Delays, Rollbacks, and Diverging Paths: The Global State of Power Plant Emissions Controls

In recent years, analysis of the world’s power plant emissions appears to have centered largely on carbon dioxide (CO ₂), mainly because carbon dominates global accounting frameworks and climate goals. In April, independent energy think tank Ember released its latest Global Electricity Review, revealing that the power sector emitted a record 14.6 billion tonnes of CO ₂ in 2024—even as low-carbon generation surpassed 40% of global output for the first time since the 1940s. But the day-to-day environmental and health burden of power generation is driven by a broader suite of emissions: sulfur dioxide (SO ₂), nitrogen oxides (NO _x), particulate matter (PM), mercury, and fugitive methane.

Those pollutants, which are subject to highly variable national regulations, are gaining renewed attention as power generators confront new pressures, including grid reliability, environmental mandates, and shifting policy regimes. In 2025, several developments show progress for ammonia co-firing, baghouse upgrades, and carbon capture retrofits, even as enforcement delays, coal resurgence, and regulatory rollbacks fog up progress.

The first half of 2025 was notably marked by substantial regulatory volatility, especially in the U.S. In June, the Trump administration’s Environmental Protection Agency (EPA) formally proposed repealing both the Biden-era carbon pollution standards for existing fossil fuel power plants (issued under Clean Air Act Section 111) and the 2024 amendments to the Mercury and Air Toxics Standards (MATS). The carbon policy reversal argues that the EPA overstepped its legal authority and failed to justify the feasibility of carbon capture and hydrogen blending as the “best system of emission reduction.” For MATS, the agency seeks to revert to the original 2012 standards, effectively rejecting the 2024 rule’s tighter limits on mercury and particulate matter on the grounds that they lack significant health benefits and impose excessive costs, particularly given its controversial requirement that plants install continuous emissions monitoring systems (CEMS).

In April, the Trump administration delayed the MATS compliance deadline by two years via executive proclamation, exempting more than 60 generating units. As expected, environmental groups filed legal challenges. The EPA’s lengthy rationale for the policy reversal appears to be centered on costs, estimating $1 billion in avoided compliance costs between 2028 and 2037, if the repeal proceeds. However, the uncertainty has left generators caught between pending litigation, planning cycles, and technology investments (Figure 1).

1. According to the U.S. Environmental Protection Agency (EPA), power plant emissions in the U.S. continued to decline in 2023, with sulfur dioxide (SO2) down 24%, nitrogen oxides (NOx) down 15%, mercury down 17%, and carbon dioxide (CO2) down 7% from 2022 levels—even as power generation fell just 2%. Compared to 1995, SO2 and NOx emissions have dropped by 95% and 89%, respectively. Source: EPA

As somewhat of a contrast, the European Union (EU) is moving to steadily tighten its emissions control framework for power plants. An August 2024 revision of the 2010-adopted Industrial Emissions Directive (IED) requires member states to comply by July 2026, potentially signaling an escalation in enforcement, scope, and technological expectations. The IED, the EU’s main tool for regulating pollution from major industrial installations, is anchored in the mandatory implementation of best available techniques (BAT), and continues to rely on the 2017 Large Combustion Plants Best Available Techniques Reference Document (LCP BREF), which defines emissions ranges—known as BAT-associated emission levels (BAT-AELs)—for pollutants like NO _x, SO ₂, dust, and mercury. While the LCP BREF is under review, BAT-AELs have driven widespread deployment of selective catalytic reduction (SCR), flue gas desulfurization (FGD), and high-efficiency fabric filters. The LCP BREF also introduced binding mercury controls, and continuous emissions monitoring is required for plants over 100 MWth. While not all units require real-time mercury measurement, annual monitoring is mandatory for coal and lignite plants.

As a whole, SO ₂ emissions and dust emissions from large combustion plants have fallen by 94% and NO _x by 73% since 2004, owing to widespread pollutant controls like FGD. In addition, while the IED does not regulate CO ₂, the EU Emissions Trading System has helped slash power sector CO ₂ emissions by about 50% from 2005 levels, as carbon prices rose to €65 per metric ton in 2024. Notably, the 2024 IED revision introduced new obligations for digital reporting, transformation plans, and a dedicated Innovation Centre on Industrial Transformation and Emissions (INCITE).

Major economies in Asia have also moved to tighten emissions controls while attempting to balance economic and energy security priorities. China is wrapping up implementation of its 14th Five-Year Plan (2021–2025), which establishes an 18% reduction in carbon intensity from 2020 levels and aims to achieve 33% renewable electricity consumption.

The State Council’s 2024–2025 Action Plan for Energy Conservation and Carbon Reduction, released in May 2024, establishes more ambitious targets, including requiring the power and industrial sectors to collectively reduce their CO ₂ emissions by 130 million tonnes annually for both 2024 and 2025. The measure is the first transition to a dual-control carbon emissions mechanism, which is slated for full implementation during the 15th Five-Year Plan period (2026–2030). In addition, the national emissions trading system now covers the power industry. A notable example is the Taizhou 500,000-tonnes-per-year post-combustion carbon capture project (Figure 2), which has now operated stably for over a year and is serving as a technical foundation for a planned scale-up to 4 million tonnes per year during the 15th Five-Year Plan period.

2. Asia’s largest post-combustion carbon capture demonstration project, located at CHN Energy’s Taizhou Power Plant in Jiangsu Province, has captured over 500,000 tonnes of CO2 annually since June 2023. After more than 400 consecutive days of stable operation, the project has achieved a 90.86% CO2 capture rate and 99.94% purity. The facility showcases key innovations in absorbent chemistry, equipment design, and control systems. Source: Gong, H.; Yang, Y.; Deng, B.; Fan, Y.; Wang, T.; Tang, Z.; and Xu, D. (March 2025)

In addition, the country’s NO _x and SO ₂ emissions continue declining under strengthened ultra-low emissions standards, with NO _x limits maintained at 50 milligrams per normal cubic meter (mg/Nm ³) and SO ₂ at 35 mg/Nm ³ for coal plants. Its SCR, FGD deployment, and CEMS network has also expanded, driven by “Blue Sky” policy.

Meanwhile, China has been mapping comprehensive mercury hotspots and identifying priority areas for targeted intervention. According to independent research organization Centre for Research on Energy and Clean Air (CREA), China’s structural optimization of the power sector—evidenced by a 4-percentage-point drop in coal-fired power generation in early 2025—is playing a critical role in the “dual reduction” of pollution and carbon emissions, especially as industrial electrification advances.

The country is also making gains in emerging technologies. In July 2024, China’s National Development and Reform Commission (NDRC) released an official ammonia co-firing strategy as part of its 2024–2027 economic action plan, mandating that existing coal-fired power plants—particularly those with long remaining service life—retrofit to achieve at least 10% renewable ammonia or biomass co-firing capability by 2027, with a target of reducing fleet-wide coal plant emissions by 50% compared to 2023 levels.

India’s thermal power plant fleet entered 2024 facing strict air-emission mandates, prompting policymakers and utilities to respond with a mix of selective compliance, technology pilots, and decarbonization plans. A December 2024 notification from the Ministry of Environment retained particulate and NO _x caps, but in July 2025, it reversed a decade-old mandate for SO ₂, despite billions of dollars spent by utilities on pollution control equipment. Only “Category A” coal plants, sited within 10 kilometers (km) of million-plus cities, are now required to retrofit wet FGD systems by December 2027. Category B units, located within 10 km of non-attainment cities, are no longer required to retrofit if their deadlines have already lapsed.

About 79% of India’s coal fleet, located outside these zones, is now permanently exempt from SO ₂ mitigation requirements. The shift follows years of low compliance: as of mid-2025, only 39 of 537 coal-fired units (about 11% of required capacity) had reportedly commissioned FGD systems. According to industry reports, despite earlier FGD mandates, implementation has been hampered by limited vendors, high capital costs—averaging INR 1.2 crore ($139,500)/MW—and persistent logistical and permitting delays, especially in regions like Delhi (National Capital Territory). Official documents suggest that while a total of 537 thermal power plant units (a combined 204 GW) could install FGD controls, installations have been completed in only 49 units (25 GW). Contracts have been awarded, or implementation has begun at 211 units, while 180 units are in the tendering process.

NO _x control remains governed by the diluted 2015 standards. Legacy units may emit up to 450 mg/Nm ³, but post-2017 plants must meet 100 mg/Nm ³. That effort spurred Bharat Heavy Electricals’ new SCR-catalyst factory and the first set of commercial orders from Maharashtra, Telangana, and West Bengal utilities. CEMS, mandatory since 2024, now cover more than 3,100 plants and 5,700 stacks, underpinning tighter PM audits even as most units rely on upgraded electrostatic precipitators (ESP) and baghouses to meet the 30–100 mg/Nm ³ particulate limits. Mercury is still capped at 0.03 mg/Nm ³, and compliance has been historically delivered mainly as a co-benefit of ESPs—and any FGD installed—rather than through dedicated sorbent injection.

Meanwhile, India’s Carbon Credit Trading Scheme (CCTS), adopted in July 2024, launched a national intensity-based emissions trading system that includes the power sector among nine energy-intensive industries. In April 2025, the government issued its first greenhouse gas benchmark notification for compliance in fiscal year (FY) 2025–2026, formalizing emissions obligations. The system builds on verified savings of 106 million tonnes of CO ₂ under the Perform-Achieve-Trade (PAT) program, which many coal- and gas-fired generators have participated in since 2012.

Among notable carbon capture pilots is NTPC’s 4.8-GW Vindhyachal Super Thermal Power Station, which has begun capturing CO ₂ from plant flue gas as part of a foundational project to explore the conversion of CO ₂ to methanol. NTPC, notably, also awarded a July 2024 contract to demonstrate methanol-firing at its 350-MW Kayamkulam gas turbine, signaling emerging interest in low-carbon co-firing fuels.

Japan’s regulatory framework has centered on implementing its GX (Green Transformation) strategy through a mandatory emissions trading system that began in May 2025, which involves aggressive deployment of post-combustion carbon capture technology at major thermal facilities. The government’s updated Global Warming Countermeasures Plan, revised in February 2025, reaffirmed a 73% greenhouse gas reduction target by 2040 and set an intermediate goal of 60% by 2035, with stringent requirements for the power sector. According to the 7th Strategic Energy Plan, thermal power plants must transition to “near-zero CO ₂ emissions” by using hydrogen and ammonia co-firing, and carbon capture, utilization, and storage (CCUS) technologies. Notably, the government explicitly calls for the “promotion of decarbonization of thermal power by utilizing hydrogen, ammonia, CCUS, etc.” as a core strategy to preserve supply reliability while cutting emissions.

Major utilities, including JERA, have responded with significant technology investments, most notably the world’s first commercial demonstration of 20% ammonia co-firing at the Hekinan Thermal Power Station, which concluded in June 2024 with positive results showing NO _x emissions remained at baseline levels while reducing SO _x by 20%. However, in June 2025, energy research and consultancy group Asia Research & Engagement (ARE) cautioned that ammonia co-firing delivers only modest CO ₂ cuts—about 10% at 20% blends—while imposing “prohibitively high costs” and lifecycle emissions risks if ammonia is fossil-derived. Without binding green ammonia standards, the group said, the strategy risks locking in expensive, low-impact decarbonization.

—Sonal Patel is a senior editor for POWER.