One GHG reduction technologies is carbon capture and sequestration (CCS), a technology that can capture and permanently store CO2 from power plants. 

In practice, exhaust gases from most combustion processes are at atmospheric pressure with relatively low concentrations of CO2. Most post-combustion capture systems use liquid solvents (most commonly amine-based) in a scrubber column to absorb the CO2 from the flue gas. This CO2-rich solvent is then regenerated by heating the solvent to release the captured CO2. The high purity CO2 is then compressed and transported, generally through pipelines, to a site for geologic sequestration.

In its proposed rulemaking, EPA said that process improvements, the availability of better solvents, and other advances have resulted in a decrease in the cost of CCS in recent years. It said the cost of CO2 capture, excluding any tax credits, from coal-fired power generation is projected to fall by 50% by 2025 compared to 2010. 

In addition, policies such as the 2022 Inflation Reduction Act (IRA) support the deployment of CCS technology and are expected to further reduce the cost of implementing CCS by extending and increasing the tax credit for CCS under Internal Revenue Code section 45Q.

EPA pointed to several examples CCS being used at power plants. These include SaskPower’s Boundary Dam Unit 3, a 110 MW lignite-fired unit in Saskatchewan, Canada, which EPA said has achieved CO2 capture rates of 90% using an amine-based post-combustion capture system retrofitted to the existing steam generating unit.

Amine-based carbon capture has also been demonstrated at AES’s Warrior Run (Cumberland, Maryland) and Shady Point (Panama, Oklahoma) coal-fired power plants.

CCS was applied to an existing combined cycle combustion turbine at the Bellingham Energy Center in south central Massachusetts. The 40 MW slipstream capture facility at Bellingham operated from 1991 to 2005 and captured 85% to 95% of the CO2 in the slipstream.

In Scotland, the proposed 900 MW Peterhead Power Station combined cycle power plant with CCS is in the planning stages and could capture 90% of its CO2 emissions.  

An 1,800 MW combined cycle unit in West Virginia is planned to use CCS and could enter service later this decade. EPA said its economic feasibility was partially credited to the expanded IRC section 45Q tax credit for sequestered CO2 provided through the IRA.

Hydrogen co-firing

EPA said that industrial combustion turbines have been burning byproduct fuels containing large percentages of hydrogen for decades. More recently, power sector combustion turbines in the have begun to co-fire hydrogen to generate electricity. 

EPA said that new utility combustion turbine models have demonstrated the ability to co-fire up to 30% hydrogen. It said developers are working toward models that will be ready to combust 100% hydrogen by 2030. It noted that several utilities already are co-firing hydrogen in test burns and some have announced plans to move to combusting 100% hydrogen in the 2035–2045 timeframe.

EPA pointed to the Los Angeles Department of Water and Power’s (LADWP) Scattergood Modernization project that includes plans to have a hydrogen-ready combustion turbine in place when the 346 MW combined cycle plant (potential for up to 830 MW) begins initial operations in 2029. LADWP foresees the plant running on 100% electrolytic hydrogen by 2035. 

In addition, LADWP also has an agreement in place to buy electricity from the Intermountain Power Agency project (IPA) in Utah. IPA is replacing an existing 1.8 GW coal- fired plant with an 840 MW combined cycle turbine that developers expect to initially co-fire 30% electrolytic hydrogen in 2025 and 100% hydrogen by 2045.

In Florida, NextEra Energy announced plans to operate 16 GW of existing natural gas-fired combustion turbines with electrolytic hydrogen as part of the utility’s Zero Carbon Blueprint to be carbon-free by 2045.

Duke Energy Corp., which operates 33 gas-fired plants across the Midwest, the Carolinas, and Florida, has outlined plans for full hydrogen capabilities throughout its future turbine fleet. EPA quoted a utility statement that said, “All natural gas units built after 2030 are assumed to be convertible to full hydrogen capability. After 2040, only peaking units that are fully hydrogen capable are assumed to be built.”

In addition to those utility announcements, several merchant generators operating in wholesale markets are also signaling their intent to ramp up hydrogen co-firing levels after initial 30% percent co-firing phases. 

The Cricket Valley Energy Center (CVEC) in New York is retrofitting its combined cycle power plant starting in 2022 as a first step toward the conversion to a 100% hydrogen fuel capable plant. 

The Long Ridge Energy Terminal in Ohio, which has co-fired a 5% hydrogen blend at its 485 MW combined cycle plant, said that its technology has the capability to transition to 100% hydrogen over time as its low-GHG fuel supply becomes available.

EPA also said that Constellation Energy also is exploring electrolytic hydrogen co-firing across its fleet. It estimated costs for blend levels in the range of 60-100% at around $100/kW for retrofits and noted that equipment manufacturers are planning 100% hydrogen combustion-ready turbines before 2030.

What’s more, the Biden administration and congressional allies have earmarked billions of dollars to stand up the sort of carbon capture industry the EPA rules are likely to rely on.

Published reports said the rules are likely to make use of recent Supreme Court decisions. Last June, the U.S. Supreme Court limited the EPA’s authority to set standards on GHGs for existing power plants.

In its 6-3 ruling, the court said that only Congress has the power to create a system of cap-and-trade rules to limit emissions from existing power plants.

The case stemmed from the EPA’s 2015 directive to coal power plant operators either to cut production or subsidize alternate forms of energy. That order was never implemented because it was immediately challenged.

Chief Justice John Roberts wrote the majority opinion in West Virginia v. the Environmental Protection Agency and was joined by the court’s other five conservative members.

The decision marked the first time a majority opinion explicitly cited the so-called “major questions doctrine” to justify a ruling. That doctrine holds that with issues of major national significance, a regulatory agency must have clear statutory authorization from Congress to take certain actions and not rely on its general agency authority.

Roberts wrote, “There is little reason to think Congress assigned such decisions” about the EPA regulations, despite the agency’s belief that “Congress implicitly tasked it, and it alone, with balancing the many vital considerations of national policy implicated in deciding how Americans will get their energy.”

The Court rules that capping carbon dioxide emissions to force a nationwide transition away from the use of coal to generate electricity may be a sensible “solution to the crisis of the day,” but that it was “not plausible that Congress gave EPA the authority to adopt on its own such a regulatory scheme.”

No CPP 2.0

The legal fight over the EPA’s authority can be traced back to a move by the Obama administration to set strict carbon limits for each state. It also urged states to meet limits by shifting to cleaner energy alternatives such as wind and solar.

The so-called Clean Power Plan was temporarily blocked in 2016 by the Supreme Court and then repealed in 2019 by the Trump administration, which argued that the plan exceeded EPA’s authority under the Clean Air Act. It argued that the act allowed the agency to set standards only within the physical premises of a power plant.

The Trump administration proposed to regulate emissions only from existing coal-fired steam plants, a policy called the Affordable Clean Energy Rule. The revision was challenged by states and environmental groups and ultimately was struck down by the U.S. Court of Appeals for the District of Columbia Circuit.

Since then, there hasn’t been an EPA standard with respect to carbon pollution from existing power plants.

Under the Biden administration, the EPA has indicated that it will not attempt to resurrect the Clean Power Plan but rather create its own rules based on Supreme Court decisions in 2007 and 2022 to regulate power plant emissions.

Laying the groundwork

The White House and congressional allies already are working to lay the groundwork needed to stand up the carbon-capture industry that the expected EPA rules may rely on. 

In December, the Department of Energy launched four programs seeded with $3.7 billion in infrastructure funding aimed at helping to build a commercially viable carbon dioxide removal industry. 

The programs are intended to help accelerate private-sector investment, spur advancements in monitoring and reporting practices for carbon management technologies, and provide grants to state and local governments to procure and use products developed from captured carbon emissions. 

In addition, the Inflation Reduction Act aimed to improve the federal Section 45Q tax credit for the capture and geologic storage of CO2, which are intended to provide complementary incentives.

The new efforts include a $115 million Direct Air Capture Prize to promote diverse approaches to direct air capture; $3.5 billion to develop four domestic regional direct air capture hubs, each of which will demonstrate a direct air capture technology or suite of technologies at commercial scale with the potential for capturing at least 1 million metric tons of CO2 annually from the atmosphere and storing that CO2 permanently in a geologic formation or through its conversion into products; the Carbon Utilization Procurement Grants Program, which will provide up to $100 million in grants to states, local governments, and public utilities to support the commercialization of technologies that reduce carbon emissions while also procuring and using commercial or industrial products developed from captured carbon emissions; and $15 million to projects led by DOE National Laboratories, plants, and sites, and supported by diverse industry partnerships spanning the emerging carbon dioxide removal sector. 

In September, DOE announced a nearly $4.9 billion set of funding opportunities aimed at bolstering investments in the carbon management industry and to reduce carbon dioxide (CO2) emissions. 

The funding from the Bipartisan Infrastructure Law is intended to support three programs to demonstrate and deploy carbon capture systems, along with carbon transport and storage infrastructure.

The funding announcements include up to $2.25 billion to support the development of new and expanded large-scale, commercial carbon storage projects with capacities to store 50 or more million metric tons of CO2, along with associated CO2 transport infrastructure; up to $2.54 billion to develop six integrated carbon capture, transport, and storage demonstration projects that can be replicated and deployed at fossil energy power plants and major industrial sources of CO2; up to $100 million to design regional CO2 pipeline networks to safely transport captured CO2 from sources to centralized locations. 

More aggressive

The Biden administration’s more aggressive actions are in contrast to the Trump administration. In the summer of 2018, the Environmental Protection Agency unveiled its proposed replacement for the Obama-era Clean Power Plan, saying its approach would give states more regulatory power on curbing greenhouse gas emissions.

The Affordable Clean Energy (ACE) rule challenged the Clean Power Plan, which set carbon reduction targets for every state. Trump and many states argued that the Clean Power Plan overstepped boundaries for federal regulatory power and put burdensome rules on many coal-power states.

The ACE included four main courses of action to reduce greenhouse gas emissions. Those included finding best on-site power plant efficiencies, calling for lists of technologies that ciould be used in state plans, an updated New Source Review permitting program and regulations giving states flexibility in developing response plans.

EPA said the new proposal reflects the latest assessment of available control technologies and techniques for reducing hazardous emissions.

The proposal would further reduce the emissions limit for filterable particulate matter (fPM) by 67 percent for existing coal plants. This standard is designed to control emissions of nickel, arsenic and other non-mercury HAP metals. To comply with the revised fPM emission limit, the proposal also requires plants to have appropriate monitoring systems that provide real-time emissions data. EPA also proposed revising requirements to assure better emissions performance during plant startup.

The proposal also includes cost and feasibility information on achieving even lower levels of fPM emissions. The agency is taking comment on whether to finalize an even stronger standard.

EPA is also proposing a 70 percent reduction in the emissions limit for mercury from existing lignite-fired sources. This would ensure these plants achieve the same level of emissions performance as other coal-fired plants.

EPA projects the proposed rule to reduce emissions of mercury and non-mercury metal pollution, such as nickel, arsenic, and lead. These pollutants are known to cause significant health impacts including fatal heart attacks, cancer and developmental delays in children.

The proposal would also result in emissions reductions of fine particulate matter, sulfur dioxide, nitrogen oxides and carbon dioxide, the agency said.

Industry-reported emissions data, required by MATS, show that 2021 mercury emissions from coal-fired electric generating units are 90 percent lower than pre-MATS (pre-2012) levels.

EPA will accept public comment on the rule for 60 days after publication in the Federal Register and will hold a public hearing.

More details here.

The Environmental Protection Agency (EPA) has spoken: the Good Neighbor Plan was finalized on March 15, 2023. This rule continues EPA’s Cross-State Air Pollution Rule (CSAPR) for the 2015 ozone National Ambient Air Quality Standards (NAAQS) and requires initial reductions from Electric Generation Units (EGUs) beginning in the 2023 ozone season (May 1-September 30). The rule pulls in other industries, such as steel, glass, and paper production, which we won’t discuss here. Requirements vary in the 23 states affected – see Figure 1.

The rule reduces the number of ozone season allowances, which in turn reduces emissions, using a phased-in approach. The operator of each emission unit subject to the rule must hold sufficient allowances to cover their ozone season nitrogen oxide (NO_x) emissions.

2023

• EPA assumes that any EGU with an existing, post-combustion control (selective catalytic reduction [SCR] or selective non-catalytic reduction [SNCR]) will operate that device fully. Therefore, allowances are reduced by the amount of extra control achieved through optimization of existing post-combustion controls.
• Assurance level exceedance provisions: When total emissions from all covered state sources exceed a state’s ozone season emissions budget by more than 21 percent (%) (this threshold can vary), all units with post-combustion controls operating at least 10 percent of the ozone season hours will be subject to a unit-specific secondary emissions limit. When this exceedance occurs, NO_x emissions are prohibited when they exceed by more than 50 tons (per ozone season), an emission rate of 0.10 pound per million British thermal units (lb/MMBtu), or 125 % of the unit’s lowest average emission rate from any previous control period. The unit will be subject to potential administrative or judicial action and subject to penalties under the Clean Air Act’s enforcement authorities. In other words, in certain circumstances the 51^st ton emitted during the summer is subject to a 0.10 lb NOx/MMBtu limit, regardless of existing permits.

2024

• EPA reduces allowances by an amount that assumes implementation of state-of-the-art combustion controls [low-NO_x burners (LNB), over-fire air (OFA), etc. specific to each boiler] on all EGUs.
• Every coal-fired steam EGU greater than 100 megawatts with an existing SCR in a covered state is limited to 0.14 lb NO_x/MMBtu (backstop daily emission rate). Exceeding this daily limit, by more than 50 tons, can result in surrendering 3 allowances for every extra ton emitted.

2026 – EPA reduces allowances by an amount that assumes:

• Implementation of new SNCR on all EGUs and SCR on half of the EGUs currently without SCR/SNCR, and
• Implementation of new controls on all non-EGUs(2-year extension available as outlined in the regulation).
• During the second ozone season after an SCR is installed (i.e. starting 2026 if SCR was installed in 2024), a unit-specific 0.14 lb NOx/MMBtu backstop emission rate applies for coal-fired EGUs. Exceeding this daily limit by more than 50 tons can result in surrendering 3 allowances for every extra ton emitted.

2027 and beyond

• EPA reduces allowances by an amount that assumes reductions based upon the fleetwide implementation of SCR (allowing for addition of alternative control methodologies or the purchase of allowances to meet the statewide mandate).
• In 2030, a unit-specific 0.14 lb NOx/MMBtu backstop emission rate applies for all coal-fired EGUs, except for circulating fluidized bed (CFB) units. Exceeding this daily limit by more than 50 tons can result in surrendering 3 allowances for every extra ton emitted.

Beware of the Prevention of Significant Deterioration (PSD) permitting implications. EPA states “The actual compliance requirement that the EGUs must meet is simply to hold sufficient allowances to cover emissions during a given control period, not to undertake any specific compliance strategy…Those costs could, in turn, result in a reduction in electricity generation from higher-emitting sources and an increase in electricity generation from lower-emitting or zero-emitting generators, but that kind of generation shifting (not mandated but occurring as an economic choice by the regulated sources) is consistent, and in no way interferes with, the existing security-constrained economic dispatch protocols of the modern electrical grid.” Many previous PSD lookback enforcement cases originated from maintenance projects that occurred prior to an increase in capacity factor. Defending causality becomes the responsibility of the EGU.

What should you do?

1. Conduct a PSD netting analysis before the capacity factor increases to provide insurance against possible lookbacks.
2. If you currently have SCR or SNCR, review the system design basis or operating assumptions to determine if you are achieving the lowest emissions possible. Reagent delivery system balancing, injection operating parameter adjustment or catalyst management programs may require updating to reflect the latest unit operating scenario or industry practice.
3. If you do not have NO_x control (LNB, OFA, SCR, SNCR), determine if this rule requires you to install it and get cost estimates now.
4. Talk to your compliance specialist or consultant about your unit’s prior emissions reporting and historical heat input in comparison with the unit specific allocations as identified by the EPA. In some cases, states may opt to modify the allocations as allowed by the rule.
5. Work with your engineering staff, qualified air quality control system engineer and/or equipment supplier to determine the options available to meet the future allocation reductions by adjusting existing operations, adding/modifying control equipment, and/or reviewing generation shifting or unit retirement.

About the Authors:

Robynn Andracsek, PE, is a Senior Air Quality Engineer at Providence Engineering and Environmental Group LLC with 26 years of experience in air permitting for utilities and district energy facilities.  Providence is an employee-owned, multidisciplinary engineering and environmental consulting firm. Our work has taken us across the United States and beyond in support of our governmental and industrial clients’ goals and challenges all the while holding an unwavering dedication to our founding principles – to take care of our clients, make a little money, and have fun while doing it. Her email address is robynnandracsek@providenceeng.com.

Tim Girard is a Project Manager at Affiliated Engineers, Inc. with 24 years of experience in air quality equipment assessment, engineering and construction projects for industrial and electrical generation facilities.  Affiliated is a multidisciplinary engineering and consulting firm with 19 offices in the United States.  Our mission drives us to find unique solutions to solve our clients’ challenges and our dedicated team of engineering professionals use industry knowledge, innovative technology and practical solutions to complete complex projects. His email address is tgirard@aeieng.com.

EPA said the rule would cut emissions that contribute to problems downwind states face in attaining and maintaining air quality standard for ground-level ozone, known as the 2015 Ozone National Ambient Air Quality Standards (NAAQS). 

The rule would use an approach during the summertime “ozone season” that is based on a NOx allowance trading program for fossil fuel-fired power plants in 22 states, and NOx emissions standards for targeted sources within nine industry categories in 20 states.

Beginning in the 2023 ozone season, power plants in 22 states are expected to take part in what EPA said is a “revised and strengthened” Cross-State Air Pollution Rule ozone season trading program.

To achieve rapid emissions reductions, EPA said it based the initial control stringency on the level of reductions achievable through immediately available measures, including consistently operating emissions controls already installed at power plants. Further reductions are expected to be phased in over several years starting in 2024. Those reductions would reflect emissions levels that could be achieved by installing new emissions controls.

Power plants in Utah would face the largest percentage decline in 2027 NOx emissions compared to 2021 levels. A 7,300-ton reduction, equal to a 74% reduction, would be required under the final rule. Mississippi emitters face a 65% reduction, while those in Louisiana and Missouri face a 61% reduction.

Texas power plants will be expected to cut NOx emissions by more than 14,000 tons by 2027, a 38% cut relative to 2021.

EPA said its final Good Neighbor Plan builds on the “demonstrated success of existing emissions trading programs” by including additional features that “promote consistent operation of emissions controls to enhance public health and environmental protection for affected downwind regions.” 

Features include backstop daily emissions rates on large coal-fired units to promote more consistent operation and optimization of emissions controls, annual recalibration of the emissions allowance bank, and annual updates to the emissions budgets to account for changes in the generating fleet.

Beginning in the 2026 ozone season, EPA plans to set enforceable NOx emissions control requirements for certain sources at existing and new industrial facilities that have “significant impacts” on downwind air quality and the ability to install “cost-effective pollution controls.”

These industry-specific requirements would apply in 20 states. EPA said the requirements reflect “proven, cost-effective” pollution reduction measures that are “consistent with standards that sources throughout the country have long implemented.”

EPA said the final rule implements the Clean Air Act’s “Good Neighbor” or “interstate transport” provision, which requires each state to submit a State Implementation Plan (SIP). The SIP documents are intended to ensure that sources within the state do not contribute significantly to nonattainment or interfere with maintenance of the NAAQS in other states. 

Where EPA finds that a state has not submitted a Good Neighbor SIP, or if the EPA disapproves the SIP, the EPA must issue a Federal Implementation Plan (FIP) within two years to assure downwind states are protected.

More information on the final rule is available here.

The action reversed action that the Trump administration took in May 2020, which the Biden administration says undermined the legal basis for the mercury regulations. 

EPA said its final rule leaves the current emissions standards unchanged and continues public health protections provided by the requirements.

The agency said it also was continuing to consider the MATS Risk and Technology Review, as directed by Executive Order 13990, to determine whether more stringent protections for hazardous air pollution from power plants are feasible and warranted. It said it expects to address that review in a separate action.

The initial finding related to mercury emissions was made in 2000 and affirmed in 2012 and 2016. In May 2020, the Trump administration reversed EPA’s 2016 finding. President Biden’s Executive Order 13990 directed EPA to review that finding and consider an action to rescind it. 

EPA found that the 2020 action was based on a “fundamentally flawed” interpretation of the Clean Air Act that “improperly ignored or undervalued” health benefits from reducing hazardous air pollution from power plants. EPA said it was reaffirming that it is “appropriate and necessary” to regulate emissions of hazardous air pollutants from coal- and oil-fired power plants.

EPA estimated that by 2017, mercury emissions from power plants were reduced by 86%, acid gas emissions by 96%, and non-mercury metal emissions by 81% compared to pre-MATS levels in 2010. It also concluded that the cost for the power sector to comply with the MATS was “likely billions of dollars lower” than originally estimated. 

EPA said it would take comments on strengthening the primary annual PM2.5 standard from a level of 12 micrograms per cubic meter to a level between 9 and 10 micrograms per cubic meter.

It said the tighter standard reflected the latest health data and scientific evidence. The agency said it also would take comments on the full range (between 8 and 11 micrograms per cubic meter) included in a recent Clean Air Scientific Advisory Committee (CASAC) report.

EPA said that since it completed its last review of the PM NAAQS in 2012, “thousands of new scientific studies have demonstrated the dangers of soot exposure.” 

EPA estimated that if finalized, a strengthened primary annual PM2.5 standard at a level of 9 micrograms per cubic meter could prevent up to 4,200 premature deaths per year. 

EPA said it was also proposing to revise other aspects related to the PM standards – such as monitoring requirements and the Air Quality Index (AQI) – in a bid to help states and Tribal Nations meet the revised standards. It proposed retaining the primary 24-hour PM2.5 standard of 35 micrograms per cubic meter, while taking comment on revising the level to as low as 25 micrograms per cubic meter. 

In June 2021, EPA said it would reconsider a Trump-era decision to retain the 2012 PM2.5 standards. At the time, it said that available scientific evidence and technical information indicated that the standards “may not be adequate to protect public health and welfare.” 

EPA said that in developing its new proposal, which was released January 6, it considered the best available science and technical information, including an Integrated Science Assessment and updated Policy Assessment.

In the settlement, Evergy agreed to address potential groundwater contamination from a CCR impoundment at the Tecumseh site, under the federal Resource Conservation and Recovery Act (RCRA).

The settlement requires Evergy to assess the nature and extent of contamination at a CCR impoundment at the Tecumseh site. Evergy will install additional monitoring wells, conduct groundwater sampling and analysis, and update closure plans for the facility’s CCR impoundment. 

If Evergy determines that remediation is necessary, it will meet with EPA to discuss next steps. The company will also pay a civil penalty of $120,000.

Energy said that some CCR units at its Lawrence Energy Center and Sibley Generating Station had earlier moved into “corrective action.” 

EPA said that CCR is a large industrial waste stream by volume and can contain harmful levels of contaminants such as mercury, cadmium, arsenic, and cobalt. Without proper management, contaminants from CCR can pollute waterways, groundwater, drinking water, and the air.

The administrative settlement was finalized on November 7. In the agreement, EPA alleged that Evergy did not meet certain requirements under the CCR program, including:

• Failure to adequately prepare annual groundwater monitoring and corrective action reports.
• Failure to comply with groundwater monitoring system requirements.
• Failure to comply with groundwater sampling and analysis requirements.
• Failure to complete an assessment monitoring program.
• Failure to comply with CCR impoundment closure and post-closure reporting requirements.

The Tecumseh coal-fired power plant began operations in 1925 and was retired in 2018. According to EPA, Evergy identified CCR contaminants leaching into groundwater from an impoundment at the Tecumseh facility in 2018, and did not fully comply with the CCR program to adequately address the contamination.

To address the risks from disposal and discharge of coal ash, including leaking of contaminants into groundwater, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments, EPA established national rules for coal ash management and disposal.

In April 2015, EPA promulgated requirements for the safe handling and disposal of coal ash from coal-fired power plants, which established technical requirements for CCR landfills and surface impoundments.

EPA said it is increasing its efforts to investigate compliance concerns at coal ash facilities around the nation to ensure compliance and protect the health of communities that is said are “overburdened” by pollution such as coal ash residuals.

The EPA said it was following Clean Air Act requirements and meeting a court deadline in proposing the rules, which is said would help states “fully resolve” their Clean Air Act “good neighbor” obligations for the 2015 Ozone National Ambient Air Quality Standards (NAAQS).

Beginning in 2023, EPA is proposing to include electric generating units in 25 states in the Cross-State Air Pollution Rule (CSAPR) NOX Ozone Season Group 3 Trading Program, which would be revised and strengthened for the 2015 ozone NAAQS. 

The states include Alabama, Arkansas, California, Delaware, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Utah, Virginia, West Virginia, Wisconsin, and Wyoming.

Beginning in 2026, EPA is proposing emissions standards for certain industrial sources in 23 states that EPA said have a “significant impact” on downwind air quality. EPA said its proposed limits on emissions from power plants and industrial sources reflect the installation and operation of “proven, cost-effective emission controls,” which it said in many cases have been implemented for years in numerous states.

The 23 states are Alabama, Arkansas, California, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, Tennessee, Texas, Utah, West Virginia, Wisconsin, and Wyoming.

EPA projects that the proposed rule by 2026 would prevent around 1,000 premature deaths and avoid more than 2,000 hospital and emergency room visits, 1.3 million cases of asthma symptoms, and 470,000 school absence days. It said reducing ozone levels also would improve visibility in national and state parks and increase protection for sensitive ecosystems, coastal waters, estuaries, and forests.

In 2026, the cost of achieving these reductions would be roughly $1.1 billion (in 2016 dollars), EPA said, and offer at least $9.3 billion in benefits. 

EPA said its proposed limits on NOX pollution from power plants would build upon existing CSAPR trading programs by including additional features that promote the consistent operation of emission controls to enhance public health and environmental protection for the region and for local communities.

Features would include daily emissions rate limits on large coal-fired units to promote more consistent operation and optimization of emissions controls, limits on “banking” of allowances, and annual updates to the emission budgets starting in 2025 to account for changes in the generating fleet.

EPA also proposed emissions standards for new and existing emissions units in additional industries: reciprocating internal combustion engines in pipeline transportation of natural gas; kilns in cement and cement product manufacturing; boilers and furnaces in iron and steel mills and ferroalloy manufacturing; furnaces in glass and glass product manufacturing; and high-emitting, large boilers in basic chemical manufacturing, petroleum and coal products manufacturing, and pulp, paper, and paperboard mills.

EPA said its proposal implements the Clean Air Act’s “good neighbor” or “interstate transport” provision, which requires each state to submit a State Implementation Plan (SIP) that ensures sources within the state do not contribute significantly to nonattainment or interfere with maintenance of the NAAQS in other states. Each state must make this new SIP submission within three years after the promulgation of a new or revised NAAQS.

Where EPA finds that a state has not submitted a good neighbor SIP, or if the EPA disapproves the SIP, the EPA must issue a Federal Implementation Plan (FIP) within two years to assure downwind states are protected. EPA said it is reviewing and acting on SIP submissions from the relevant states covered by this proposal.

EPA said it will take comment on the proposed rule for 60 days after it is published in the Federal Register.