Environmental

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Operational GHG Emissions

The “Evolve” aspect of our Climate Change Strategy focuses on realizing the full potential of our current asset base. The purpose of evolution is to differentiate us and our capabilities from those of our peers. In June 2021, we publicly announced emissions reduction targets^[1] geared toward aggressively driving down the emissions associated with our Production segment operations, as follows: 

In October 2024, we announced our achievement in reaching net-zero Scope 1 and Scope 2 GHG emissions^[2] across the company’s legacy operations ahead of our 2025 goal. This milestone covers the entirety of our upstream operations, including the recently acquired Alta Assets and the Tug-XcL Assets, which were not part of the original target set in 2021. These assets combined represented an approximately 52% increase relative to starting-point emissions. We achieved net zero primarily through emissions abatement and utilized company-generated offsets to counteract the remainder rather than utilizing purchased credits. For 2024, the combined Scope 1 and Scope 2 emissions for EQT Assets, Alta Assets, and Tug-XcL Assets was 745,016 MT CO₂e. EQT generated more than 745,016 of offsets to reach net zero. With this accomplishment, we were the first traditional energy company of scale in the world to achieve net zero on a Scope 1 and Scope 2 basis. For additional details about the project EQT completed to generate the offsets, see Climate Change Strategy.

Our NetZero Now+ initiative reflects our current achievement of attaining net-zero Scope 1 and Scope 2 GHG emissions with respect to our 2021 emissions target, as well as our aspiration to achieve net-zero Scope 1 and Scope 2 GHG emissions across additional assets in future years. Further information about the monumental achievement can be found on our NetZero Now+ website.

Further, after achieving our Scope 1 GHG and methane intensity targets during calendar year 2023, we continued to exceed these targets in 2024.

Initially, we focused on implementing operational improvements to meet these GHG emissions targets. Our primary emissions reduction activities include the items below:

• Natural gas-powered pneumatic device replacement program;
• Leak detection and repair (LDAR);
• Mitigation of venting and flaring;
• Prevention of releases during well unloading;
• Use of glycol pumps on dehydration units;
• Electrification of our hydraulic fracturing fleets; and
• Monitoring for opportunities to make our transportation fleets more efficient.

Detailed information about the natural gas-powered pneumatic device replacement program is described further in this section. Additional details about other emission reduction activities are described in our 2023 Environmental, Social, and Governance (ESG) Report and at NetZero Now+.

Through the successful implementation of our emission reduction initiatives and activities, we have also made noteworthy progress toward our other emissions reduction goals. In 2024, for example, we reduced the total Scope 1 GHG emissions emitted by our historical EQT assets to 309,228 MT CO₂e — a nearly 4% reduction compared to 2023 levels and a 67% reduction compared to 2018 levels, the latter marking the emission levels before our current management team joined EQT in mid-2019. This emissions reduction was propelled by our elimination of natural gas-powered pneumatic devices from our production operations, which we completed with respect to our historical assets in December 2022. The completion of this 2022 initiative alone is projected to reduce our annual carbon footprint by over 300,000 MT CO₂e.^[3]

Additionally, we have significantly reduced GHG emissions from acquired assets. For example, the 2024 Scope 1 GHG emissions of the Alta Assets were 123,821 MT CO₂e, an approximately 50% reduction since we began operating these assets in 2021. This is concrete evidence of the Growth pillar of our Corporate Climate Strategy, and our ability to scale our emissions reduction initiatives to successfully apply them to assets we acquire.

We also continue to work on further reducing emissions from acquired assets. In 2024, the Scope 1 GHG emissions associated with the operation of Tug-XcL Assets were 228,508 MT CO₂e, a slight increase compared to 2023. As we have additional time to operate these assets, we are working to incorporate emission reduction approaches similar to those we have used for legacy EQT and Alta Assets.

EQT Production Segment Scope 1 and Scope 2 GHG Emissions (MT CO₂e)^[4]

Production Segment Scope 1 GHG Emissions Intensity (MT CO₂e emitted/gross annual production [Bcfe])^[5]

We actively participate in ONE Future, which seeks to improve the industry’s environmental performance. With a science-based approach, ONE Future has set a 2025 target for methane emissions intensity for the industry at or below 1%, a target of 0.283% for the Production segment, and a target of 0.080% for the Gathering and Boosting segment. We significantly outperform the ONE Future methane intensity target for our industry and the Production and Gathering and Boosting segments. Our company-wide Production segment and Gathering and Boosting segment methane emissions intensity values decreased in 2024 compared to 2023.

Methane Emissions Intensity^[6]

Our company-wide 2024 Scope 1 Production segment methane intensity is 0.0070%, which is 65% lower than our 2025 methane intensity target.

Production Segment Methane Emissions Intensity (Production segment methane emissions [MT CH₄]/(Gross annual production of hydrocarbons + Methane content [MT Ch₄])

In January 2023, we partnered with other leading U.S. natural gas companies to launch the AMI, a coalition committed to further enhance methane monitoring throughout the Appalachia Basin and facilitate additional methane emissions reductions in the region. AMI’s efforts are intended to promote greater efficiency in the identification and remedy of potential fugitive methane emissions from operations in the Appalachian Basin through coordinated aerial surveys on a geographic-basis, as opposed to an operator-specific basis, and advanced methane monitoring and reporting frameworks.

Following successful completion of the pilot program in 2023, the program was expanded in 2024 to utilize more than 15,000 aerial surveys across approximately 20,500 square miles of the Appalachian Basin to measure emissions from oil and gas operations as well as other sources, such as coal mines and landfills. In its March 2025 announcement of the 2024 monitoring program results, AMI determined that the Appalachian Basin has the lowest methane emissions intensity of any major oil and gas producing basin in the United States. Further, the results showed that coal mines represented the highest average emissions per site of any type of facility included in the surveys.

In 2025, AMI intends to monitor more than 32,000 square miles of the Appalachian Basin, including gas production facilities with daily volumes roughly 100% of the daily production within the Appalachian Basin, which is a nearly sixfold increase in volume compared with surveys completed in 2023. The number of non-oil and gas sites surveyed, such as coal mines/vents and landfills, are also anticipated to increase.

In 2024, we also continued our membership with the OGMP 2.0 — an initiative led by the United Nations Environment Programme in partnership with the European Commission, the United Kingdom Government, the Environmental Defense Fund, and other leading oil and natural gas companies, which aims to monitor and mitigate methane emissions on a global scale. OGMP 2.0 requires member companies to disclose a methane reduction target and submit a comprehensive, measurement-based report of methane emissions from operated and non-operated assets annually. In 2024, for the third year in a row, we received an OGMP 2.0 “Gold Standard” rating, the highest reporting level under the initiative, in recognition of our ambitious methane emissions reduction targets and advanced commitment to accurately measure, report, and reduce our company-specific and site-level methane emissions. To receive the “Gold Standard,” we achieved a Level 4 reporting level of the five available reporting levels, which requires source-level quantification.

We use this measurement and monitoring data to compare against emissions values calculated using emissions factors. These results also allow us to identify potential emissions reduction initiatives going forward. Further, we examine potential differences between emissions calculated using emissions factors and measurement or monitoring approaches to determine the best method to prepare annual emissions inventories in the future.

When we set our GHG emissions targets in 2021, pneumatic devices were one of our largest sources of methane emissions. We use pneumatic level switches and liquid level controllers^[7] to set thresholds and to control motor valves that manage fluid in vessels such as separators, scrubbers, and filters. We operate thousands of pneumatic level switches and liquid level controllers across our operations that regulate gas and liquid separation volumes or activate shutdowns when high or low liquid levels occur. As of December 31, 2024, we do not operate any permanent or temporary high-bleed pneumatic controllers at our production locations.

Our Natural Gas-Powered Pneumatic Device Replacement Program represents a substantial step forward toward our emissions goals and was the primary factor in being able to achieve our targets ahead of schedule. Through this program, we replaced or retrofitted nearly 9,000 natural gas-powered pneumatic devices on all our historical production locations and compressor stations through a “fit-for-purpose” technology strategy.

When we make capital allocation decisions for our emissions reduction initiatives, we prioritize projects that support actual emissions reductions versus emissions reported per U.S. Environmental Protection Agency (EPA) guidance. For example, internal research shows that actual annual emissions attributable to pneumatic devices during the first 2 years of a well’s productive life are roughly equal to the actual emissions for the remaining balance of the well’s life. Importantly, while these early-life pneumatic device emissions likely exceed the flat annual emissions attributed under EPA guidelines, which apply a single emissions factor regardless of the life of the well, we also found that EPA guidelines result in inflated emissions for the remainder of the well’s life.^[8] As such, when we initiated our pneumatic device replacement program, we began by targeting all new development and all sites within their first 2 years of production. Ultimately, our goal is to reduce actual emissions — not “desktop” emissions.

Replacement of natural gas-powered pneumatic devices represents a meaningful opportunity to reduce methane emissions within the oil and natural gas production industry. Based on our own research and replacement program, we believe most of the emissions from these devices are abatable at a relatively low cost. The total project cost of our replacement program was approximately $28 million, which equates to a carbon abatement cost of approximately $6 per ton.^[9]

To build upon the work done to monitor and reduce GHG emissions, we are working to digitize the emissions calculation process to adopt controls and allow for potential future third-party verification. We partnered with Context Labs, a leader in advanced climate data analytics, to establish a strategic partnership to help support our efforts to scale emissions mitigation across our operations and achieve long-term emissions goals, including:

• Centralized and standardized emissions data gathering, governance, and reporting;
• Certification and verification of the carbon intensity of the products that we produce and deliver to our customers; and
• Generation of asset-grade, data-backed, low-carbon intensity natural gas products and carbon credits.

To accomplish this, we are building a digital framework that will allow us to track, report, and verify our GHG emissions. In addition, we plan to incorporate details to track the carbon offsets generated by our New Ventures team. In 2024, we completed the integration of EQT Production operational and asset-related data. Key milestones of this ongoing integration include:

• Integration of EQT Midstream operational and asset-related data in 2025;
• Integration of carbon offset data in 2026; and
• Verification methodology with additional layers of monitoring data in 2026.

While this process will improve the reporting and potential verification of our emissions, it will also benefit our customers. We expect a global differentiated gas market to evolve toward a carbon intensity data exchange where all commercial transactions include measurement-informed GHG emissions data. Including third-party certified environmental attributes from the entire natural gas distribution lifecycle will allow energy buyers to make decisions based on a fuel's empirically informed GHG emissions impact. Recognizing that many of our customers are increasingly obligated to cap their emissions and/or purchase GHG emissions allowances, integrating measurement-informed differentiated natural gas with performance certificates presents an opportunity for buyers to reduce their emissions impact. These trends are anticipated to benefit us given our relative emissions performance compared to industry metrics, as well as our robust portfolio of differentiated gas products.

We monitor and report on operational GHG emissions as required by state and federal regulations. We gather operational data and report emissions annually per emissions inventory requirements in each state where we have operations. For sources subject to the EPA’s GHG Reporting Program, we submit reports to the EPA, which are validated electronically. We follow all GHG emissions-limiting regulations we are subject to and seek continuous improvement capabilities in areas that provide the greatest opportunity for GHG reductions. For more information on how we stay abreast of applicable regulations, please see Public Policy and Perception.

Our GHG emissions fall into three categories or “scopes:”

• Scope 1 emissions: Direct GHG emissions from sources we own or control;
• Scope 2 emissions: GHG emissions from the generation of purchased electricity, typically from a third-party entity (such as a utility), and consumed in connection with our operations; and
• Scope 3 emissions: All other indirect GHG emissions due to our activities, from sources not owned or controlled by us, such as the use of our sold products by individual consumers.

The GHG Protocol has additional information about how these scopes are defined. We explain how we calculate our Scope 1, 2, and 3 emissions in more detail below. The GHG emissions values below include emissions generated by the EQT, Alta, and Tug-XcL Assets, but do not include emissions associated with the Equitrans Assets acquired in July 2024. Please refer to the Equitrans 2024 Greenhouse Gas Emissions Supplemental Report to review the GHG emissions from Equitrans Assets. Emissions from these assets will be included in company totals for 2025 after EQT has operated them for a full calendar year.

We calculate and report our Scope 1 GHG emissions in accordance with Subpart W (Petroleum and Natural Gas Systems) of the EPA’s GHG Reporting Program. Pursuant to the EPA’s rules and regulations, emissions are reported according to defined “industry segments” as opposed to a single set of emissions at the operator level. The EPA’s reporting framework for petroleum and natural gas companies identifies five industry segments: Production, Gathering and Boosting, Processing, Transmission and Storage, and Distribution. Most of our operations for the EQT, Alta, and Tug-XcL Assets (and our Scope 1 GHG emissions) fall within the Production segment. Certain operations from those assets generate emissions that are disclosed as emissions from the Gathering and Boosting segment. Further, beginning in 2024, we reported emissions with the Transmission and Storage segment for the applicable midstream operations for the acquired Equitrans Assets. We have no reportable emissions within Subpart W’s Processing or Distribution segments.^[1] The GHG emissions shown below are the total Scope 1 values before offsets are applied.

Scope 1 GHG Emissions (MT CO₂e)^[2], ^[3]

2024 Scope 1 Emissions Sources (MT CO₂e)^[4]

We began to track and calculate our Scope 2 GHG emissions using the location-based method^[10] in 2020. We use the EPA Emissions & Generation Resource Integrated Database’s state emission factors for our operating areas. Our Scope 2 emissions increased in 2024 due to increased electricity usage at our Clearfork Processing Plant.

Scope 2 GHG Emissions (MT CO₂e)^[11]

We began efforts to understand and track our Scope 3 GHG emissions in 2020 by calculating our indirect emissions within all 15 Scope 3 categories. Once calculated, we then conducted a materiality assessment to determine which of the categories were material to our stakeholders’ understanding of our Scope 3 emissions impact. The findings identified category 11, Use of Sold Products, as the primary source of our indirect emissions. As such, we report only category 11 Scope 3 emissions. In 2025, we plan to finalize an updated Scope 3 materiality assessment to determine if additional Scope 3 categories may be material following the acquisitions completed in 2021–2024.

It is important to note that Scope 3 emissions estimates are subject to uncertainty, inconsistency, and duplication due to the reporting of assets outside the control of the reporting company and various reporting and calculation methodologies. In addition, two or more companies will account for the same emissions within their Scope 1, 2, or 3 emission inventories. As an exploration, production, and midstream company, we have no direct control over how the natural gas and natural gas liquids (NGLs) we produce, transport, and sell are ultimately consumed.

Scope 3 GHG Emissions (MT CO₂e)^[14]