Environmental

Operational
GHG Emissions

What We Are Doing

Our emissions vary based on the type and amount of field activity conducted at any given time and, therefore, also vary on an annual basis. We review our Scope 1 emissions inventory on a source-by-source basis to determine areas of opportunity and to monitor our overall impact.

Our Scope 1 emissions primarily originate from our operations and fleet transportation. Fuel combustion is one of the largest contributors to our Scope 1 emissions and, as a result, we have dedicated significant resources to improving our processes and equipment. We have electrified many of our water pumps with natural gas rather than relying on diesel and are pursuing utility power for sites where we are unable to transition our water pumps from diesel to natural gas. Read more about how we are reducing emissions associated with our water-movement activities in Water.

Our primary emissions reduction activities include the following:

Our focus on implementing innovative technologies, best management practices, and aligned policies over the past several years has directly resulted in decreasing our GHG and methane emissions intensity. We regularly review technologies to determine whether they can cost-effectively reduce our emissions in the short-term. For example, by implementing new data management technologies, we identified pneumatic devices as a significant source of our GHG and methane emissions and, correspondingly, in a period of just 18 months we developed and successfully executed a plan to replace our natural gas-powered pneumatic devices, significantly reducing our GHG and methane emissions.

Natural Gas-Powered Pneumatic Device Replacement Program

We use pneumatic level switches and liquid level controllers 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/liquid separation volumes or activate shutdowns when high or low liquid levels occur.

Compressed air, natural gas, nitrogen, electricity, or other supply media can power pneumatic level switches and liquid level controllers, but natural gas is the most common power source for these devices within the natural gas industry. The U.S. Environmental Protection Agency (EPA) classifies natural gas pneumatic level switches and liquid level controllers into three categories — continuous high-bleed, continuous low-bleed, and intermittent-bleed. High-bleed pneumatic controllers are significant sources of methane emissions when compared to low-bleed or intermittent-bleed controllers.^[1] Replacement of a high-bleed controller with a low-bleed or intermittent-bleed controller results in a reduction of GHG emissions by approximately 96% and 64%, respectively.^[2] As of December 31, 2022, we did not operate any high-bleed pneumatic controllers.

In 2022, we completed the replacement or retrofit of nearly 9,000 natural gas-powered pneumatic devices on all our production locations and compressor stations through a “fit-for-purpose” technology strategy. Pneumatic actuators were replaced with electric actuators and natural gas supply was replaced with air through compressor installations. As part of this initiative, we installed 341 air compressors and retrofitted 451 dump assemblies and 381 motor valves to electric actuators. The entire conversion process took 515 days and was completed one year ahead of our planned schedule. Execution of the program took nearly 23,000 work-hours. The completion of this project represents a substantial step forward in achieving our emissions goals, considering that approximately 47% of our 2021 Production segment Scope 1 GHG emissions came from natural gas-powered pneumatic devices.^[3]

We replaced or retrofitted approximately 9,000 pneumatic devices in 18 months, 1 year ahead of schedule

Elimination of Natural Gas-Powered Pneumatic Devices Complete

Replacing natural gas-powered pneumatic devices represents a meaningful opportunity for reducing methane emissions within the oil and natural gas production industry. It is estimated that the U.S. oil and natural gas production sector currently deploys more than 1 million natural gas-driven pneumatic devices. 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 pneumatic device replacement program was approximately $28 million, which equates to a carbon abatement cost of approximately $6 per ton.^[4] We also published a whitepaper highlighting our research and findings on developing and implementing a pneumatic device replacement program so that other operators can leverage our experience and implement this process in their own operations.

Leak Detection and Repair (LDAR) Program

Our investment in LDAR surveys has been one of the most significant investments we have made to reduce emissions releases. Going beyond compliance with robust state and federal requirements on air emissions, our LDAR program involves the following:

Our standard practice exceeds state and federal requirements related to leak repair procedures and we routinely upgrade our management system to better track leak repairs at our sites. In 2022, no repairs were delayed beyond the applicable regulatory limits and approximately 30% of all leaks detected in our production operations were immediately repaired. Over 97% of all leaks detected in our production operations were repaired within the first 15 days of leak detection. We identified approximately 97% more leaking components in 2022 than in 2021, which was attributable to a significant increase in the number of OGI surveys we conducted in 2022.

Leak Detection and Repair Metrics^[5]

Venting/Flaring Practices

Typically, there are two phases in the development of a well when venting and flaring may occur, 1) drilling and completions, and 2) production. Our completions operations involve the process of making a well ready for production after the well is drilled. During the completions phase, fluids are injected into the well at high pressure – a process known as hydraulic fracturing – to create fissures in the underground shale formation. As the well is hydraulically fractured, “plugs” composed of fiberglass and carbon fiber composite material are installed in the wellbore to segment the wellbore and maintain pressure to prevent the premature release of hydrocarbons from the well. After the hydraulic fracturing process is completed, the plugs are removed by circulating produced water in the wellbore. As this water comes out of the well, it may contain small amounts of entrained gas. On average, 500 thousand cubic feet (Mcf) of entrained gas is released from the well in connection with our completion activities. The volume of entrained gas is too small to be sent to sale, and it cannot be stored because of the risk of explosion. Instead of venting the entrained gas, we utilize a closed loop system, pursuant to which any entrained gas is separated from the liquid used to complete the well, and the gas is then directed to a flare where it is combusted.

Following the completions phase, a well can begin producing hydrocarbons. During the production phase of a well, our flaring and venting practices differ based on the amount of condensate and oil produced. Generally, the industry considers a “dry gas” well to be a well that produces water, methane, and ethane but not significant natural gas liquids, condensate, or oil. A well that consistently produces natural gas in addition to condensate and/or oil is considered a “wet gas” well. Dry gas wells generally have significantly lower emissions when compared to wet gas wells and require fewer emissions controls. Most of the wells we operate are dry gas wells and no gas is flared in connection with production from these wells. To minimize flaring at our wet gas wells, we use various methods of emissions minimization including closed-vent systems with low-pressure separators, vapor recovery systems, and vapor destruction units (VDUs).

We leverage best management practices for the installation of pilot-operated valves and latch-down hatches on closed-vent systems, including the installation of low-pressure separators with vapor recovery systems during periods of high production. The valves, hatches, and additional separators have significantly improved sealing, reduced leaks, and allowed us to standardize the installation of latch-down hatches on all new installations. We also conduct quarterly LDAR inspections at all our operated well sites.

Well Unloading

As a natural gas well ages, “liquid loading” occurs where liquids — primarily water — accumulate in the wellbore. These liquids create backpressure that restricts or stops the gas flow. To restore productivity, multiple approaches can be used to unload the fluid from the wellbore; the simplest is to flow the well to a lower-pressure environment, such as an atmospheric tank. As part of our ongoing efforts to minimize emissions, we follow guidance from The Environmental Partnership to reduce methane emissions from well unloading.

If a well only produces through production casing, we install tubing to reduce flow area and to allow the produced gas from the well to efficiently unload the fluid. We install well tubing on an accelerated schedule to limit the amount of venting that occurs from well unloading activities, thus reducing the amount of methane emissions. We further minimize tank venting by using automated plunger lift equipment in wells with tubing and, where this is not possible, we use a swab rig to mechanically remove fluids from a well to restore flow. In 2022, we began the use of trailer mounted compressors as an alternative to traditional swabbing and/or tank venting, which allows for gas to be produced while unloading rather than being vented to an atmospheric tank. For unconventional wells, we have personnel onsite while unloading wells. We follow the industry best practice of installing plunger lifts one to three years into a well’s life. Each of these methods helps to reduce our emissions associated with the removal of liquids from our wells.^[6]

Dehydration Units

To reduce methane emissions during production operations when transferring rich and lean glycol, we use chemical exchange pumps and electric-driven pumps rather than natural gas-powered pneumatic pumps on our dehydration systems. Unlike natural gas-powered pneumatic pumps, electric-driven pumps emit no methane from their operation. Chemical exchange pumps only emit gas embedded within the glycol and are not powered by natural gas pressure, which results in less methane emitted than would otherwise be produced by a comparable natural gas-powered pneumatic pump. Methane emissions from our chemical exchange pumps are sent to a vapor destruction unit, where the methane is combusted. Additionally, our standard protocol is to install condensers on new dehydration regenerator still columns to further minimize emissions. These units condense volatile liquid organics out of the gas and vapor streams collecting marketable natural gas liquids and minimizing odors and emissions. The resulting emissions are sent to a vapor destruction unit.

Electrifying Our Fracturing Fleets

As described in Air Quality, we have transitioned substantially all our fracturing (frac) fleets from diesel to electric, powered by a natural-gas-fired turbine using EQT-produced natural gas. We project that the implementation of these next-generation electric frac fleets have eliminated over 20 million gallons of diesel fuel consumption from our operations annually. The electrification of our frac fleets also decreases our emissions due to the corresponding reduction in vehicle use that would otherwise be needed to deliver diesel fuel to our well pads. We project that the implementation of electric frac fleets has reduced our annual carbon footprint by approximately 35,000 MT of CO₂e.

Transportation

We have operations in multiple states, requiring reliance on trucks and other fleet vehicles for the transportation of workers and materials to job sites. Our vehicles drive millions of miles annually and we actively pursue efficient, cleaner-burning alternatives — such as compressed natural gas — for our vehicles. In addition to reducing our fleet size, we continue to utilize newer, fuel-efficient, and technology-enabled vehicles to reduce total vehicle miles and associated emissions. We continue to consider efficiency improvements to our fleet. Read more about our transportation improvements in Water.

[1] Source: https://www.law.cornell.edu/cfr/text/40/appendix-Table_W-1A_to_subpart_W_of_part_98.

[2] Metrics only include OGI survey data.

[3] Includes emissions from EQT's historical assets, as well as emissions from the Chevron Assets and the Alta Assets.

[4] Calculated as follows: $28,000,000 / (305,614 MT CO₂e pneumatic related emissions per year × 15 years) = ~$6 per metric ton of CO₂e.

[5] Metrics only include OGI survey data.

[6] Source: U.S. EPA Office of Air Quality Planning and Standards (OAQPS), Oil and Natural Gas Sector Liquids Unloading Processes, April 2014 (https://www.ourenergypolicy.org/wp-content/uploads/2014/04/epa-liquids-unloading.pdf).

How We Are Doing

GHG Emissions and Targets

We monitor and report on operational air emissions as required by state and federal regulations. We gather operational data and report emissions annually in accordance with 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. Pennsylvania recently enacted methane-limiting regulations for conventional and unconventional wells. 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 are broken into three categories or “scopes.”

• Scope 1 emissions are direct GHG emissions from sources we own or control.
• Scope 2 emissions are GHG emissions from the generation of purchased electricity consumed in connection with our operations.
• Scope 3 emissions are all other indirect GHG emissions as a result of 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.

Scope 1 GHG Emissions

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 (and consequently our Scope 1 GHG emissions) fall within the Production segment.

We own an insignificant amount of midstream assets and the emissions from these assets are disclosed as emissions from the Gathering and Boosting segment. We have no emissions within the Processing, Transmission and Storage, or Distribution segments.

Scope 1 GHG Emissions (MT CO₂e)^[1]

2022 Scope 1 Emissions Sources (MT CO₂e)^[2]

Scope 2 GHG Emissions

We began tracking our Scope 2 GHG emissions (i.e., indirect GHG emissions from purchased electricity to power certain aspects of our operations) in 2020. A third-party entity, typically a utility, generates these emissions at their facility.

The two prevailing methods for calculating Scope 2 GHG emissions are the market-based method and the location-based method. Under the market-based method, Scope 2 emissions are calculated based on the reporting company’s contracts with electric utilities. Under the location-based method, Scope 2 emissions are calculated based on the average emissions intensity of the reporting company’s local power grid. We use the location-based method to calculate our Scope 2 emissions, utilizing the EPA Emissions & Generation Resource Integrated Database’s state emission factors for our operating areas.

Scope 2 GHG Emissions (MT CO₂e)^[8]

Scope 3 GHG Emissions

We began efforts to track and understand our Scope 3 GHG emissions (i.e., other indirect emissions) in 2020. There are 15 categories of Scope 3 emissions. To fully understand our Scope 3 emissions, we calculated our Scope 3 emissions within all 15 categories during 2020. We then conducted a materiality assessment to determine which of the 15 categories are material to helping our stakeholders understand our Scope 3 emissions impact; most of our Scope 3 emissions are generated from category 11 (Use of Sold Products). As such, we report only Scope 3 emissions from category 11.

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 and production company, we have no direct control over how the natural gas and NGLs we produce and sell are ultimately consumed.

Scope 3 GHG Emissions (MT CO₂e)^[9]

GHG Emissions Targets

As discussed in Climate Change Strategy, the "Evolve" aspect of our strategy focuses on realizing the full potential of our current asset base. The purpose of evolution is to differentiate us by distinguishing our capabilities from those of our peers. In line with that focus, we have set short-term and medium-term goals for our Production segment operations to keep us on track.^[10]

We are planning to achieve our goal of net-zero Scope 1 and Scope 2 Production segment GHG emissions by or before 2025 primarily through operational improvements. Through 2022, we have already made noteworthy progress in our efforts toward achieving our net-zero goal, including reducing our EQT Production segment Scope 1 and 2 GHG emissions to 433,450 MT of CO₂e — a 19.8% reduction compared to 2021.

In 2022, we continued to advance our proprietary emissions model that allows us to track our real-time emissions at the well level and by emissions source which enables us to project our emissions up to seven years into the future. This detailed data allows us to more accurately make capital allocation decisions that maximize both the environmental and financial impacts of our emissions initiatives. For instance, based on the data derived from our emissions model, we determined that a substantial portion of our Scope 1 emissions are generated from pneumatic devices, as discussed in What We are Doing. With this information, we developed and executed a plan to replace all the natural gas-powered pneumatic devices utilized in our production operations over a span of 18 months. The completion of this initiative is projected to reduce our annual carbon footprint by over 300,000 MT of CO₂e.^[11] This would not have been possible without the advanced detailed emissions data and analytics derived from our proprietary emissions model.

While we are already operating at an industry-leading emissions intensity level — in part driven by prior adoption of emissions-limiting operational technologies like electric frac crews and hybrid drilling rigs — we fully anticipate additional opportunities for operational improvements beyond our pneumatic device replacement initiative, albeit of a lesser impact, to contribute to achieving our net-zero goal.

When making capital allocation decisions for our emissions reduction initiatives, we prioritize projects that will support actual emissions reductions versus emissions reported pursuant to EPA guidance. For example, internal research shows that actual annual emissions attributable to pneumatic devices during the first two 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.^[12] As such, when we initiated our pneumatic device replacement program, we began by targeting all new development and all sites within their first two years of production. Ultimately, our goal is to reduce actual emissions, not “desktop” emissions.

Further to that end, we are actively developing plans to increase our usage of next-generation monitoring technologies across a broader portion of our asset base. While we already employ leading practices in detection, we are driven to constantly improve our ability to identify and quickly address potential emissions incidents. In 2022, we began implementing aerial methane surveys completed with a Light Detection and Ranging (LiDAR) remote sensing technology. Additionally, as a demonstration of this commitment, in 2022 we continued our participation in the Oil and Gas Methane Partnership 2.0 (OGMP 2.0), which is a Climate and Clean Air Coalition 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. In 2022, we were awarded a “Gold Standard” rating by OGMP 2.0, the highest reporting level under the initiative, in recognition of our ambitious methane emissions reduction targets and advanced commitment to accurately measuring, reporting, and reducing company-specific and site-level methane emissions. We are among a mere 14 upstream companies globally qualifying as “Gold Standard” under OGMP 2.0 for 2022.

While we prioritize emissions reduction opportunities versus generating offsets and purchasing credits, offset generation comprises part of our plan to achieve net-zero Scope 1 and Scope 2 GHG emissions by or before 2025. Given the varying maturity of technologies underpinning offset generation opportunities, we are contemplating principally relying on more proven offset opportunities — such as land management and biological carbon sequestration initiatives — to help us achieve our net-zero goals. We plan to leverage our relationships with landowners to execute land-based carbon sequestration opportunities organically.

We are continuing to develop and grow our Land Based Carbon Credit Program. In 2022, we partnered with Teralytic — the producer of the world’s first wireless Nitrogen, Phosphorous, and Potassium sensor — to track our carbon sequestration efforts with remote data sensors. Through strong commercial relationships with landowners, and new strategic partnerships, these resources have a high potential to support our carbon sequestration efforts, which we believe will be the ultimate step in enabling us to achieve our net-zero goal by, or before, 2025.

Additionally, while our net-zero target does not include our Scope 3 emissions, we are exploring ways to meaningfully affect the emissions impact from the use of our products. Our recent technological and cultural transformation has instilled across our organization the mentality, approach, and nimbleness necessary to adapt in dynamic environments. These changes have been intentional and were pursued in part to allow us to evolve. We do not believe that setting a net-zero Scope 3 emissions target currently is the optimal manner for us to contribute to an acceleration of a sustainable pathway to a low-carbon future. Read more about our approach in Climate Change Strategy.

We believe these goals provide the right prioritization and targets to guide our strategy and decision‑making throughout the company, will continue to position us as a leader in the energy industry, and will accelerate a sustainable pathway to a low-carbon future.

[1] We are subject to the methodologies for reporting GHG emissions under Subpart W (Petroleum and Natural Gas Systems) of the EPA’s GHG Reporting Program. We calculate our Scope 1 GHG emissions using EPA calculation guidelines under 40 Code of Federal Regulations Part 98. Notably, there are certain sources of emissions which are not reported to the EPA, either because the amount of emissions does not satisfy the minimum reporting threshold or because the EPA does not require emissions from the particular source to be reported. In 2022, we conducted peer and industry benchmarking analysis of ESG reporting trends and determined that the industry standard is to report Scope 1 emissions in alignment with the EPA’s Subpart W. Based on this analysis, we restated our historical (2018 – 2021) Scope 1 GHG emissions and GHG emissions intensities to align with the emissions we report to the EPA under Subpart W. Unless otherwise noted, the Scope 1 GHG emissions disclosed throughout our ESG Report include only our EPA Subpart W emissions, and thus, in some cases there may be additional sources of Scope 1 GHG emissions that are not reflected because they are not required to be reported to the EPA under Subpart W.

[2] Scope 1 emissions are converted to CO₂e for comparability. The gasses included in this conversion are CO₂, CH₄, and N₂O. Data provided in the table reflects emissions reported to the EPA under Subpart W. In 2022, we also had emissions from certain combustion sources that are not required to be reported to the EPA under Subpart W. Such non-Subpart W combustion emissions for 2022 were as follows: (i) EQT Production segment: 37,172 MT CO₂e; (ii) Alta Assets Production segment: 98,116 MT CO₂e; (iii) EQT Gathering and Boosting segment: 824 MT CO₂e; (iv) Alta Assets Gathering and Boosting segment: 3,394 MT CO₂e.

[3] Combustion emissions: Combustion emissions include emissions from our diesel and natural gas drill rigs, completion engines, stationary engines, and generators.

[4] Process emissions: Process emissions originate from our glycol and desiccant dehydrators.

[5] Other vented emissions: Other vented emissions include emissions from our storage tanks, reciprocating compressors, well liquid unloading operations, pneumatic controllers, and pneumatic pumps.

[6] Fugitive emissions: Fugitive emissions include equipment leak surveys, and population count emissions.

[7] Flared hydrocarbons: Flared hydrocarbons emissions include emissions from vapor destruction units.

[8] Given the timing of the closing of the Chevron Acquisition in the fourth quarter of 2020, our 2020 Scope 2 emissions do not include possible indirect emissions associated with the Chevron Assets. 2021 and 2022 EQT Scope 2 emissions include indirect emissions associated with the Chevron Assets. Scope 2 emissions from the Alta Assets have been disclosed separately as noted in the table.

[9] 2020 Scope 3 emissions include only indirect emissions from EQT's operations and exclude possible indirect emissions associated with the Chevron Assets. 2021 and 2022 Scope 3 emissions include indirect emissions from EQT's operations as well as the Chevron Assets and the Alta Assets. We report our category 11 Scope 3 emissions by calculating combustion emissions from the natural gas and NGLs (including ethane) we produce and sell using emission factors obtained from the EPA. Beginning in 2022, we began to calculate our category 11 Scope 3 emissions based on the natural gas and NGLs sales volumes reported in our Annual Report on Form 10-K, which we believe to be the industry standard approach based on benchmarking we conducted in 2022. For purposes of this calculation, we assume that all the natural gas and NGLs we sell are combusted. We assume that the limited volume of oil we produce and sell is processed, and thus, our oil sales are included in category 10 (Processing of Sold Products), rather than category 11.

[10] Net-zero and GHG emissions intensity targets are based on assets owned by EQT on June 30, 2021, and thus, exclude emissions and production from the Alta Assets. Methane emissions intensity target includes emissions and production from the Alta Assets. Scope 1 emissions included in the net-zero and GHG emissions intensity targets are based exclusively on emissions reported to the EPA under the EPA’s Greenhouse Gas Reporting Program (Subpart W) for the onshore petroleum and natural gas production segment. Methane emissions intensity, and corresponding 2025 methane emissions intensity target, is calculated in accordance with the methodology maintained by ONE Future.

[11] Emissions reduction projections are based on anticipated abated emissions from EQT's historical assets, as well as the Alta Assets and the Chevron Assets. Due to how emissions from pneumatic devices are calculated under Subpart W, the full effect of the emissions reduction from our pneumatic device replacement program will not be reflected in our annual emissions until we report emissions for calendar year 2023. Additionally, while we replaced 100% of the natural gas-powered pneumatic devices utilized in our production operations as of December 31, 2022, we may from time to time reinstitute the use of natural gas-powered pneumatic devices in temporary situations, particularly in remote locations and while servicing or fixing non-natural gas-powered pneumatic devices used at our sites. The ultimate reduction of GHG and methane emissions from our pneumatic device replacement program will therefore fluctuate depending on the number and length of time of use of such temporary natural gas-powered pneumatic devices.

[12] We presented these findings to the EPA in November 2020 in part to assist in their analysis on how to best tackle pneumatic device emissions.