Environmental

Operational
GHG Emissions

As a part of our corporate Climate Change Strategy, we pursue new ventures that have the potential to accelerate the path to a lower-carbon future. We focus on the implementation of innovative technologies, best management practices, and aligned policies, which, over the past several years, has directly resulted in decreased GHG and methane emissions intensities. In 2023, we launched a partnership with Wheeling Park Commission, Teralytic, a soil analytics company, and Climate Smart Environmental Consulting, LLC, to implement forest management projects that span more than 1,000 acres of forest land at Oglebay and other Wheeling Park Commission properties. This partnership will supplement our ongoing emissions reduction efforts by reducing or removing carbon dioxide (CO₂) emissions from the atmosphere, which acts as a carbon offset to our operational emissions. We plan to utilize Teralytic’s soil probe technology to ensure the quantification of offsets we generate are accurate and transparent, in alignment with the U.S. Department of Agriculture’s Natural Resource Conservation Service’s Conservation Practice Standards and Verra guidelines.

Through strong commercial relationships with landowners, resources like Teralytic’s soil probe technology have a high potential to support our carbon sequestration efforts and grow our Land-Based Carbon Credit Program, which we believe will be the ultimate step in enabling us to achieve our net-zero goal by 2025.

We use pneumatic level switches and liquid level controllers^[6] 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, 2023, we do not operate any permanent or temporary high-bleed pneumatic controllers.

In 2022, we completed our Natural Gas-Powered Pneumatic Device Replacement Program, which replaced or retrofitted nearly 9,000 natural gas-powered pneumatic devices on all our production locations and compressor stations through a “fit-for-purpose” technology strategy. The completion of this project represents a substantial step forward toward our emissions goals, and was responsible for a 32% decrease in our 2023 GHG emissions.^[7]

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.^[8] 

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

• Use of optical gas imaging (OGI) technology at all compressor stations, dehydration facilities, and well sites to conduct LDAR surveys and mechanical integrity inspections of conventional wells to inspect leaks on a quarterly basis;
• Operation of gas detection cameras by a certified team of 15 EQT employees who have completed a 3-day training course that consists of classroom and onsite experience with OGI experts;
• Use of three types of OGI cameras, all verified by the manufacturer to meet the U.S. Environmental Protection Agency’s (EPA) LDAR requirements under the EPA’s New Source Performance Standards for the Oil and Natural Gas Industry;
• Annual auditory, visual, and olfactory inspections for each of our conventional wells;
• Remote gas detection monitors inside the gas processing units of our unconventional wells that monitor for leaks in real time and automatically alert our gas control center to assign a specialist to conduct an inspection when necessary;
• Use of fixed gas monitors in each separator housing, which identify leaks in real time and automatically alert our gas control center to assign a specialist for a follow-up inspection; and
• Leak repairs conducted as soon as reasonably possible.

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. Additionally, we implemented an initiative beginning in the fourth quarter of 2022 to survey each of our sites using OGI cameras on a quarterly basis. This led to an over four times increase in the total number of OGI surveys we conducted during 2023 as compared to the prior year. In 2023, no repairs were delayed beyond the applicable regulatory limits and approximately 36% of all leaks detected in our production operations were immediately repaired. While we identified approximately 121% more components with leaks in 2023 than in 2022, this was directly attributable to the significant increase in the number of OGI surveys we conducted during the year, and in fact, the number of components with leaks in relation to the number of surveys conducted decreased year-over-year by nearly 50%.

Leak Detection and Repair Metrics^[9]

Typically, venting and flaring may occur in two phases in the development of a well: 1) drilling and completions, and 2) production.

Our completions operations involve the process of preparing a well 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” comprised of fiberglass and carbon fiber composite material are installed in the wellbore to segment the wellbore and maintain pressure. These plugs 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. This water may contain small amounts of entrained gas^[10] when extracted from the well. On average, completion activities release 500 thousand cubic feet of entrained gas per well. The volume of entrained gas is too small to be sold, and it cannot be stored because of the risk of explosion. Instead of venting the entrained gas, we use a closed loop system that separates the gas from the liquid and directs it to a flare where it is combusted.

Following the completions phase, a well can begin producing hydrocarbons. We conduct quarterly LDAR inspections at all our operated well sites. However, during the production phase of a well, our flaring and venting practices differ based on the amount of condensate and oil produced. Most of the wells we operate are dry gas wells,^[11] which have significantly lower emissions compared to wet gas wells and require fewer emissions controls. EQT does not flare gas in connection with production from these wells.

To minimize flaring at our wet gas wells,^[12] we use various methods of emissions minimization including closed-vent systems with low-pressure separators, vapor recovery systems, and vapor destruction units (VDUs). We use 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. 

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 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; this reduces the amount of methane emissions. We further minimize tank venting by using automated plunger lift equipment or foamer injection slipstreams 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 2023, we began utilization of a zero emissions swab rig, which eliminated the venting of methane during swabbing. In 2022, we began the use of trailer-mounted compressors as an alternative to traditional swabbing and tank venting and in 2023 we added a third unit to our fleet. The trailer-mounted compressors allow gas production while unloading rather than ventilation to an atmospheric tank. For unconventional wells, we have personnel onsite while unloading wells. We follow the industry best practice of installing plunger lifts 1 to 3 years into a well’s life. Each of these methods helps to reduce our emissions associated with the removal of liquids from our wells.^[13]

To reduce methane emissions during production operations when transferring rich and lean glycol, we use chemical exchange 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 VDU, 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 and collect marketable natural gas liquids and minimize odors and emissions. The resulting emissions go to a VDU.

We operate in multiple states and rely on trucks and other fleet vehicles to transport 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 reduction of our fleet size and the transition of  most of our fracturing (frac) fleets from diesel to electric, we continue to use 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 frac fleet transition in Air Quality and other transportation improvements in Water.

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.
• 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.

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 our Scope 1 GHG emissions) fall within the Production segment. However, we also own certain midstream assets, and the emissions from such assets are disclosed as emissions from the Gathering and Boosting segment. We have no reportable emissions within Subpart W’s Processing, Transmission and Storage, or Distribution segments.^[1]

Scope 1 GHG Emissions (MT CO₂e)^[2]

2023 Scope 1 Emissions Sources (MT CO₂e)^[3] 

We began to track and calculate our Scope 2 GHG emissions using the location-based method^[9] in 2020. We use the EPA Emissions & Generation Resource Integrated Database’s state emission factors for our operating areas.

Scope 2 GHG Emissions (MT CO₂e)

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.

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)^[12]

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 line with that focus, we have set short- and medium-term goals for our Production segment operations to keep us on track to achieve our goal of net-zero Scope 1 and Scope 2 Production segment GHG emissions by 2025.^[13]

We intend to achieve these goals primarily through operational improvements. Through 2023, we continued to make noteworthy progress, including reducing our EQT Production segment Scope 1 and Scope 2 GHG emissions to 280,824 MT CO₂e — a 35% reduction compared to 2022, and reducing our EQT Production segment Scope 1 GHG emissions intensity to 152 MT CO₂e/Bcfe — beating our 2025 GHG emissions intensity target a full year ahead of our goal.

When we make capital allocation decisions for our emissions reduction initiatives, we prioritize projects that support actual emissions reductions versus emissions reported per 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.^[14] As such, when we initiated our pneumatic device replacement program in 2022, 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.

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 quickly find and address potential emissions incidents.

While we prioritize emissions reduction opportunities over generation of offsets and purchase of credits, offset generation comprises part of our plan to achieve net-zero Scope 1 and Scope 2 GHG emissions by 2025. Given the varying maturity of technologies that underpin 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. See New Ventures for details on our recent carbon offset and sequestration initiatives.