The funding would support technologies that capture CO2 from industrial and power generation or directly from the atmosphere and transport it either for permanent geologic storage or conversion into valuable products such as fuels and chemicals.

The sixth opening of FECM’s Carbon Management funding opportunity announcement (FOA) will support the following areas of interest:

• Reactive carbon capture approaches for point source capture or atmospheric capture with integrated conversion to useful products. Reactive carbon capture is the integration of carbon capture with conversion to a product. This area of interest would focus on conceptual design studies followed by laboratory validation of reactive CO2 capture approaches from exhaust flue gas streams at electric generation and industrial facilities or from the atmosphere, with conversion of the CO2 into environmentally responsible and economically valuable products.
   
• Engineering-scale testing of transformational carbon capture technologies for natural gas combined cycle (NGCC) power plants. Testing under real flue gas conditions aims to achieve 95 percent or greater carbon capture efficiency and 95 percent CO2 purity, while demonstrating significant progress toward a 30 percent reduction in the cost of capture.
   
• Engineering-scale testing of transformational carbon capture technologies in portable systems at industrial plants. Development and testing of portable systems for transformational technologies would be conducted at a variety of sites, including oil refineries and petrochemical, cement and lime, pulp, steel and iron, and glass plants.
   
• Preliminary front-end engineering design (Pre-FEED) studies for carbon capture systems at existing (retrofit) domestic NGCC power plants. Pre-FEED studies of commercial-scale, advanced carbon capture systems at existing NGCC power plants or combined heat and power facilities that employ NGCC power generation.
   
• Pre-FEED studies for carbon capture systems at hydrogen production facilities using coal, mixed coal/biomass or natural gas feedstock. Studies to advance commercial-scale carbon capture systems that separate CO2 with at least 95 percent capture efficiency at new or existing hydrogen production facilities using coal, mixed coal/biomass/municipal solid waste/unrecyclable plastics, or natural gas feedstocks.
   
• Enhancing CO2 transport infrastructure (ECO2 transport): Pre-FEED studies for multimodal CO2 transfer facilities. Studies that support the development of viable and strategically adaptable multimodal transportation infrastructure capable of transferring CO2 across regional and national CO2 transportation networks.

Since the end of 2023, 8 Rivers and Siemens Energy have collaborated on development of direct-fired super critical CO₂ turbines across a range of applications and fuel types. 8 Rivers, a developer of decarbonization technology and projects, said the ongoing turbine development program provides line of sight to future commercial projects. 

Siemens Energy has selected the commercially available generator that will be used with the Allam-Fetvedt Cycle (AFC) turbine. Siemens Energy will also provide related equipment, services, compression and grid technologies.

However, 8 Rivers said it has completed a study with a commercial party which assessed the feasibility of a biomass fueled Allam-Fetvedt Cycle negative emissions power system (Biome). This resulted in the recent signing of an MoU with the aim of commercial deployment, the company said.

8 Rivers argues that biome as a power system allows for the generation of low-cost, reliable, negative emissions power while simultaneously generating large volumes of carbon dioxide removal (CDR).  

North Carolina-based 8 Rivers develops zero-carbon technologies such as hydrogen, carbon capture and biomass carbon removal. It jointly owns NET Power, whose Allam-Fetvedt Cycle combusts natural gas with oxygen (rather than air) to fuel a supercritical CO₂ cycle that generates electricity.

The technology reuses most of the carbon dioxide produced and captures the rest, meaning it emits virtually nothing into the atmosphere. NET Power has said its plants should cost no more to build and operate than a traditional natural gas plant.

In 2018, we reported NET Power successfully achieved first fire of its demonstration plant and test facility in La Porte, Texas. At that time, the company had targeted the global deployment of 300 MW capacity commercial-scale plants beginning as early as 2021.

The Sutter Decarbonization Project would be designed to capture 95% of carbon emissions from Sutter Energy Center. Calpine now plans to begin the first phase of the DOE cooperative agreement, which will support the engineering and design of the project.

Calpine is working with the Sacramento Municipal Utility District (SMUD) to support its 2030 Zero Carbon Plan through the project. Other partners include ION Clean Energy and 1PointFive Sequestration.

Sutter Energy Center is located in Yuba City, California. The 550 MW combined-cycle plant became commercially operable in 2001.

In December 2023, we first reported that the Sutter Decarbonization Project would receive up to $270 million in DOE funding.

The project would use ION’s ICE-21 solvent to capture the CO2 and sequester it permanently more than a half a mile underground in saline geologic formations. It would be the first in the world to deploy an air-cooling system at a carbon capture facility, which would eliminate the use of cooling water and significantly minimize freshwater usage.

Calpine also recently executed the first phase of its cost sharing agreement for the Baytown Decarbonization Project, a similar CCS demo project in Baytown, Texas.

“Calpine is grateful for the DOE’s commitment to working with Calpine to advance this important technology and believes that this is a recognition of the quality and strength of Calpine’s CCS program,” said Alex Makler, Calpine’s Senior Vice President, West Region.

The future adoption of carbon capture and storage likely depends on a variety of factors, like changes in the cost to capture CO2, the availability of pipeline networks and storage capacity for transporting and storing CO2, federal and state regulatory decisions and the development of clean energy technologies that could affect the demand for CCS.

One of the largest generators in the U.S., Vistra, tapped McKinsey & Company to develop a machine-learning model to improve the efficiency and emissions of the coal-fired Martin Lake Power Plant in Rusk County, Texas.

The effort began when Vistra wanted to build and deploy a heat-rate optimizer (HRO) for the plant. The company worked with McKinsey data scientists and machine learning engineers from QuantumBlack AI to build a “multilayered neural-network model,” or an AI-powered algorithm that learns about the effects of complex nonlinear relationships.

The team fed the model two years of plant data to see which combination of external factors and internal decisions could produce the optimal HRO for any given time. External factors included temperature and humidity, and internal decisions included variables that operators can control.

It wasn’t a “one-and-done” solution, though. Vistra’s team continued to provide guidance on how the plant worked and identified data sources from sensors, which McKinsey said helped its engineers refine the model by adding and removing variables to see how the heat rate changed.

Through the training process and “introducing better data,” the models eventually made predictions with 99% accuracy or higher. After running the model through a series of real-world tests, the engineers turned the model into an “AI-powered engine.” After implementing the engine, the plant’s operators received recommendations every 30 minutes on how to improve the plant’s heat-rate efficiency.

“There are things that took me 20 years to learn about these power plants,” said Lloyd Hughes, Vistra’s operations manager. “This model learned them in an afternoon.”

With higher efficiency came more carbon reduction. Martin Lake was running more than 2% more efficiently after three months of operating with the machine-learning tool, which McKinsey said resulted in savings of $4.5 million per year and 340,000 tons of abated carbon.

Following the success at the Martin Lake Power Plant, Vistra distributed the AI-enabled HRO to another 67 generation units across 26 plants, which resulted in an average of 1% improvement in efficiency, McKinsey said, in addition to more than $23 million in savings.

Overall, Vistra’s AI initiatives have helped the company avoid around 1.6 million tons of carbon per year, McKinsey said.

Read the full case study here.

For perspective, AEP’s systemwide peak load at the end of 2023 was 35 GW. The utility serves 5.6 million customers in 11 states through its subsidiaries and has the country’s largest transmission system.

AEP Interim CEO Ben Fowke said the company continues to work with data centers to meet their increased demands for power, while ensuring that new contracts are fair to all of its customers.

“I want to emphasize that it’s critically important that costs associated with these large loads are allocated fairly, and the right investments are made for the long-term success of our grid,” Fowke told investors.

Fowke cited AEP filing new data center tariff proposals in Ohio and large-load tariff modifications in Indiana and West Virginia.

In Ohio, the proposed rate structure would require new data centers with loads greater than 25 MW and cryptomining/mobile data center operations with loads greater than 1 MW to agree to meet certain requirements before infrastructure is constructed to serve them.

Data centers specifically would be required to make a 10-year commitment to pay for a minimum of 90% of the energy they say they need each month – even if they use less.

Along with Exelon, AEP is also protesting a proposal that would result in the co-location of an Amazon Web Services (AWS) data center at Talen Energy’s Susquehanna nuclear plant in northeast Pennsylvania. The utilities claim the proposed interconnection agreement would result in unfair cost burdens on ratepayers and negatively impact market operations and reliability.

According to a study published by EPRI in May, data centers could consume up to 9% of U.S. electricity generation by 2030 — more than double the amount currently used.

The burgeoning of data centers is one reason utilities are planning for the largest increase in natural gas-fired plants in over a decade. Buyers of F-Class, advanced-class and aeroderivative gas turbines are reportedly experiencing lead times not seen since the gas boom of the early 2000s.

AEP’s Public Service Company of Oklahoma (PSO) plans to seek regulatory approval for the purchase of Green Country, a 795 MW natural gas combined-cycle plant in Jenks, Oklahoma. Subject to approval, PSO expects to close on the transaction by June 30, 2025.

On impact of environmental regulations

In the utility’s 10-Q, AEP said federal rules and environmental control requirements would impact the utility’s generation fleet. AEP noted EPA’s suite of measures to crack down on pollution from fossil-fired plants.

Under one of the measures, coal-fired plants which plan to stay open beyond 2039 would have to reduce or capture 90% of their carbon dioxide emissions by 2032. As of June 30, 2024, AEP said approximately 46% of the company’s owned generating capacity was coal-fired.

AEP said it is in the early stages of identifying the best strategy for complying with the rule while ensuring resource adequacy.

The company, along with other utilities, states, companies and trade associations challenged the rule and requested a stay, which was denied by the D.C. Circuit Court of Appeals.

AEP and other utilities have now filed applications with the United States Supreme Court seeking an emergency stay.

The OUCC filed testimony last week to the Indiana Utility Regulatory Commission, arguing that the commission should reject Duke’s proposal due to the “speculative nature of the feasibility and affordability of a CCS system.”

Duke Energy’s request would raise annual revenues for its Indiana electric utility by nearly $492 million, the OUCC said, which would be implemented in two phases. The utility’s testimony and exhibits project that an average monthly residential bill for 1,000 kWh would be $170.67 when new rates are fully implemented in March 2025.

“Duke’s proposal would impose extreme rate shock and unfairly burden its residential customer base, which has experienced significant and worsening affordability challenges,” said Ben Inskeep, Citizens Action Coalition program director. “This rate case is inconsistent with the policy of the State of Indiana and the General Assembly’s repeated emphasis that electric utility bill affordability is a priority. Disappointingly, while Duke proposes a destabilizing rate increase that places a disproportionate burden on residential customers, it has not offered material improvements to its programs that would meaningfully help residential customers with their unaffordable electric bills.”

The OUCC argued its analysis shows that an increase of approximately $184.7 million (6.1%) is warranted instead, based on the case’s evidence and applicable law.

Duke was awarded a Department of Energy (DOE) grant to conduct a front-end engineering design (FEED) study on CCS systems at its Edwardsport Generating Station. The estimated cost of the project is more than $17 million, with an estimated offset of roughly $8 million in federal funding.

In his testimony, Brian Wright, a utility analyst in the electric division for Indiana’s OUCC, noted that Duke’s first CCS feasibility study concluded that CCS was not feasible at Edwardsport due to the “lack of geological formations onsite that could act as a good carbon storage medium.” However, more recent studies at the location have shown that dolomite formations in the area could provide carbon storage capacity.

While Duke Energy has claimed it cannot estimate whether any of its out-of-state subsidiaries could benefit from the study, the OUCC said at “at the very least” the study should improve Duke’s knowledge and experience in evaluating the technological and geographical feasibility of CCS at other sites. Therefore, OUCC argued, the benefits of Duke’s study will likely extend beyond Indiana’s borders, and portions of the cost should be allocated to Duke’s other jurisdictions.

In its petition, Duke Energy said it has been nearly five years since it last filed for a general rate increase, and the test year in the company’s last general rate case was a fully forecasted calendar year 2020 – meaning the case establishing its current rates and charges was filed and the record was closed before the COVID-19 pandemic. Since then, Duke Energy said, the economic climate has changed “significantly,” including increased inflation, increased cost of capital, and Duke Energy Indiana’s capital investments to its electric system.

Testing was conducted at the company’s 4.4 MW gas-powered plant in Holyoke, Massachusetts, which serves the local electric grid.

The company called it a “huge milestone” and said it’s possible for any internal combustion engine – big or small – to have no CO2 emissions.

ESG’s carbon capture system consists of a two-step process: first removing the water from the exhaust and then capturing the CO2. Drying the exhaust more than doubles a CO2-adsorbent’s capacity, enabling 100% of the carbon to be captured while simultaneously reducing the size and cost of the system.

ESG’s water removal and carbon capture system is designed for both large and small systems and can be retrofitted onto current operating power plants plus applied to mobile applications, the company said.

ESG’s water removal system consists of an advanced ceramic membrane incorporated into a mechanical cooling system. According to the company, the CO2 capture system uses solid adsorbers that are nontoxic and easy to handle, making the entire system very versatile and energy efficient.

ESG plans on implementing this technology across all its planned facilities. It has also licensed the technology to a subsidiary of Camber Energy.

The company plans to build a second gas-fired plant in Holyoke. The 4.2 MW plant would also be powered by Caterpillar engines.

For 20 years, the U.S. Environmental Protection Agency (EPA) regulated coal-fired power plants through litigation using a revised interpretation of the routine maintenance exemption in the New Source Review (NSR) regulations. This national compliance initiative ended in 2019 after affecting 113 plants at a cost of $21 billion (as shown in the below figure). However, a new proposed NSR rule change could have a similar significant effect on the power industry.

The big problem with the routine maintenance exemption was the lack of a definition for “routine” and the subsequent after-the-fact evaluations of projects by EPA. At plants grandfathered under NSR [(e.g., operating without best available control technology (BACT)], industry made repairs and undertook projects that it considered to be routine (boiler retubing, turbine overhauls, etc.) without first seeking an NSR permit. In the 1990s, when EPA realized these older plants had never undergone NSR permitting, EPA reevaluated “routine” and decided that these repairs retroactively needed NSR limits and controls. “Routine maintenance” was a powerful tool in shutting down many coal-fired boilers.

On February 22, 2024, EPA proposed several revisions to its NSR preconstruction permitting regulations.^[1] In another of EPA’s unfortunate acronyms,^[2] these rules are referred to Project Emissions Accounting (PEA, 2020) Rule and the Project Emissions Accounting Rule Reconsideration (PEAR, 2024). The two rules were meant to clarify issues resulting from the mostly failed 2002 NSR Reform Initiative and the rule interpretations in intervening years.

PEA and PEAR attempt to formally define a project, to wit, what activities are included when calculating and comparing emission increases to the NSR permitting thresholds. For example:

• How many years separation are required before two activities are considered a single project?
• Does a project include just the new emissions or also the associated emission unit decreases?
• What makes an emission decrease enforceable when replacing an old unit?

Industry seeks clarity and certainty when interpreting environmental regulations. Failure to obtain the correct permit is costly (see Figure above). The group of activities that constitute a project is virtually always site-specific. Substantial comments (due July 2, 2024) were received on the draft regulation.

For example, EPA proposed the following revisions to the definition of project (revised text is in bold):

Project means a discrete physical change in, or change in the method of operation of, an existing major stationary source, or a discrete group of such changes (occurring contemporaneously at the same major stationary source) that are substantially related to each other. Such changes are substantially related if they are dependent on each other to be economically or technically viable. In an extreme ozone nonattainment area, a “project” means each discrete operation, emissions unit, or other pollutant-emitting activity.

Comments from industry groups, regulators and tribal organizations varied widely. The proposal was a much-needed improvement, it included a presumption that industry was trying to circumvent the regulations, and it imposed unjustified recordkeeping and reporting. The proposal manages to please no one completely and annoy everyone in differing ways. Commenters argue that “discrete” is poorly defined, the test for “economically viable” is not provided, and removing the previous guidance that two projects divided by more than three years are separate is ill-advised.

Additionally, commenters argue permitting each reduction could be onerous, EPA failed to identify any instance in which a failure to properly define a “project” altered the applicability determination and/or led to circumvention of NSR preconstruction permitting requirements, and reporting requirements are vague enough to be applicable to new office equipment.

NSR is a poorly written regulation, influenced by lobbyists and corrupted by 50 years of litigation. Like the 2002 NSR Reform attempt, this proposal, and in fact the entire NSR program, is subject to political winds and capricious legislative whims. When combined with the recent Supreme Court assassination of the Chevron Deference (when in doubt, defer to the experts at the regulatory agencies), power plants stagger under increased regulatory uncertainty. Redefining projects has the potential to impact the power industry as significantly as the reinterpretation of “routine”.

What should you do?

• Acknowledge that PEA/PEAR is a big deal, and it will affect your operations.
• Consult an attorney before each outage and project.
• Conduct NSR netting calculations to set baseline emissions before each outage and project.
• Document project emissions, including reductions, in-house and potentially with your regulator.
• Consult with your regulator to understand what permits are required before and which emissions reports are required after each post outage/project.
• Follow this rule in industry groups to understand how it evolves.

References

¹ 89 Fed. Reg. 36,870 (May 3, 2024) Docket ID EPA-HQ-OAR-2022-0381

² See CSAPR pronounced Casper

About the Author: 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.

The Baytown Decarbonization Project is designed to capture 95% of CO2 emissions from two of the three turbines at the company’s Baytown Energy Facility, enabling the facility to produce electricity as well as steam for collocated industrial use. Calpine will now begin the first phase of the DOE cooperative agreement, with other phases to follow upon successful completion of phase one and finalization of plans for subsequent phases.

“We are pleased to have reached another milestone in the development of our Baytown Decarbonization Project. This initial Phase 1 commitment by the DOE will support the engineering and design of the project, further our community engagement, and advance project planning,” said Caleb Stephenson, Calpine’s Executive Vice President of Commercial Operations.

“This marks an important step forward for the Baytown CCS Project,” added Stephenson. “While there remain many milestones ahead, this step demonstrates Calpine’s continued commitment to being a leader in the energy transition in general and in carbon capture technology in particular. Calpine looks forward to continuing its partnership with the DOE as we work toward decarbonization of facilities like the Baytown Energy Center, which will be a critical part of our energy infrastructure for the foreseeable future and play a key role in decarbonizing our nation’s industrial sector.” Stephenson said.

In addition to the company’s Baytown project, Calpine continues to advance its similarly sized Sutter Decarbonization Project in California, which is negotiating an agreement with OCED that will help advance that project as well.

“Calpine is grateful for the DOE’s commitment to working with Calpine to advance this important technology and believes that this a recognition of the quality and strength of Calpine’s CCS program,” said Stephenson.

Carbon capture and storage (CCS) involves removing carbon dioxide, either from the source of pollution or from the air at large and storing it deep underground. In some instances, the CO2 is transported across states through pipelines and stored at facilities and used for other purposes.

The Biden Administration believes large-scale deployment of carbon capture, transportation, and storage infrastructure could play a vital role in reducing emissions and has increased pressure on the CCS industry to show that the technology can significantly help combat climate change.

Proponents say CCS could have a huge role in reducing emissions, while environmentalists note the technology is far from scale and argue that focusing on it distracts from renewable energy solutions.

WASHINGTON (AP) — The Environmental Protection Agency will not be able to enforce a key rule limiting air pollution in nearly a dozen states while separate legal challenges proceed around the country, under a Supreme Court decision Thursday.

The EPA’s “good neighbor” rule is intended to restrict smokestack emissions from power plants and other industrial sources that burden downwind areas with smog-causing pollution.

Three energy-producing states — Ohio, Indiana and West Virginia — challenged the rule, along with the steel industry and other groups, calling it costly and ineffective.

The Supreme Court put the rule on hold while legal challenges continue, the conservative-led court’s latest blow to federal regulations.

The high court, with a 6-3 conservative majority, has increasingly reined in the powers of federal agencies, including the EPA, in recent years. The justices have restricted EPA’s authority to fight air and water pollution, including a landmark 2022 ruling that limited EPA’s authority to regulate carbon dioxide emissions from power plants that contribute to global warming.

The court is also weighing whether to overturn its 40-year-old Chevron decision, which has been the basis for upholding a wide range of regulations on public health, workplace safety and consumer protections.

A look at the good neighbor rule and the implications of the court decision.

What is the ‘good neighbor’ rule?

The EPA adopted the rule as a way to protect downwind states that receive unwanted air pollution from other states. Besides the potential health impacts from out-of-state pollution, many states face their own federal deadlines to ensure clean air.

States such as Wisconsin, New York and Connecticut said they struggle to meet federal standards and reduce harmful levels of ozone because of pollution from out-of-state power plants, cement kilns and natural gas pipelines that drift across their borders.

Ground-level ozone, commonly known as smog, forms when industrial pollutants emitted by cars, power plants, refineries and other sources chemically react in the presence of sunlight. High ozone levels can cause respiratory problems, including asthma and chronic bronchitis. People with compromised immune systems, the elderly and children playing outdoors are particularly vulnerable.

Judith Vale, New York’s deputy solicitor general, told the court that for some states, as much as 65% of smog pollution comes from outside its borders.

States that contribute to ground-level ozone must submit plans ensuring that coal-fired power plants and other industrial sites do not add significantly to air pollution in other states. In cases where a state has not submitted a “good neighbor” plan — or where EPA disapproves a state plan — a federal plan is supposed to ensure downwind states are protected.

What’s next for the rule?

The Supreme Court decision blocks EPA enforcement of the rule and sends the case back to the U.S. Court of Appeals for the District of Columbia Circuit, which is considering a lawsuit challenging the regulation that was brought by 11 mostly Republican-leaning states.

An EPA spokesman said the agency believes the plan is firmly rooted in its authority under the Clean Air Act and “looks forward to defending the merits of this vital public health protection” before that appeals court.

The spokesman, Timothy Carroll, said the Supreme Court’s ruling will “postpone the benefits that the Good Neighbor Plan is already achieving in many states and communities.”

While the plan is on pause, “Americans will continue to be exposed to higher levels of ground-level ozone, resulting in costly public health impacts that can be especially harmful to children and older adults,” Carroll said. Ozone disproportionately affects people of color, families with low incomes, and other vulnerable populations, he said.

Rich Nolan, president and CEO of the National Mining Association, said he was pleased that the Supreme Court “recognized the immediate harm to industry and consumers posed by this reckless rule. No agency is permitted to operate outside of the clear bounds of the law and today, once again, the Supreme Court reminded the EPA of that fact.”

With a stay in place, Nolan said the mining industry looks forward to making its case in court that the EPA rule “is unlawful in its excessive overreach and must be struck down to protect American workers, energy independence, the electric grid and the consumers it serves,.”

Few states participate

The EPA rule was intended to provide a national solution to the problem of ozone pollution, but challengers said it relied on the assumption that all 23 states targeted by the rule would participate. In fact, only about half that number of states were participating as of early this year.

A lawyer for industry groups that are challenging the rule said it imposes significant and immediate costs that could affect the reliability of the electric grid. With fewer states participating, the rule may result in only a small reduction in air pollution, with no guarantee the final rule will be upheld, industry lawyer Catherine Stetson told the Supreme Court in oral arguments earlier this year.

The EPA has said power-plant emissions dropped by 18% in 2023 in the 10 states where it has been allowed to enforce its rule, which was finalized last year. Those states are Illinois, Indiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia and Wisconsin. In California, limits on emissions from industrial sources other than power plants are supposed to take effect in 2026.

The rule is on hold in another dozen states because of separate legal challenges. The states are Alabama, Arkansas, Kentucky, Louisiana, Minnesota, Mississippi, Missouri, Nevada, Oklahoma, Texas, Utah and West Virginia.

Administrative overstep or life-saving protection?

Critics, including Republicans and business groups, call the good neighbor rule an example of government overreach.

The EPA rule and other Biden administration regulations “are designed to hurriedly rid the U.S. power sector of fossil fuels by sharply increasing the operating costs, … forcing the plants’ premature retirement,” Republican lawmakers said in a brief filed with the high court.

Supporters disputed that and called the “good neighbor” rule critical to address interstate air pollution and ensure that all Americans have access to clean air.

“Today’s move by far-right Supreme Court justices to stay commonsense clean air rules shows just how radical this court has become,” said Charles Harper of environmental group Evergreen Action.

“The court is meddling with a rule that would prevent 1,300 Americans from dying prematurely every year from pollution that crosses state borders. We know that low-income and disadvantaged communities with poor air quality will bear the brunt of this delay,” Harper said.

Roger Reynolds, senior legal director of the environmental group Save the Sound, said the decision hinders the EPA from protecting states such as Connecticut and New York that suffer from ozone pollution generated in the Midwest.

“We cannot reach healthy air quality for our residents without addressing upwind pollution, in addition to local sources,” Reynolds said.

The rule applies mostly to states in the South and Midwest that contribute to air pollution along the East Coast. Some states, such as Texas, California, Pennsylvania, Illinois and Wisconsin, both contribute to downwind pollution and receive it from other states.