. App. DC 227 (D.C. Cir. 2012)) (stating that “a reevaluation of which policy would be better in light of the facts” is the “kind of reevaluation [that] is well within an agency's discretion”). As described in section IV of this preamble, two factors the EPA considers when setting limitations based on BAT are non-water quality environmental impact, which expressly includes “energy requirements,” as well as “such other factors as the Administrator deems appropriate.” 33 U.S.C. 1314(b)(2)(B). Most notable with this industry is the impact of environmental regulations, including the steam electric ELGs, on the U.S. electricity grid. Since the promulgation of the 2024 rule, Federal agencies, States, grid operators, and grid reliability experts have identified an impending energy crisis resulting from increased load and the premature retirement of critical steam electric and other baseload power plants. NERC has consistently warned of resource adequacy and reliability shortfalls that

could occur if coal-fleet retirements occurred faster than the system could respond by constructing replacement baseload power (DCN SE11931). This is consistent with previous testimony that the EPA was aware of as of the 2024 rule.\1\

\1\ On May 4, 2023, bipartisan commissioners of FERC testified before the Senate Energy and Natural Resources Committee about the very real crisis facing the nation's grid. Commissioners warned of a “looming reliability crisis in our electricity markets,” “a very catastrophic situation in terms of reliability,” and “unprecedented challenges to the reliability of our nation's electric system” (DCN SE11932).

Since the promulgation of the 2024 rule in May of 2024, the EPA has become aware of new information and data demonstrating the existence of an energy crisis. Much of the information relied upon by the EPA during the 2024 rulemaking process proved to underestimate energy supply and demand projections, while more recent information and data points to an impending, extraordinary spike in energy demand that cannot currently be satisfied. For example, on October 16, 2024, FERC held a Commissioner-led Reliability Technical Conference to discuss policy issues related to the reliability and security of the North American bulk power system (BPS). Commissioners and witnesses expressed serious concerns about the anticipated retirement of existing generating resources, the addition of significant volumes of variable energy resources, and rapid anticipated electric load growth (DCN SE11933).

More recently, on June 4 and 5, 2025, FERC held another Commissioner-led Technical Conference titled “Meeting the Challenge of Resource Adequacy in Regional Transmission Organization and Independent System Operator Regions.” The technical conference addressed how resource retirements, load growth, and the changing resource mix have contributed to resource adequacy challenges across the nation. NERC testified that “growth projections of electric demand have reached heights unseen in decades, disrupting resource adequacy plans across North America” (DCN SE11950).

Other Federal agencies have also confirmed, and taken action to address, the energy crisis. For example, the Department of Energy (DOE) recently issued an emergency order to delay the closure of Consumers Energy's 1,560-megawatt (MW) J.H. Campbell steam electric power plant in West Olive, Michigan, citing urgent reliability concerns for the Midcontinent Independent System Operator (MISO) grid, as the Midwest braced for peak summer electricity demand (DCN SE11953). The three-unit steam electric 1,560 MW J.H. Campbell plant, built between 1962 and 1980, was slated to go “cold and dark” by June 2025 as part of Consumers Energy's transition to renewables. In the October 27 revision of the 2025 Final E.O. report, the DOE concluded the retirement of firm power capacity such as coal-fired EGUs is exacerbating the resource adequacy problem, as this capacity is not being replaced on a one-to- one basis. One of the key takeaways in the report is, “The status quo of more generation retirements and less dependable replacement generation is neither consistent with winning the AI race and ensuring affordable energy for all Americans, nor with continued grid reliability (ensuring `resource adequacy')” (DCN SE11976). The DOE also recently issued an emergency order under section 202(c) of the Federal Power Act directing PJM Interconnection (PJM),\2\ in coordination with Constellation Energy, to operate specified generation units at the Eddystone, Pennsylvania, Generation Station past their planned retirement. The order follows recent statements from PJM warning that its system faces a “growing resource adequacy concern” due to load growth, the retirement of dispatchable resources, and other factors (DCN SE11922). There are over a dozen such emergency orders issued by the DOE in the past six months alone (DCN SE11999). In May 2025, FERC also approved a reliability must-run contract between PJM and Talen Energy to keep the Brandon Shores two-unit, 1,280 MW coal- fired power plant in Anne Arundel County, Maryland, online past its anticipated retirement date to ensure reliability (DCN SE11961).

\2\ PJM Interconnection is the regional transmission organization that manages all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.

Public utilities at the state level are taking similar actions to rapidly change planning activities in response to the energy crisis. In its 2022 integrated resource plan \3\ (IRP) final order, Southern Company subsidiary Georgia Power had slated Plant Bowen for retirement by 2027. More recently, Georgia Power announced plans to extend the life of several existing coal- and natural gas-fired power plants into the late 2030s, including proposals to extend operations at the 3.2- gigawatt (GW) Plant Bowen--one of the world's largest coal plants--from a previously published 2027 retirement date to the end of 2038 according to their January 2025 IRP (DCN SE12076). Between the filing of Georgia Power's 2025 IRP and its Budget 2026 Load and Energy Forecast, the total pipeline of large-load projects through the 2030s has more than doubled, from 22.8 GW to 51.1 GW (EPA-HQ-OW-2009-0819- 10679, pg. 4). Commenters provided additional data to support these assessments. Prior to 2024, Southern Company reported roughly flat growth in its electric service territories due to economic conditions and energy efficiency; more recently, the utility--the second largest by customer base in the U.S.--now projects average annual retail sales growth of eight percent through 2029, a significant increase from the growth forecast of approximately one percent a few years ago (DCN SE12029) (EPA-HQ-OW-2009-0819-10679, pg. 4).

\3\ An Integrated Resource Plan is an electric utility's plan to meet forecasted electricity demand over a specified future period. Most States require utilities to have IRPs with a 20-year horizon and commonly require a detailed plan for the first few years of the forecasted energy demand. An update is typically required every two or three years with less-detailed interim reports sometimes being required annually. As discussed in the 2024 rule, utilities plan and budget for plant closures as part of the normal IRP process.

According to NERC, regions across the North American BPS are positioned to meet peak demand under normal summer and winter conditions, although elevated risks of electricity supply shortfalls could persist under periods of extreme temperatures, surging demand, and resource variability as illustrated by the following example. In June 2025, a severe heat wave impacted the eastern U.S., significantly increasing energy demand beyond predictions. The National Weather Service issued extreme heat warnings of triple digit temperatures ranging from south of St. Louis to north of Boston. To put the strain on the grid in context, PJM stated that demand reached about 161,000 MWs on June 23, 2025, the highest level recorded since 2011. According to FERC, PJM had only about 10 GW remaining to spare at the period of peak load. FERC chairman Mark Christie noted that grid operators' ability to just narrowly sustain power supplies through the extreme heat and humidity without blackouts reflects significant and growing resource adequacy challenges, stating at a June 26, 2025, briefing, “We're simply not building generation fast enough, and we're not keeping generation that we need to keep” (DCN SE11949).

More broadly, this heat wave also resulted in a June 24, 2025, power outage that left more than 71,000 customers without electricity in Michigan, Pennsylvania, New York, and

Massachusetts, according to Poweroutage.us. The heat wave impacted other regions as well. On June 24, 2025, the DOE issued an emergency order to Duke Energy Carolina under Section 202(c) of the Federal Power Act to address potential grid shortfall issues in the Southeast (DCN SE11962). We Energies in Wisconsin had planned closures of its Oak Creek Units 5 and 6 in 2024 and Units 7 and 8 in 2025, but it recently announced postponement of retiring Units 7 and 8, citing tightened energy supply requirements in the Midwest power market and the need to maintain reliable service during peak-demand periods, such as those experienced during the June 2025 heatwave (DCN SE11963). In San Antonio, ERCOT deployed 400 MW of mobile generation units to help reduce the risk of energy shortages during heat waves (DCN SE11964).

NERC's mission is to ensure the reliability, resiliency, and security of the North American BPS. The BPS is made up of six regional entities \4\ that provide NERC with data, narratives, and assessments to independently evaluate long-term reliability, recognize trends, and identify emerging issues and potential risks for the upcoming 10-year period. NERC develops a long-term reliability assessment (LTRA) annually based on known system changes as of July of the current year. NERC is subject to oversight by FERC.

\4\ The six regional entities (REs) overseen by NERC that monitor and enforce reliability standards for the BPS are: Midwest Reliability Organization (MRO), Northeast Power Coordinating Council (NPCC), ReliabilityFirst (RF), SERC Reliability Corporation (SERC), Texas Reliability Entity (Texas RE), and Western Electricity Coordinating Council (WECC).

“Resource adequacy” refers to the ability of an electricity system to meet the power demand of customers at all times, even during peak usage and potential outages. In the December 2024 LTRA, NERC identified increasing resource adequacy challenges for the upcoming 10 years as demand growth surges and power generators announce retirement plans (DCN SE11905). NERC also identified a substantial number of the replacement generation resources as weather dependent and, thus, more variable and less reliable than the resources they would replace. This includes ensuring sufficient generation capacity and reserves to maintain a stable power supply. The MISO recently affirmed the importance of these resources in its 2024 Reliability Imperative report, in which it identified significant challenges associated with new, weather-dependent resources that “do not provide the same critical reliability attributes as the conventional dispatchable coal and natural gas resources that are being retired” (DCN SE11929).

Furthermore, NERC categorized six areas in the U.S. as “Elevated- Risk.” \5\ Areas categorized as Elevated-Risk meet established resource adequacy targets or requirements, but probabilistic or deterministic analysis of conditions that are plausible but more extreme than normal seasonal peaks are likely to cause shortfall in area reserves. More extreme conditions can include temperatures that result in above-normal demand levels, low resource output or availability, and/or disruption of normal electricity transfers. NERC further wrote that “the aggregate of peak electricity demand for NERC's 23 assessment areas has risen by over 10 GW--more than double the year-to-year increase that occurred between the summers of 2023 and 2024” (DCN SE11938). The 2024 LTRA identified PJM as Elevated-Risk due to resource additions not keeping up with expected generator retirements and projected demand growth. Here, winter seasons replace summer as the higher risk periods due to generator performance and fuel supply issues.

\5\ The EPA agrees with comments that, at proposal, the Agency had cited to a previous version of NERC 2024 LTRA that had erroneously listed MISO as “High Risk” due to a data mismatch error, which has been corrected in the July 11, 2025, update to the 2024 LTRA.

Since proposal, NERC has also published its seasonal Winter Reliability Assessment (DCN SE12030). This report found that six NERC regions or sub-regions have an elevated risk during extreme weather for the 2025-2026 winter season. Specifically, the report discusses that, while the share of power that coal provides continues to decrease, the ability of coal to be stockpiled for extreme winter weather allows coal to satisfy an increasingly important role that is infeasible or prohibitively costly for natural gas, a fuel that NERC describes as a “just-in-time fuel.”

PJM's 2023 study (DCN SE11847) and 2024 study (DCN SE11901) highlight several trends that increase reliability risks: the growth rate of electricity demand; retirements at risk of outpacing the construction of new resources due to a combination of factors including siting and supply-chain disruptions; and the fact that PJM's interconnection queue is composed primarily of intermittent and limited-duration resources, which need multiple MWs to reliably replace one MW of thermal generation (e.g., coal, natural gas, nuclear). The 2024 PJM report shows increased wholesale power costs of almost five percent and significant rises in capacity prices, such as 20 percent in New Jersey. The 2024 report also highlights PJM concern about load growth, particularly from data centers and electrification, as a significant driver of increased demand and capacity needs, as well as the slow pace of new generation coming online to replace retiring resources, findings further supported in recent public PJM communications (DCN SE12077).

The National Association of Regulatory Utility Commissioners (NARUC) also released Grid Reliability and U.S. Coal Fleet Attributes: Considerations for State Regulators (DCN SE12000). NARUC stresses the “. . . need for [. . .] regulations that consider grid reliability . . .” While noting that the electric grid will continue to undergo significant changes, with renewables and storage making up the vast majority of new capacity in coming years, NARUC pointed out that coal and other conventional generation have advantages in providing dispatchable power when needed, stating these plants provide “consistent, reliable power, especially during periods of high demand or low renewable generation, such as during extreme weather events.” Thus, the report echoed NERC in finding that the rapid retirement of a large number of coal plants is a “concern.”

In deregulated electricity markets, capacity auctions are used to send signals monetarily that would lead to similar planning as the IRP process. PJM capacity auctions are typically held three years in advance of the capacity delivery year and are designed to ensure sufficient generating capacity to meet electricity demand and grid reliability at lowest cost. PJM uses capacity market auctions to accept offers to provide power at lowest cost first, but recent delays in auctions due to regulatory issues and litigation have led to higher prices. This can be seen with the results of PJM's recent capacity auction for the 2026-2027 delivery year. On July 22, 2025, PJM announced that it had completed its auction and that the clearing price was the settlement cap of $329.17/MW-day, a 22 percent increase over the previous year's clearing price, which was already an increase over the $28.92/MW-day that cleared the auction two years ago. This clearance price achieved adequate capacity, including reserve margins, but cleared by only 139 MW, approximately the amount generated by a single small- to mid-sized EGU. This reflects the tightening margins between supply and demand in

the PJM service area, demonstrating that in the short term, the loss of even a single coal-fired EGU (which can often be several hundred MW capacity) could lead to resource adequacy issues (DCN SE11965 and DCN SE11966).

In addition, the 2024 PJM report states, “The demand in each scenario reflects growth from end-use electrification, electric vehicles and data centers. Recent history of this anticipated growth has proven unprecedented and dynamic. Average growth estimates for PJM's summer peak, for example, have increased by 375 percent between the 2022 and 2024 load forecasts, from 0.4 percent per year to 1.6 percent per year. This trend adds to the complexity of ensuring reliability through the energy transition” (DCN SE11901). This report identifies a drastic increase in energy demand, significantly higher than was anticipated in formulating the 2024 rule.

Finally, another important aspect of the LTRA is the interconnection queue. The LTRA reports the interconnection queue has a backlog for the huge variety of replacement sources and storage projects seeking to connect to the grid, such as the ERCOT example above. In summary, the 2024 LTRA identified “critical reliability challenges facing the industry: satisfying escalating energy growth, managing generator retirements, and accelerating resource and transmission development” (DCN SE11905).

A data center is a building or group of buildings that holds computer systems and equipment to power every day digital services. These facilities provide space, power, cooling, and security for servers and network hardware. Data centers power almost everything online, from websites to banking and video streaming. Consumers and companies worldwide depend on services that run through data centers every hour. Many industries, such as healthcare, retail, manufacturing, and government, rely on data centers for secure storage and quick access to information. The demand for cloud computing, e-commerce, streaming, AI programming, and social media makes these sites more important each year. Data centers use a large amount of electricity, making reliable and affordable power one of the most important factors to U.S. economic development and national security (DCN SE12002). Data centers and the massive power they require are critical to national security because they store and process sensitive government, military, and intelligence information, support artificial intelligence (AI) development, and manage critical digital infrastructure (DCN SE12003).

According to the DOE, from 2014 to 2016 the annual energy consumption of data centers in the U.S. remained stable at approximately 60 terawatt-hours (TWh). By 2018, this figure had increased to around 76 TWh, accounting for 1.9 percent of the country's total electricity consumption. Recent forecasts expect total power demand for data centers to be between 74 and 132 GW in 2028, corresponding to 6.7 and 12 percent of total U.S. electricity consumption. The adoption and growth of AI has been cited as a leading driver of surging data center demand in the U.S., with the technology requiring immense computing power, and several utilities are already adopting additional power resources to meet this demand (DCN SE11906). For example, Entergy Louisiana will add three highly efficient steam electric power plants to its system to meet growing power demands due to data center expansion in the state, including Meta's $10 billion data center in northeast Louisiana, which will be the largest in Meta's fleet (EPA-HQ-OW-2009-0819-10667, pg. 8). In February 2025, American Electric Power's Indiana & Michigan Power Company reached a joint settlement with the Indiana Office of Utility Customer Counselor, Amazon Web Services (AWS), Microsoft, Google, and the Data Center Coalition to establish a process for new, large-scale industrial customers like data centers to connect to the grid. Previously, AWS announced a $11 billion investment in a data center campus in New Carlisle, Indiana, and another $2 billion data center in Fort Wayne, Indiana, both among the largest economic development projects in the state (EPA-HQ-OW-2009-0819-10667, pg. 8). Alliant Energy has cited Google's $576 million data center investment, and Quality Technology Services' $750 million data center investment, both in Cedar Rapids, as contributing to the company's projected 30 percent increase in electric demand in its service area by 2030 (EPA-HQ-OW-2009-0819-10667, pg. 8- 9). The National Renewable Energy Center's “Data Center Infrastructure for 2025” shows transmission network and new data center demand capacity coinciding geospatially with large cities, highlighting the challenges demand growth is already placing on the grid (DCN SE11922). The EPA notes that consultants, investors, and ratings firms such as S&P and Moody's identify the U.S. technology sector as one that can initiate, develop, and complete projects relatively quickly, with new data centers operational in as little as two to three years. Meanwhile, the energy sector requires longer lead times to schedule and build infrastructure as a result of extensive planning requirements and significant capital investment.

These concerns have been confirmed by several commenters who have expressed a need for more energy load and reliability due to projected data center buildout, manufacturing growth, and population growth. South Carolina requires additional capacity due to the State's seven percent population increase from 2020 to 2024 (DCN SE12036), and $9.22 billion in economic investments announced in 2023, some of which includes the buildout of data centers (DCN SE12037 and EPA-HQ-OW-2009- 0819-10679, pg. 3). Edison Electric Institute, which represents all investor-owned electric companies in the U.S., also cited data center growth as a core reason to continue expanding energy capacity, relying on a 2024 report by the Electric Power Research Institute finding that data centers may consume more than nine percent of U.S. electricity generation annually by 2030, compared to an estimated four percent today (DCN SE12038 and EPA-HQ-OW-2009-0819-10667, pg. 7). EEI further cites the rapid buildout of data centers as a reason why “EEI members that planned to retire facilities under the 2028 [Permanent Cessation of Coal Combustion] PCCC Subcategory are finding during analyses of fleet operability and efficiency that they may need to keep plants running for additional years to meet customer demand” (EPA-HQ-OW-2009- 0819-10667, pg. 15). Natural gas and coal are forecast to meet over 40 percent of the electricity demand from data centers until at least 2030 (DCN SE11967).

Moreover, as described in the President's July 2025 strategy titled “Winning the Arms Race: America's AI Action Plan” (DCN SE11954), AI systems may pose novel national security risks in areas such as cyberattacks and the development of chemical, biological, radiological, nuclear, or explosive weapons. Ensuring America is at the forefront of AI development is vital for national defense and homeland security. The President issued Executive Order 14179, Removing Barriers to American Leadership in Artificial Intelligence, making it possible for America to retain global leadership in AI. 90 FR 8741 (January 31, 2025). Executive Order 14179 will ensure that AI adoption and

development is progressing at the rapid pace necessary to maintain American dominance, which would further expand the need for upgrades to the U.S. electrical grid to support data centers as identified in the AI Action Plan (DCN SE11954).

In addition to the documented increase in energy demand, another issue facing the power sector, in addition to compliance with the 2024 rule's deadlines, is challenges in obtaining equipment to maintain and upgrade steam electric power plants. This includes the ready supply of key components of control technologies (e.g., microchips) that are experiencing increased global demand from other industries and, consequently, becoming another rate-limiting factor for the installation of new wastewater treatment technologies necessary to comply with wastewater limits. For example, Southern Company's public comment detailed delays from two vendors that might add 16 weeks or more to its project schedule (EPA-HQ-OW-2009-0819-10705). To support this comment, Southern Company provided a memorandum from WesTech (EPA- HQ-OW-2009-0819-10705, Attachment B) detailing a number of long lead time components for wastewater technologies including the following:

Pumps, compressors, and blowers have lead times of 28 to 40 weeks due to global vendor capacity constraints.

Pressure vessels and heat exchangers have fabrication lead times that now extend beyond 30 weeks, influenced by material availability and shop backlogs.

Electrical and control systems require extended delivery times of 40-plus weeks in some instances due to semiconductor supply shortages.

Structural steel and specialty alloys are impacted by raw material and fabrication delays, resulting in delivery windows ranging from 26 to 32 weeks.

Some specialized valves and actuators are quoted at 28 or more weeks.

Critical instrumentation, including transmitters and analyzers, is averaging 30 weeks due to supply chain dependencies in electronics manufacturing.

The power industry is also experiencing a significant turbine backlog, primarily for natural gas turbines, leading to a further reliance on existing steam electric power plants. A combination of factors, including increasing electricity demand, particularly from data centers, ongoing natural gas plant development using combustion turbines, and airline industry manufacturing, has led to a substantial increase in orders for gas turbines. Three major original equipment manufacturers--GE Vernova, Siemens Energy, and Mitsubishi Power--have reported backlogs stretching into 2029 and beyond. The Electric Power Research Institute reports a five-year-plus wait for new turbine installations (DCN SE11930).

Critical grid components, like transformers, are also facing longer lead times, further impacting project timelines (DCN SE11968). According to the U.S. Department of Commerce, the average U.S. electricity grid transformer is 38 years old, fast approaching the 40- year life expectancy of a transformer. The National Renewable Energy Laboratory notes utilities needing to add or replace transformers are currently facing high prices and long wait times due to supply-chain shortages (DCN SE11969). The National Infrastructure Advisory Council reports Hitachi has a waitlist of two to four years for transformers, and supply issues and uncertainty continue to affect development with lead times for transformers averaging 120 weeks and large transformer lead times averaging 80 to 210 weeks, with at least one other U.S. company having a backlog of five years (DCN SE11968). The list of U.S. infrastructure that depends on transformers includes new housing developments, a growing electric vehicle charging station market, and renewable energy projects. For instance, in Texas, companies planned to build 108 new gas-fired power plants and 17 expansions in the next few years to power AI and other heavy industries. In just one example, however, the developer Engie withdrew from two projects in Texas in February 2025 citing “equipment procurement constraints” (DCN SE11951). With the high uncertainty surrounding resource adequacy over the next decade, the need to maintain baseload capacity from existing steam electric power plants will remain for the foreseeable future.

Demand for all major fuels and energy-related technologies jumped in 2024 worldwide, and coal remains a crucial fuel source in addressing potential demand spikes in several countries besides the U.S., notably in China, in India, and across much of Southeast Asia. A May 2025 International Energy Agency report stated that peak demand is slated to grow even faster than overall power demand, and potentially 80 percent faster in emerging markets and developing economies by 2035 (DCN SE11915). These findings highlight that supply-chain issues are increasing globally (DCN SE11977) and will likely continue to increase as the demand and the competition for components escalates across the world.

Several commenters provided their own examples of how projected energy demand increases have impacted facility retirement dates and additional data to suggest that unprecedented demand is driving policy changes that support the extension of the 2024 rule's deadlines. Talen, for example, has determined that a 2028 planned retirement of two of its facilities--Keystone Generating Station and Conemaugh Generating Station, both in Pennsylvania--is no longer feasible (EPA-HQ-OW-2009- 0819-10695, pg. 7).

In early 2025, Santee Cooper, a public power utility in South Carolina, reassessed its 2024 IRP adopted in May

2024 and updated it. This update reflects “significant uncertainties on whether Santee Cooper will be able to retire its Winyah Generating Station by its targeted retirement date of 2033.” The confluence of a number of factors \6\ has made it “impossible” for Santee Cooper to “establish a firm retirement date for the four Winyah units, which would be reflected in a federally enforceable commitment through the NOPP election by the end of [2025]” (EPA-HQ-OW-2009-0819-10683, pg. 4).

\6\ Specific factors cited as challenges to establishing retirement dates included: unanticipated increases in electricity demand due to the explosive growth of energy-intensive manufacturing and data centers, electrification of the transportation sector, and substantial challenges and timing uncertainties in the development of new replacement generation and other related energy infrastructure, including the permitting and buildout of new natural gas combustion turbines, natural gas pipelines, transmission lines, and large transformers.

Buckeye Power's Cardinal Plant submitted a NOPP intending to retire its unit 3, which was consistent with demand forecasts when the NOPP was submitted in 2021; however, recent PJM capacity market results resulted in discussions between Buckeye Power and PJM to continue operating this unit under a reliability must-run (RMR) order through May 2029 or longer. Ultimately, Cardinal was able to continue operating this unit in light of projected increases without an RMR (DCN SE12008, pg. 125). Similar discussions were had between PJM and KeyCon's Conemaugh Plant, which had filed a NOPP to retire by 2028, but in light of recent auctions and clearing prices soaring to their highest level in decades, KeyCon was able to procure treatment technologies to meet limitations and remain in compliance for coming years (DCN SE12008, pg. 125-26).

Southwestern Electric Power (SWEPCO) originally submitted a NOPP for its Welsh Plant to cease coal combustion by 2028. However, as demand has evolved, to be compliant with its minimum Southwest Power Pool (SPP) capacity obligations, Welsh would need to convert to an alternative fuel source or add new generation before ceasing coal combustion in 2028. If SWEPCO did not meet its capacity obligations, SPP could issue deficiency charges (EPA-HQ-OW-2009-0819-10671, p. 16).

Southern Company submitted NOPPs for 2028 retirement for 12 units. While two units retired, two were denied by the public service commission for retirement, others have repowered or plan to repower, and the rest of the units transferred applicability to continue operating in response to load growth (EPA-HQ-OW-2009-0819-10705, p. 26). The Georgia Public Service Commission initially postponed a decision on the retirement of Plant Bowen in 2022, and in 2025 supports continued operation to the mid-2030s due to increasing load growth in Georgia (EPA-HQ-OW-2009-0819-10705, p. 23).

In addition, several power companies (e.g., Mill Creek Generating Station, E.W. Brown Generating Station, CPS Energy's Spruce Unit 1, PacifiCorp's David Johnston Plant, KeyCon's Keystone Generating Station) expressed concern regarding EGU retirements in light of increasing power demand. Some suggested an extension would allow them to delay these retirements, in part, to meet surging energy demand. PPL Corporation and its two subsidiaries, Louisville Gas and Electric and Kentucky Utilities Company, provided comments indicating that the 2024 rule would likely “compel premature retirement of a significant number of our coal generating fleet” despite the company's projected “very high levels of increased demand in the near term.” Furthermore, PPL projected that annual energy requirements will climb sharply from 32,808 GWh in 2025 to 48,129 GWh in 2032--an increase of almost 47 percent. Peak summer and winter demand increases of about 1,800 MW for the same period are also projected (EPA-HQ-OW-2009-0819-10674, pg. 5). The EEI noted in their comments that several members that had planned to retire units before the 2028 cessation deadline may need to keep these units online for additional years to meet customer demand (EPA- HQ-OW-2009-0819-10667, p.15).

The EPA is extending seven deadlines in the 2024 rule, updating the 2024 rule's transfer provisions to allow facilities to switch between compliance alternatives, and creating authority for limited additional timing flexibility for both the 2020 and 2024 rule deadlines, based on site-specific factors. First, the EPA is extending the date for existing steam electric power plants to submit a NOPP for the permanent cessation of coal combustion by 2034 subcategory. In addition to this deadline extension, the EPA is expanding the transfer flexibilities in 40 CFR 423.13(o) by including a new transfer provision for facilities wishing to switch between requirements for zero discharge and requirements applicable to the permanent cessation of coal combustion by 2034 subcategory. Second, the EPA is extending the latest compliance dates for zero-discharge limitations applicable to discharges of FGD wastewater, BA transport water, and CRL. The third set of deadline extensions apply to standards for the same wastewaters from indirect dischargers. Specifically, the EPA is promulgating a set of tiered standards for indirect dischargers that would provide flexibility to achieve zero discharge on the same timelines as direct dischargers. Fourth, the EPA is providing authority for additional site-specific extensions of paperwork submission dates and deadlines in the 2020 or 2024 rules when necessary to address unexpected circumstances.

The EPA's proposed rule solicited comment on each of the provisions described above, including comments on alternatives and comments providing information and data supporting the proposed deadline extensions and related provisions (90 FR 47703 to 47707). Following the thorough engagement process, which included public webinars, tribal consultations, and a careful consideration of all comments and information submitted, the EPA has determined that the final extensions and related modifications are supported by the full record before the Agency. As discussed further below in this section, the EPA finds that none of the alternatives presented by commenters were supported by new information or otherwise warranted modification to the date extensions or other provisions outlined in the proposal. The EPA also finds that suggestions not to move forward with finalizing any of the deadline extensions or related modifications were not warranted in light of the record and statutory factors, as discussed more fully in later parts of this section. As such, and for the reasons described herein, the EPA is finalizing the proposed extensions and modifications. This rule will, in part, provide flexibility to a critical industry in advance of imminent deadlines, which could otherwise force utilities to make premature and irrevocable decisions to begin the process of decommissioning without full consideration of rapidly evolving regional resource adequacy needs.

As part of the proposal, the EPA also requested data to better understand whether and the extent to which it would be appropriate for the EPA to undertake more comprehensive reconsideration of the 2024 rule, in part, to ensure grid reliability beyond this rule's most immediate extensions and related modifications. The decisions described below reflect the EPA's commitment to maintaining a balanced

approach that supports both environmental goals and operational feasibility for an industry on which Americans rely. See the EPA's response to comments document (DCN SE12008) for a more detailed discussion of the Agency's finding with regards to public input on the proposed regulation.

Following publication of the 2024 rule, stakeholders, including trade associations and utilities, have raised concerns that certain facilities need more time to decide whether to avail themselves of the 2024 rule's compliance pathway for EGUs seeking to retire or convert to alternative fuel sources by December 31, 2034. Based on recent forecasts projecting a surge in energy demand, the EPA finds that the 2024 rule's December 2025 deadline may unreasonably force facilities to decide to retire when they could still be needed to meet local or regional resource adequacy and grid reliability needs. Such premature retirements could result in unforeseen impacts on the ability of the U.S. to ensure that energy remains abundant, affordable, and reliable for Americans. This would be inconsistent with the Administration's prioritization of ensuring a reliable and secure domestic source of energy to meet those demands. The EPA is committed to ensuring these steam electric power plants have the option to remain in operation to increase the Nation's energy supply, meet surging demand (e.g., from data centers), support regional grid reliability, and grow domestic manufacturing, jobs, and wages, while simultaneously fulfilling its statutory duties and advancing the Clean Water Act's goal of eliminating discharges to the Nation's waters.

Since promulgation of the 2024 rule, the EPA has continued to discuss electric reliability issues with the DOE, NERC, and other stakeholders under the framework established in the Joint Memorandum on Interagency Communication and Consultation on Electric Reliability (EPA-DOE MOU) (DCN SE11904). At a recent EPA-DOE MOU meeting, NERC presented findings from its LTRA (DCN SE11905). In the 2024 LTRA, NERC found that electric reliability will face unanticipated challenges in the coming decade due to “surging demand growth” at the same time many generators are anticipating retiring, decisions that are being forced, in part, by the adoption of a regulatory regime that was informed by significantly lower demand forecasts. One key aspect identified in the 2024 LTRA is the surging demand growth needs of data centers. In its 2024 U.S. Data Center Energy Usage Report, the DOE found that “U.S. data center energy use has continued to grow at an increasing rate . . .” (DCN SE11906). The EPA has also received additional reports indicating that surging demand will introduce resource adequacy issues to a greater extent than the Agency anticipated during the 2024 rule proceedings (see section V).

As previously explained, in the 2024 rule, the EPA established a subcategory for EGUs permanently ceasing coal combustion by December 31, 2034. For these EGUs, less stringent limitations and standards apply to discharges of pollutants. These less stringent limitations and standards are the same as the limitations and standards previously applicable under the 2020 rule. As there were no nationally applicable limitations and standards for CRL prior to 2024, the subcategory left in place the requirement for permitting authorities to develop case-by- case TBELs using their BPJ, and it established mercury and arsenic limitations based on chemical precipitation after the retirement of the plant. In order to participate in this subcategory, facilities had to submit a NOPP to their permitting authority or control authority by December 31, 2025, and subsequently submit annual progress reports on the steps taken to achieve permanent cessation of coal combustion. The NOPP notifies the permitting authority or control authority of the plant's intent to opt into the 2024 rule's subcategory for sources that anticipate closure or repowering.

At the time of the 2024 rule, the EPA estimated there were “around 50” EGUs whose retirement dates had been announced between 2030 and 2034. While the flexibilities in the new permanent cessation of coal combustion subcategory were also applicable to retirements prior to 2030 (especially with regard to CRL), these post-2030 retirements would have been subject to the full suite of zero-discharge limitations but for the subcategory. Utilities and trade associations have extensively communicated to the EPA that facilities need additional time to decide about ceasing coal combustion in light of surging electricity demand, especially in areas where data centers and manufacturing facilities may be constructed in the near future. Several public comments further confirmed this understanding. For example, Santee Cooper discussed changes in its South Carolina service area that left the utility uncertain as to whether it could retire its Winyah facility by 2033 (EPA-HQ-OW-2009-0819-10683).

The EPA received many comments in support of, and in opposition to, the extension of the NOPP submission date extension. Comments in support of the extension pointed to many of the same considerations discussed by the EPA in the proposal. Comments opposing the NOPP extension pointed to many of the same concerns certain commenters had with the deadline extensions as a whole (i.e., that the EPA did not sufficiently justify how concerns with energy reliability or affordability, as well as supply-chain issues, warrant any regulatory changes).

The EPA disagrees with comments arguing that the record does not support a NOPP submission date extension and agrees with those commenters supporting the proposed NOPP submission date extension to December 31, 2031. Providing for NOPP submission as late as 2031 allows utilities to evaluate their most recent IRP or three-year capacity market auction result before committing to this pathway, and the new submission deadline does not reflect when all facilities will actually submit their NOPP to receive subcategorized limitations in their permit.

In addition, the EPA disagrees with comments characterizing the NOPP submission date as a substantive regulatory provision in and of itself, whether those comments supported or opposed the extension of that date. The primary function of the NOPP is to inform the permitting authority that the discharger will seek the less stringent subcategorized limitations applicable to EGUs planning to permanently cease coal combustion. In this way, it can help the permitting authority to better understand and prepare the resources needed for permitting these particular facilities. However, beyond conveying this intent to the permitting authority, the NOPP serves no other purpose for regulated utilities or permitting authorities. Regardless of the timing of the NOPP submission, and even if the EPA were to eliminate the requirement to file a NOPP altogether, the limitations of the subcategory and corresponding substantive deadlines would still apply as they did prior to this final deadline-extension rule.

With respect to the suggestion that issuing a DFR extending the NOPP date demonstrates that the EPA pre-judged the outcome of this rulemaking, the Agency disagrees. As the EPA stated above and in the proposal, allowing for NOPP submission as late as 2031 lets utilities evaluate their most recent IRP or three-year capacity market auction result before committing to this compliance pathway. While the EPA

could have issued a DFR with an earlier submission date that did not exceed the zero-discharge compliance dates, this would have resulted in the Agency needing to take a second action, shortly after the first, to extend the NOPP submission date once again, even after the DFR went into effect.

The rationale for the subcategory for the permanent cessation of coal combustion by 2034 was set forth in the 2024 rule and, as described in that rule, is based on the statutory factors in CWA sections 301 and 304. The NOPP provides the mechanism for facilities to make use of that subcategory, and thus the date for the NOPP submission is authorized under CWA section 501(a), which allows the Administrator to prescribe such regulations as are necessary to carry out his functions, including establishment of ELGs, pursuant to sections 301 and 304 of the CWA. As such, the EPA is extending the NOPP date in 40 CFR 423.19(h) from December 31, 2025, to December 31, 2031. The new December 31, 2031, NOPP submission date is three years prior to the permanent cessation of coal combustion date and, thus, would allow for the most accurate three-year capacity auctions in deregulated regions (e.g., PJM) or the more typical two- to three-year IRP cycle to conclude prior to a plant opting into the subcategory with a NOPP. See the response to comments document (DCN SE12008) for further discussion of EPA findings related to the NOPP extension.

The EPA is establishing a set of new transfer provisions in 40 CFR 423.13(o) to enhance flexibility to choose among compliance alternatives. As described in the 2020 rule, even where facilities have provided a NOPP and publicly announced retirement or repowering plans, actually ceasing coal combustion may “require local or state regulatory approval prior to reducing its utilization or planning to retire . . .” 85 FR at 64709. Such procedural steps continue to exist, and in light of energy demand concerns and commitments, they may not be ultimately fulfilled. Thus, a plant fully intending to retire steam electric power generation under a previous announcement could be subject to unanticipated demand growth or other circumstances that lead a regulatory authority to reject the retirement decision. In such cases, it is reasonable and consistent with the statutory and regulatory framework to permit a plant to transfer back into a compliance pathway that applies the generally applicable zero-discharge limitations. Similarly, it is possible that a plant intending to remain in operation may not clear a capacity auction or may be required by a State regulatory body to retire. In such cases, it would contradict the intent of the subcategory to treat these facilities differently from those that were carrying out earlier planned retirements.

The EPA did not receive adverse comments on the proposed transfer provision distinct from comments relating to the proposed compliance deadline extensions. Several commenters provided suggested edits, largely based on specific needs of a utility or a utility group. However, the EPA did not find the suggested revisions were accompanied with a sufficient underlying rationale to warrant modifying the proposal for this final rule. As such, the EPA is finalizing these provisions as proposed--allowing transfers into and out of the subcategory for EGUs permanently ceasing combustion of coal by 2034 up until the December 31, 2034, deadline--to ensure that facilities facing unexpected changes in operations are not unfairly penalized as compared to the rest of the industrial sector. See the response to comments document (DCN SE12008) for a more detailed discussion on this topic.

As originally promulgated, the 2024 rule's zero-discharge limitations must be met as soon as possible, but “no later than” December 31, 2029. As part of its rationale for establishing this latest date, the EPA stated that this date created “a level playing field” for facilities regardless of where they were in their five-year permit cycle. 89 FR at 40256. After considering the comments, and for the reasons discussed below, the EPA is extending the “no later than” dates for zero-discharge limitations in the 2024 rule (applicable to discharges of FGD wastewater, BA transport water, and CRL) to December 31, 2034 (i.e., one additional permit cycle).

The EPA finds that postponing the “no later than” dates is warranted for several reasons, supported by the statutory factors, found in sections 301 and 304 of the CWA, of availability, achievability, cost, non-water quality environmental impact (including energy requirements), and such other factors as the Administrator deems appropriate. Three reasons, in particular, led to the EPA's finding. First, the December 31, 2029, date for meeting the limitations no longer is “available” for all facilities under the current circumstances due to constraints in the ability to procure and install the control technologies or their component parts, including as a result of supply-chain disruptions, as well as competition for skilled labor. Second, delaying the “no later than” date is critical in allowing facilities that recently invested in technologies to meet the 2020 rule a longer period to amortize the costs of those technologies, which is expected to improve their ability to undertake additional investments towards compliance with the 2024 rule, in addition to having less impact on customer rates. Finally, postponing the “no later than” date until December 31, 2034, gives facilities the ability to transfer out of the permanent cessation of coal combustion by 2034 subcategory and still meet the applicable BAT limitations by their deadline, thereby allowing them to continue to generate electricity using coal resources as necessitated by local or regional resource adequacy and reliability needs and to mitigate an impending national energy emergency. This postponement also provides the EPA time to consider a subsequent rulemaking where it can further review new comments and data received on the costs, economic achievability, and energy impacts of the zero-discharge requirements that are subject to extended compliance deadlines in this final rule.

The EPA received a number of comments in support of, and in opposition to, the deadline extensions. One group of commenters argued that the proposed rule's legal and factual bases for the extensions were improper and fully opposed them. These commenters further insisted that the record does not support the reasons the EPA provided as justification. Specifically, these commenters disputed that there were any documented supply-chain delays demonstrating the deadline of 2029 is not achievable. These commenters stated that the EPA only provided anecdotal evidence of supply-

chain issues impacting industry compliance or that evidence presented was not “new.” Commenters also argued that the compliance date of 2029 was still technologically available using the EPA's own analysis and findings. Finally, these commenters disputed the EPA's proposed findings that there was a national energy crisis leading to resource adequacy and reliability concerns or that demand from data centers and manufacturing growth was as much as claimed. Therefore, these commenters asserted that planning timeframes did not support the need for flexibility until as late as 2034.

A second group of commenters argued that the deadline extensions would not cure the underlying legal and factual deficiencies in the 2024 rule. These comments typically also included tacit support for the extensions as a temporary fix while the EPA reconsidered the underlying regulatory provisions.

A third group of commenters supported the deadline extensions and, in some cases, recommended changes. These comments supported both the legal and factual bases for the extensions or suggested additional rationales. These comments also supported extending all the zero- discharge limitations, citing the fact that many facilities choose to develop co-treatment of wastewaters. Many of these commenters agreed that there were supply-chain issues affecting the feasibility of a 2029 compliance deadline. One commenter cited a recent six-month delay in a necessary component and overall schedule for a membrane and thermal system designed to meet the VIP limitations for FGD wastewater. Several other comments represented that these systems were not available by 2029 either due to supply-chain issues or other reasons. One of these comments provided an engineering dependency chart demonstrating that a plant in South Carolina would need until December of 2031 to complete installation of a zero-discharge system. Some commenters further suggested that competition over skilled labor meant that, while the 2029 deadlines might be achievable by some facilities, they may not be feasible industrywide.

Several commenters also agreed with the EPA that cost recovery is often spread over longer timeframes than the four years between the 2020 rule deadlines (no later than 2025) and 2024 rule deadlines (no later than 2029). In particular, some commenters pointed to examples of a 20-year bonding program that was approved by one state public utility commission. These commenters also agreed with the EPA that allowing until 2034 would provide the greatest latitude to facilities to transfer between the compliance alternatives of the 2024 rule and avoid rushed decision-making and premature retirements that could impact resource adequacy and reliability. Some commenters suggested that the EPA is warranted in extending compliance deadlines so that facilities would have sufficient time to see the results of any subsequent rulemaking before committing further resources to compliance. Some of these comments pointed to the 2017 postponement rule (82 FR 43494, September 18, 2017) as a precedent for the EPA to take this action. In light of the comments received and EPA's careful review of the record, the EPA is finalizing the zero-discharge compliance deadline extensions as proposed. The following paragraphs further explain the reasons for the EPA's decision. 1. Industry-Wide Installation of the 2024 Zero-Discharge Limitations Cannot Reasonably Be Achieved Nationwide by 2029 Due to Longer-Than- Expected Timelines and Delays in Procuring Necessary Components and Completing Installation

The first basis supporting the EPA's decision to postpone the latest compliance deadlines for the zero-discharge limitations is the longer-than-expected timelines and delays in procuring necessary components and completing installation of the relevant wastewater control technologies. With respect to the first basis for the postponement, supported by the statutory factors of technological availability and “other factors” (here, supply-chain risks), the EPA concludes that the record clearly demonstrates that at least some extension is warranted, as discussed further in this section. And the EPA also concludes that the record supports an extension until 2034 for the latest deadline, for the reasons also discussed below.

In feedback on the proposed rule, electric utilities and trade associations provided information calling into question the ability of plants to meet the 2024 rule zero-discharge requirements on the timeframes set forth in that rule. In particular, some commenters offered new information with timeframes for specific steps in the implementation of zero-discharge technologies that could result in exceedance of the “no later than” December 31, 2029, compliance dates (e.g., see Southern Company Comments--EPA-HQ-OW-2009-0819-10705), and Santee Cooper submitted a detailed engineering dependency chart demonstrating that it cannot comply with the 2024 rule's requirements for FGD wastewater prior to December 2031 (EPA-HQ-OW-2009-0819-10769). After considering this new information, it is apparent that at least some facilities will need longer timeframes than until 2029 to comply.\7\

\7\ While environmental groups correctly note that, in some circumstances, facilities may be able to request a variance, this does not eliminate the EPA's duty to establish reasonable timeframes for a national regulation, pursuant to the statutory factors prescribed by the CWA.

This assumption is bolstered by the fact that the vendor that sold the zero-discharge system employed at one plant (the NRG Parish plant) submitted comments on the proposed rule that support the EPA's finding that delayed implementation is warranted, in part, to avoid overwhelming qualified contractors.\8\ This vendor is not the only commenter to have raised such concerns. Other commenters noted that competition for skilled labor and supplies means that, while individual facilities may still be able to comply by 2029, industrywide conversion may take longer, a consideration that similarly factored into the EPA's choice of applicability timing in the 2020 rule (85 FR 64683).

\8\ While the vendor supported an extension, the vendor also suggested a staggered variant of the deadline extension wherein some facilities comply sooner and information from those facilities is shared with “higher risk” facilities to create a larger base of “operational know-how.” The EPA did not finalize this alternative approach.

In addition to the information that longer timeframes may be needed for at least some plants, supply-chain disruptions risk further delays in these timelines, which were already problematic for compliance. While the EPA agrees in part with comments that supply-chain issues are not wholly “new” concerns, the Agency has identified disruption in supply chains as an issue ever since the 2020 rule (85 FR 64683). The fact that supply-chain issues continue to linger, and that these issues continue to result in delays in the ultimate timeframes to commission wastewater treatment systems, are important aspects of the problem that the EPA should consider. Motor Vehicle Mfrs. Ass'n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983). The EPA also agrees with comments stating that the Agency has authority to consider supply-chain risks as an “other factor” that the Administrator deems appropriate, under CWA section 304(b), when determining BAT applicability, and it has done so here.

Furthermore, the nature of supply-chain risks is not static, but continues to evolve. In 2020, the EPA was primarily concerned about supply-chain

disruptions from the COVID-19 pandemic and how it impacted the timing of the technologies required to comply with the 2020 rule's generally applicable limitations (e.g., biological treatment). At that time, the EPA did not consider supply-chain risks a concern for meeting BAT limitations in the VIP, as the rule gave utilities over eight years to install the relevant technologies to meet such limitations. Stakeholders have recently identified delays in obtaining critical components for these same technologies (which can be used to achieve the 2024 rule's zero-discharge limitations), and these newly identified delays have the potential to delay existing coal-fired EGUs from complying with the 2024 rule's limitations on the timelines envisioned in that rule, as the following example shows.

Georgia Power Company's Plant Scherer has experienced delays in receiving equipment for its membrane and brine crystallization system that may delay the project timeline by up to 16 weeks. While this 16- week project delay is not expected to singlehandedly cause the facility to miss the 2028 deadline for achieving the 2020 rule's BAT limitations in the VIP, that deadline was over eight years from publication of the 2020 rule and over seven years from the facility submitting a NOPP requesting VIP limitations in its permit. In contrast, the latest zero- discharge deadlines in the 2024 rule were approximately five and a half years from publication and a mere four years from the December 31, 2025 deadline to submit a NOPP, should a facility have opted into the subcategory for the permanent cessation of coal combustion by 2034.\9\ When considering FGD wastewater and CRL,\10\ these deadlines also apply to a much larger group of facilities than the handful of facilities that opted into the 2020 rule VIP as of the October 2021 deadline. Thus, while facilities in the 2020 rule's VIP may be able to accommodate a 16-week delay due to the longer timeframe of that compliance pathway, the shorter timeframe and larger number of facilities needing to comply with the 2024 rule's zero-discharge limitations substantially raises the likelihood that at least some facilities will face delays impacting compliance.

\9\ The EPA only notes the NOPP filing deadline to the extent that facilities may not have been certain of their compliance pathway prior to this date.

\10\ BAT for BA transport water is not based on the same technologies as FGD wastewater and CRL.

Plant Scherer is also not the sole example provided by commenters. Others stated that similar supply-chain issues have impacted installation schedules for at least two other plants in the VIP while waiting for critical component parts, such as specialty alloys and rotating equipment (EPA-HQ-OW-2009-0819-10667-A1 Comment Excerpt 11; EPA-HQ-OW-2009-0819-10694-A1, Comment Excerpt 16). Another comment adds that the wait time for membrane delivery can be over two years (e.g., 28-month lead time), which would follow the sometimes equally lengthy process of designing the new wastewater treatment system for a given plant (EPA-HQ-OW-2009-0819-10679, pg. 39).\11\ These specific examples demonstrate that supply-chain delay concerns are more than just hypothetical, as some commenters have suggested.

\11\ This comment also states that lead times for SDEs are 13 months.

The challenge in weighing supply-chain risks is further supported by comments from technology vendors themselves. While one treatment technology vendor submitted a comment reaffirming its ability to deliver treatment technologies within the original 2029 compliance deadlines, this vendor relied in part on its previous experience and staffing converting BA systems to 2024 rule-compliant systems across the coal fleet. However, the technologies for FGD wastewater and CRL are not the same as those for BA conversions, and even if that experience is directly translatable, BA conversions occurred over a 10- year period from the publication of the 2015 rule to 2025, whereas the timeframe under the 2024 rule is only five and a half years.

Two other zero-discharge technology vendors submitted comments on the proposal expressly supporting the need for additional time. One vendor agreed with the EPA's proposed extension, while the other vendor recommended a staged compliance timeline rather than the “no later than” dates specified in the rule to avoid what they referred to as a “compliance cliff” (EPA-HQ-OW-2009-0819-10666-A1, Comment Excerpt Number 3). While the EPA agrees that it could be counterproductive to just push off compliance by five years for all facilities, this is not how section 423.11(t) operates. That provision requires permitting authorities to establish a date that is “as soon as possible” subject to the consideration of four factors but “no later than” the dates that the EPA is postponing in this action. Thus, if properly applied, this will result in some gradual adoption of zero-discharge technologies rather than a rush for all facilities to convert in 2034. Furthermore, a number of facilities are proceeding with these technologies under the VIP or are in the process of transferring out of the permanent cessation subcategory into the VIP, and thus they will still be installing these same technologies by 2028.

Some commenters argued that the compliance date extensions are not warranted because the 2024 rule record demonstrated that membrane, thermal, and SDE technologies could be installed in timeframes shorter than 2029 and because at least one plant (the NRG Parish plant) subsequently did just that in under two years. While the EPA acknowledges that parts of the 2024 rule record appear to support the 2024 rule's original timeframes, the Agency disagrees that the compliance deadline extensions are not warranted. The information pointed out by these commenters must be considered along with other record evidence, particularly newer information, showing longer timeframes are needed, as described above.

After carefully considering the information before it, the EPA has determined that the weight of the evidence shows that the 2024 rule BAT technologies are no longer available nationwide on the timeframes provided for in that rule and, therefore, expecting compliance by 2029 is no longer reasonable. Courts have recognized that the EPA must select a “reasonable” time by which BAT limitations are available. See Am. Frozen Food Inst., 539 F.2d at 132 (endorsing the view that, although the best available standard does not mean that the technology must be in actual routine use somewhere, it does mean that the technology “must be available at a cost and at a time which the Administrator determines to be reasonable”) (citation omitted); see also CPC Int'l, Inc. v. Train, 515 F.2d 1032, 1048 (8th Cir. 1975) (same). Thus, the EPA's next task was to determine the precise length of the extension. The EPA has decided that an extension until 2034 is reasonable because it addresses the on-the-ground realities and concerns discussed above, and extending the latest compliance deadlines one additional permit cycle will create parity wherever a plant is in its particular permit cycle. Selecting compliance dates that account for the fact that the CWA envisions issuance of NPDES permits on a 5- year schedule, 33 U.S.C. 1342(b)(1)(B), is consistent with how the EPA structured its compliance period in the 2015, 2020, and 2024 rules. The EPA further notes that it did not extend these deadlines past 2034 as

some comments suggested.\12\ Instead, any unforeseen circumstances that may be out of a facility's control and would hinder a facility's ability to comply by 2034 could, where appropriate, be sufficiently addressed by the site-specific timeline flexibilities established at 40 CFR 423.18(d), as discussed below.

\12\ As was done in the 2015, 2020, and 2024 rules, the EPA will also evaluate availability timing as part of any subsequent reconsideration.

2. An Extension of the Latest Compliance Deadlines for the 2024 Rule's Zero-Discharge Limitations Until 2034 Is Warranted Based on the Adverse Impacts on Customer Rates Resulting From the Cumulative Costs of Complying With Multiple Rules in Short Succession

The second basis supporting the EPA's decision to postpone the latest compliance deadlines for the zero-discharge limitations is the adverse impacts on customer rates, which have seen soaring increases, including the cumulative costs to utilities of complying with both the 2020 and 2024 rules in short succession. This second basis is supported by the statutory factors of “cost” and “other factors as the Administrator deems appropriate,” which in this case is electricity price impacts to residential households. The EPA disagrees with the commenter that suggests that finalizing the deadline extensions would increase residential electric customer bills in either the short run or the long run. Electricity bills are climbing rapidly and, while not all service areas have experienced the same 20 percent electricity price increase seen in New Jersey (DCN SE11952 and SE11973), many states have seen prices rise over recent years (DCN SE12031). Electricity prices had already been a problem for many Americans. In 2021, many moratoria on utility shut-offs ended with tens of billions of dollars in bills coming due “as high as $1,500 to $2,000” for some customers (DCN SE12032), and yet a recent article documented that U.S. Census Bureau data show an increase from 20 percent to 24 percent of households unable to pay their energy bills between 2021 and 2024 (DCN SE12031).

These challenges would continue to mount for utilities forced to comply with the 2024 rule under that rule's deadlines. One municipal commenter explained that, if their utility had to rush to install zero- discharge systems for BA transport water and CRL under the timeframes of the 2024 rule, their customers would face a price increase of up to 15 percent (EPA-HQ-OW-2009-0819-10691). Instead, this commenter supported the proposed deadline extensions being finalized because, in part, it would allow the municipality to “orient their budget cycles to the compliance schedule” (EPA-HQ-OW-2009-0819-10691). The EPA agrees with this commenter that longer implementation timeframes can moderate impacts to electricity consumers. Specifically, two municipalities that recently procured zero-discharge technologies to treat CRL were able to avoid price increases to existing tipping fees, in part because they were provided ample time to plan and save for these expenditures (DCN SE12033, DCN SE12034).

This consideration is more pronounced for facilities with FGD wastewater. The EPA agrees with comments stating that typical amortization periods for wastewater treatment technologies are 20 years. One comment providing a specific state approval of a 20-year cost-recovery program bears this timeframe out as normal and appropriate (EPA-HQ-OW-2009-0819-10665). The 2020 and 2024 rules discussed how facilities incur greater capital costs when amortized over fewer and fewer years. Specifically, the record demonstrated that annualized capital costs approximately double when amortization shrinks from the typical 20-year period to eight years. 84 FR 64640. In some cases, under the 2024 rule, facilities completing installation of a biological treatment system by the end of 2025 would be required to turn around and install zero-discharge systems by 2029.

In the 2024 rule, the EPA's analysis showed that these cumulative costs were economically achievable within the previously projected electricity market supply and demand; however, these supply and demand assumptions have proven inaccurate, as discussed previously.\13\ In addition to the requirement under section 304(b) of the CWA to consider “cost,” the effects of cumulative impacts are an important consideration that agencies regularly consider,\14\ and back-to-back amortization of costs incurred by some of the larger plants to meet the 2020 and 2024 rules could mean steep rises in costs to utilities. These costs are often passed on, leading to similarly steep rises in residential electricity prices, at a time where there are significant concerns related to the grid demand and reliability.\15\ While the CWA does contemplate technological advancement, in addition to the requirement to consider the “cost” of achieving effluent reduction, as mentioned, the Act also requires consideration of “such other factors as the Administrator deems appropriate.” 33 U.S.C. 1314(b)(2)(B). The EPA has historically examined potential impacts on residential electricity prices in previous iterations of the Steam Electric ELG as an “additional factor that might be appropriate when considering what level of control represents BAT” (80 FR 67856, 85 FR 64685). Providing facilities more time to amortize the costs of the previous 2020 rule helps reduce short-term price pressures on American families, as well as domestic manufacturers, and adds additional support for this action's extension of the latest deadlines for the 2024 rule's zero-discharge limitations.

\13\ The EPA expects to update any relevant portions of its cost and achievability analyses, as appropriate, in any subsequent action considering revisions to the underlying technology bases for the 2024 rule.

\14\ See, e.g., Executive Order 13563--Improving Regulation and Regulatory Review.

\15\ Again, while the EPA's 2024 rule record analyzed these electric price increases, the EPA expects to update any relevant portions of this analysis in a future rulemaking to reflect more current conditions, as appropriate.

3. An Extension of the 2024 Rule's Latest Compliance Deadline for Zero- Discharge Limitations Is Warranted To Ensure Plants Can Continue Operating To Support Grid Reliability and in Light of Legitimate Uncertainties About the Economic and Energy Impacts of the 2024 Rule

The third basis supporting the EPA's decision to postpone the latest compliance deadlines for the zero-discharge limitations is the need to ensure plants can continue operating to support grid reliability and in light of legitimate uncertainties about the economic and energy impacts of the 2024 rule. With respect to the third basis for the postponement, based on the statutory factors of economic achievability, as well as non-water quality environmental impact (including energy requirements) or “other factors” (resource adequacy and grid reliability), the EPA agrees with comments stating that there is a national energy crisis impacting resource adequacy and grid reliability. The EPA has continued to identify information supporting this conclusion, including NARUC (2025), NERC 2025-2026 Winter Reliability Assessment, and information provided in various public comments. The EPA also agrees that increasing demand from data centers, manufacturing, and other causes could exacerbate these issues in the short run. The EPA received several comments detailing population growth, manufacturing growth, and data center

projects that are leading to demand increases in several service areas. As a result of this information, the EPA disagrees with comments that appear to cherry pick information to the contrary and present that information as a justification for retaining the 2024 rule's 2029 compliance deadlines.

While these commenters list a litany of supposed errors in the EPA's rationale, their complaints sometimes contradict each other. For example, some commenters state that the EPA does not have the expertise to make judgments about reliability and resource adequacy or that the Agency should defer to states, which are given the primary oversight of reliability-related issues, whereas other commenters accuse the Agency of not conducting sufficient analysis on those issues. Some commenters even go so far as to suggest that the EPA second-guess the DOE's lawfully issued Federal Power Act section 202(c) orders.

The EPA disagrees with the premise of these comments, as they illustrate a misunderstanding that the Agency is trying to regulate the electric grid or make primary findings regarding the operations thereof. To the contrary, the EPA is merely pointing to what competent state, national, and North American electric reliability authorities have already concluded as the Agency decides how best to implement its statutory directive to establish technology-based regulations governing point source discharges under the CWA. Even taking these commenters' information as true, the EPA finds that, at most, it demonstrates that there is uncertainty as to future demand growth, resource adequacy needs, and reliability concerns. To the extent that these commenters point to information that calls out these uncertainties, the EPA agrees that the future on these difficult issues is uncertain, but that is no reason to continue with the status quo. In fact, uncertainty is commonly accounted for by reliability authorities through probabilistic assessments. For example, NERC states that it conducts its analysis of electricity shortfall risks by considering “probability-based risk assessments” (DCN SE12030).

The EPA notes that there is also uncertainty in the extent to which the 2024 rule is driving closures in the near term. Closures matter in determining the economic achievability of the rule, as well as impacts on grid reliability, which the EPA may consider as an “energy requirement” or, alternatively, an appropriate “other factor” in its BAT decision-making. The EPA disagrees with comments stating that the 2024 rule analyses demonstrate that the costs of the rule are still economically achievable and that the impacts on coal-fired plants are small. In response to the EPA's request for data to support any subsequent rulemaking, commenters have raised concerns that the Agency's data may be stale, the Agency may have underestimated costs, and these underestimated costs may have led to underestimated market impacts.\16\ Furthermore, some commenters have provided cost estimates of systems that are significantly more expensive than the EPA's estimates in 2024. Compounding these purported analytical inaccuracies, underlying inputs for electric market modeling (e.g., demand projections) have also changed significantly in just one year. These factors all result in the impacts of the 2024 rule being uncertain, despite the relatively short time that has elapsed since the 2024 rule analyses were performed.

\16\ Even if the impacts were accurately estimated, costs and impacts that the EPA found to be achievable in 2024 may no longer be, in light of the Agency's findings regarding resource adequacy and reliability.

However, it is also not reasonable for some commenters to request that the EPA update all the Agency's data and analyses prior to finalizing this deadline-extension rule, and such an update is not legally required. The EPA has always been clear that it would conduct any reconsideration in multiple phases (DCN SE12039), and in the proposed deadline-extension rule the Agency explicitly stated that it would use information received from its data request to “define the scope of this subsequent rulemaking to potentially revise the underlying technology bases for certain limitations and standards in the 2024 rule” (90 FR 47708). This is consistent with the approach taken in the 2017 postponement rule. That rule was finalized relatively quickly, and without revising the EPA's major analyses, which were only updated during the subsequent 2020 reconsideration rule (85 FR 64650), a substantial effort that took three years. The U.S. Court of Appeals for the Fifth Circuit upheld the EPA's 2017 postponement rule as a lawful follow-on rulemaking to the 2015 rule. Clean Water Action v. EPA, 936 F.3d 308, 315-16 (5th Cir. 2019). Assuming a three-year re- analysis here, the EPA would not be able to meaningfully evaluate the very data it asked for and finalize a rule until 2028. It would make no sense for the EPA to finalize a deadline-extension rule one year before the 2024 rule's latest compliances deadlines for zero-discharge limitations, as most of the costs for the rule would have been incurred and most of the construction completed. Instead, the EPA is proceeding exactly as it said it would by completing this relatively narrow and tailored first rule and then, after determining the scope of a subsequent reconsideration rulemaking, commencing the difficult work of updating all its analyses and conclusions, as appropriate. This approach is entirely consistent with case law finding that an agency “need not solve every problem before it in the same proceeding.” Mobil Oil Expl. & Producing Se. v. United Distrib. Cos., 498 U.S. 211 (1991) (citing Vt. Yankee Nuclear Power Corp. v. NRDC, Inc., 435 U.S. 519, 543-544 (1978) (agencies are free to engage in multiple rulemaking “absent constitutional constraints or extremely compelling circumstances”).

The EPA also notes that coal-fired power plants serve a unique niche in the electric grid. As discussed in NARUC (2025) and NERC 2025- 2026 Winter Reliability Assessment, these plants, unlike natural gas plants, have fuel stockpiles and can reliably provide dispatchable power during extreme weather (DCN SE12000 and DCN SE12030). These findings are consistent with the operations of the Keystone and Conemaugh plants, which total 3,400 MW of nameplate capacity and were dispatched during Winter Storm Elliot, allowing PJM to avoid a load shedding event (DCN SE12042). This illustrates the importance of maintaining a diverse fleet of generating units that includes a variety of fuel sources, a fact that the EPA cited in subcategorizing oil-fired units in the 2015 rule (80 FR 67856).

Based on the foregoing considerations, the EPA has concluded that an approach that meets the statutory directives and environmental goals of the CWA while respecting the needs for resource adequacy and reliability is warranted in the short term. In particular, by extending the latest compliance deadlines for the zero-discharge requirements in the 2024 rule to December 31, 2034, the EPA can help ensure that plants that might be planning for retirement or repowering by 2034 can more readily stay online past that date to meet the Nation's energy requirements and still be on track to meet the otherwise applicable effluent limitations. Furthermore, while the commenters paint a picture in which costs and impacts of the 2024 rule are small, interconnection queue backlogs are resolved, and new generation and storage projects are able to quickly address resource adequacy concerns, this scenario falls on one end of a spectrum of probabilistic outcomes.

Other probabilistic outcomes include those with significantly higher costs and impacts, high demand growth, delays with commissioning new generation, and impactful extreme weather events. Instead of definitively resolving these uncertainties, it is appropriate for the EPA to fulfill its statutory duties while exercising its discretion to ensure maintenance of a diverse fleet and protection against any number of worst-case scenarios, especially while it considers further actions it may take to revise the 2024 rule. 4. The Final Rule Does Not Revise the 2024 Rule's Earliest Compliance Dates, Which Have Already Passed

The EPA disagrees with public comments suggesting that these extensions would result in widespread delays in compliance. The EPA is not postponing the earliest compliance date for the 2024 rule, which has since passed and, as a result, facilities without some of the limitations described above have already begun submitting NOPPs (DCN SE12001) and installing technology to comply with zero-discharge limitations (EPA-HQ-OW-2009-0819-10666). These extensions are not intended to simply provide this industrial sector with a blanket deferral of compliance, but instead to appropriately acknowledge the rapidly changing demand on this industry and provide permitting authorities greater flexibility to react in real time to the evolving challenges on the power sector. Of note is the fact that a permitting authority is required to evaluate the same criteria in section 423.11(t) as was required in the 2024 rule when considering the “as soon as possible” date. The factors at section 423.11(t) include consideration of “Time to expeditiously plan (including to raise capital), design, procure, and install equipment to comply with the requirements of the final rule” and “Other factors as appropriate.” For these reasons, the EPA disagrees with comments suggesting that it is necessary to postpone the earliest compliance dates. Therefore, the EPA is not postponing the “as soon as possible” date. See Implementation of the Steam Electric ELGs Deadline Extension Final Rule (DCN SE12026) for detail on how these changes impact the ongoing permitting of facilities. For a more thorough discussion of the EPA's response to the public comments on the extensions of the zero-discharge limitations, see the response to comments document (DCN SE12008).

While the majority of steam electric power plants directly discharge the three wastestreams for which the EPA established zero- discharge limitations in the 2024 rule, there are still one or more indirect dischargers of each of these wastewaters. The EPA finds that the considerations discussed above in this preamble that warrant longer applicability timing for zero-discharge requirements on direct dischargers are equally applicable to indirect dischargers. Thus, the EPA is finalizing a new tiered standard for indirect dischargers that conforms with the Act and allows an indirectly discharging plant to choose to be subject to the same limitations, and on the same timeframes, as apply to existing direct dischargers.

Section 307(b)(1) of the CWA requires that pretreatment standards “shall specify a time for compliance not to exceed three years from the date of promulgation.” 33 U.S.C. 1317(b)(1). This three-year period is similar to the three years stated in sections 301(b)(2)(C), (D), and (F), which apply to BAT limitations. 33 U.S.C. 1311(b)(2)(C), (D), and (F). Section 301(b)(2)(C) states that “there shall be achieved . . . compliance with [BAT] effluent limitations . . . as expeditiously as practicable but in no case later than three years after the date such limitations are promulgated . . . and in no case later than March 31, 1989.” \17\ 33 U.S.C. 1311(b)(2)(C). The EPA reads those provisions as requiring that the Agency's original BAT limitations be met no later than three years after the date that ELGs are promulgated, with a back-end deadline of March 31, 1989. Furthermore, the Act is silent as to any required timeframe for compliance with revised effluent limitations after March 31, 1989. See Clean Water Action v. EPA, 936 F.3d 308, 316-17 (5th Cir. 2019) (“EPA's reading of the text accords the language its natural meaning: the initial BAT effluent limitations were to be complied with as expeditiously as practicable, but in no case later than three years after promulgation, with a final compliance date of March 31, 1989-- whichever came first. This reading is supported by section 1311(d), which requires the EPA periodically to review BAT limitations, including after 1989, but contains no such compliance deadline.”) (citation omitted).

\17\ CWA section 301(b)(2)(D) and section 301(F) contain similar language. 33 U.S.C. 1311(b)(2)(D) and (F).

Given that BAT limitations and PSES are intended to be analogous, as previously described, it would make sense that the three-year requirement in CWA section 307 also applies only to the EPA's initial pretreatment standards for an industry. This is supported by CWA section 307(b)(2), which includes language stating that the Administrator shall “from time to time” revise its pretreatment standards and does not include language directing compliance with revised standards under that paragraph by any particular date. In other words, it would be illogical to read into the statute a deadline for compliance with revised standards if it remains within the EPA's discretion as to when to initiate revisions to such standards. Nonetheless, even assuming that the three-year requirement applies to revisions of those standards, the EPA's pretreatment standards meet that requirement because they represent a phased-in standard that increases in stringency after three years from promulgation, in order to reflect when more stringent technologies are available, achievable, and have acceptable non-water quality environmental impact, as required by the Act.

In the first tier of the standard, indirect dischargers are required, by January 1, 2029, to meet pre-2024 rule standards for FGD wastewater, BA transport water, and CRL. These standards (which are based, respectively, on biological treatment plus chemical precipitation, high-recycle-rate systems, and the permitting authority's BPJ) are available and achievable, as supported by the record in the EPA's prior rules. In the second tier of the standard, facilities opting to file a permit application with their permitting authority to directly discharge these wastewaters are allowed to continue indirectly discharging until the compliance date determined by the permitting authority, but no later than December 31, 2034, provided they certify that they will complete the conversion to direct discharge. In the second tier of the standard for facilities that do not opt to become direct dischargers, the tiered standard changes to zero discharge by January 1, 2029. In either case, this pretreatment standard is one standard that tightens over time, and so it conforms to the requirement of the Act that pretreatment standards specify a time for compliance not to exceed three years from the date of promulgation.\18\ The EPA expects that

this approach provides equity across a range of permitted facilities regardless of their discharge circumstance--i.e., direct or indirect.

\18\ As explained more fully in its response to comments document (DCN SE12008), the EPA also does not agree with commenters that BAT limitations such as the ones promulgated in the 2024 rule and addressed in this action are subject to a requirement that they apply no later than three years after the date of promulgation.

The EPA received a number of comments in support of, and in opposition to, the tiered standard for indirect dischargers. Comments against the tiered standard included general opposition to the delay in compliance with the 2024 standard, claims that the EPA lacks a record supporting the delay, and questions regarding the Agency's legal authority to delay the 2024 pretreatment standards. The EPA disagrees with commenters that argue there is no record support for the extension, as detailed in the paragraphs above supporting the compliance date extension for the zero-discharge BAT limitations. The Agency also disagrees that the PSES compliance deadlines cannot lawfully be extended beyond three years from promulgation of the 2024 rule, for the reasons discussing EPA's statutory authority under Section 307 of the CWA, explained above.

The EPA agrees with commenters that support the tiered standard for PSES because the approach provides consistency in the compliance deadlines between requirements for indirect and direct dischargers. The tiered standard gives facilities that have infrastructure that conveys wastewater to a publicly owned treatment works adequate time to design, procure, and install new, zero-discharge technology to comply with the 2024 limitations. This approach will provide equitable regulatory treatment across permitted facilities regardless of their discharge circumstance (i.e., direct or indirect). The tiered PSES standard is appropriate because, as a general matter, the same factors that warrant longer applicability timing for zero-discharge limitations for direct dischargers (e.g., equipment delays due to supply-chain disruptions, changing energy demand forecasts) apply equally to indirect dischargers. There is no difference as a general matter between a direct discharger and indirect discharger as far as being able to procure and install the relevant zero-discharge technologies, nor is there a difference in terms of the importance of these plants to meeting regional energy demands. See the discussion above and EPA's response to comments document (DCN SE12008) regarding the rationale for the extension of the latest compliance dates for the 2024 rule BAT limitations. The tiered requirement is also consistent with the extended deadline to submit a NOPP for cessation of coal combustion by 2034. The tiered PSES gives facilities the flexibility to consider retirement decisions, especially in light of increased energy demand and resource adequacy concerns, before the deadlines for requirements based on installation of zero-discharge technology, rather than potentially forcing premature retirement.

Finally, the EPA received comments opposing the zero-discharge PSES, suggesting that indirect dischargers should continue to be able to discharge to POTWs. The EPA also received comments from utilities and industry trade associations that the zero-discharge technologies used to establish PSES and BAT limitations in the 2024 rule are not available or economically achievable and are a primary cause of coal- fired power plant retirements. As previously explained, the EPA is considering future action to revise the zero-discharge BAT limitations and PSES for the relevant wastestreams.