Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.

We believe that the principal risks associated with our business, and consequently the principal risks associated with an investment in our equity or debt securities, generally fall within the following categories:

We describe these risks in greater detail under Item 1A., "Risk Factors."

This Annual Report on Form 10-K contains certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and are usually identified by the use of words such as "anticipate," "estimate," "could," "would," "will," "may," "forecast," "approximate," "expect," "project," "intend," "plan," "believe" and other words of similar meaning, or the negative thereof, in connection with any discussion of future operating or financial matters.thereof. Without limiting the generality of the foregoing, forward-looking statements contained in this Annual Report on Form 10-K include the matters discussed in sections "Strategy" and "Outlook" in Item 1., "Business," the section "Trends and Uncertainties" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations",Operations," and the expectations of our plans, strategies, objectives and growth and anticipated financial and operational performance, including guidance regarding our strategy to develop our reserves; drilling plans and programs, including availability of capital to complete these plans and programs; total resource potential and drilling inventory duration; projected production and sales volume, including liquified natural gas (LNG) volumes and growth rates;sales; natural gas prices; changes in basis and the impact of commodity prices on our business; potential future impairments of our assets; projected well costs and capital expenditures; infrastructure programs; the cost, capacity and timing of obtaining regulatory approvals; our ability to successfully implement and execute our operational, organizational, technological and ESG initiatives, and achieve the anticipated results of such initiatives; projected gathering and compression rates; potential acquisition transactionsacquisitions or other strategic transactions, the timing thereof and our ability to achieve the intended operational, financial and strategic benefits from any such transactions including the Tug Hill and XcL Midstream Acquisition (defined in Note 6 to the Consolidated Financial Statements);or from any recently completed strategic transactions; the amount and timing of any repayments, redemptions or repurchases of our common stock, outstanding debt securities or other debt instruments; our ability to retire our debt and the timing of such retirements, if any; the projected amount and timing of dividends; projected cash flows and free cash flow, and the timing thereof; liquidity and financing requirements, including funding sources and availability; our ability to maintain or improve our credit ratings, leverage levels and financial profile; our hedging strategy and projected margin posting obligations; the effects of litigation, government regulation and tax position; and the expected impact of changes to tax laws.

The forward-looking statements included in this Annual Report on Form 10-K involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. We have based these forward-looking statements on current expectations and assumptions about future events, taking into account all information currently known by us. While we consider these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, many of which are difficult to predict and beyond our control. TheThese risks and uncertainties that may affect the operations, performance and results of our business and forward-looking statements include, but are not limited to, those set forth in Item 1A., "Risk Factors" in this Annual Report on Form 10-K, and other documents we file from time to time with the SEC.

We are a natural gas production company with operations focused in the Marcellus and Utica Shales of the Appalachian Basin. BasedAs of December 31, 2023, we had 27.6 Tcfe of proved natural gas, NGLs and oil reserves across approximately 2.1 million gross acres, and, based on average daily sales volume, we arewere the largest producer of natural gas in the United States. As of December 31, 2022, we had 25.0 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 2.0 million gross acres, including approximately 1.8 million gross acres in the Marcellus play.

We are committed to responsibly developing our world-class asset base and being the operator of choice for all stakeholders. By promoting a culture that prioritizes operational efficiency, technology, sustainability and sustainability,safety, we seek to continuously improve the way we produce environmentally responsible, reliable low-cost energy. We measure sustainability through consideration of our best-in-class team and culture, ESG-focusedthe ESG performance of our operations, our substantial inventory of core drilling locations and strongour investment grade balance sheet. We believe that the scale and contiguity of our acreage position differentiates us from our Appalachian Basin peers and that our evolution into a modern, digitally-enabled exploration and production business enhances our strategic advantage.

Our operational strategy focuses on the successful execution of combo-development projects. Combo-development refers to the development of several multi-well pads in tandem. Combo-development generates value across all levels of the reserves development process by maximizing operational and capital efficiencies. In the drilling stage, rigs spend more time drilling and less time transitioning to new sites. Advanced planning, a prerequisite to pursuing combo-development, facilitates the delivery of bulk hydraulic fracturing sand and piped fresh and recycled water (as opposed to truck-transported water), and provides the ability to continuously meet completions supply needs and the use of environmentally friendly technologies. Operational efficiencies realized from combo-development are passed on to our service providers, which reduces overall contract rates.

The benefits of combo-development extend beyond financial gains to include environmental and social interests. We have developed an integrated ESG program that interplays with our combo-development-driven operational strategy. Core tenets of our ESG program include investing in technology and human capital; improving data collection, analysis and reporting; and engaging with stakeholders to understand, and align our actions with, their needs and expectations. Combo-development, when compared to similar production from non-combo-development operations, translates into fewer trucks on the road, decreased fuel usage, shorter periods of noise pollution, fewer areas impacted by midstream pipeline construction and shortened duration of site operations, all of which fosters a greater focus on safety, environmental protection and social responsibility.

We believe that combo-development projects are key to delivering sustainably low well costs and higher returns on invested capital. Our business model has been developed to enable us to generate sustainable free cash flow and correspondingly, we have implemented a robust capital allocation strategy directed at responsibly developing our assets while also returning capital to our shareholders through a combination of debt retirements, dividends and strategic share repurchases, and debt retirements.repurchases. We are also focused on maintaining investment grade credit metrics, which allows us to capture a lower cost of capital and further enhance shareholder returns.

Our strategy, and combo-development projects in particular, requires significant advanced planning, including the establishment of a large, contiguous leasehold position; the advanced acquisition of regulatory permits and sourcing of fracturing sand and water; the timely verification of midstream connectivity; and the ability to quickly respond to internal and external stimuli. Without a modern, digitally-connected operating model or an acreage position that enables operations of this scale, combo-development would not be possible. Furthermore, we believe the benefits of our operating model can be magnified through select strategic transactions, and part of our strategy includes creating value through mergers and acquisitions, divestitures, joint ventures and similar business transactions, as well as investing in energy transition opportunities directed at complementing, and in certain cases diversifying, our core business operations.

We believe that our proprietary digital work environment, in conjunction with the size and contiguity of our asset base, uniquely position us to execute on a multi-year inventory of combo-development projects in our core acreage position. Our operational strategy employs this differentiation to advance our mission of being the operator of choice for all stakeholders, while simultaneously helping to address energy security and affordability both domestically and globally.

In 2023,2024, we expect to spend approximately $1.7$2.15 billion to $1.9$2.35 billion in total capital expenditures, excluding amounts attributable to noncontrolling interests and acquisitions.expenditures. We expect to allocate the total planned capital expenditures as follows: approximately $1,400$1,685 million to $1,535$1,775 million to fund reserve development, approximately $120$220 million to $140$250 million to fund midstream and other infrastructure, approximately $125 million to $190 million to fund land and lease acquisitions, approximately $125 to $160$70 million to fund$80 million towards capitalized overhead and approximately $50 million to $55 million towards capitalized interest and other productionitems. Included in total planned capital expenditures is approximately $200 million to $300 million for strategic growth projects composed of approximately $70 million to $90 million for water infrastructure within reserve development, approximately $50 million to $70 million for growth projects within midstream and other infrastructure and approximately $55$80 million to $65$140 million applied towards capitalized overhead.for in-fill leasing and mineral purchases within land and lease acquisitions. In 2023,2024, we expect our sales volume to be 1,9002,200 Bcfe to 2,000 Bcfe, excluding amounts attributable acquisitions.2,300 Bcfe.

We are committed to maintaining investment grade credit metrics, and we have a goal to retire at least $4.0reduce our absolute debt to $3.5 billion, of our debt between January 1, 2022 and December 31, 2023, subject to the occurrence and timing of the closing of the Tug Hill and XcL Midstream Acquisition and the overall performance of the commodity markets. Our capital allocation plan is focused on maintaining production volumes while also returning capital to shareholders, including through our quarterly cash dividend and share repurchase program, underpursuant to which we are authorized to repurchase up to $2.0 billionshares of our outstanding common stock for an aggregate purchase price of up to $2 billion, excluding fees, commissions and through our quarterly cash dividend, which is currently an annual rate of $0.60 per share.expenses. Furthermore, we have aligned our hedge strategy in a manner that we believe will mitigate the risk of volatility of future natural gas and NGLs prices, thereby enabling us to execute on our capital expenditure, debt retirement and shareholder return strategy.

Our revenues, earnings liquidity and ability to growliquidity are substantially dependent on the prices we receive for, and our ability to develop our reserves of, natural gas, NGLs and oil. Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas, NGLs and oil at our ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations. Changes in natural gas, NGLs and oil prices could affect, among other things, our development plans, which would increase or decrease the pace of the development and the level of our reserves, as well as our revenues, earnings or liquidity. Lower prices and changes in our development plans could also result in non-cash impairments in the book value of our oil and gas properties or downward adjustments to our estimated proved reserves. Any such impairments or downward adjustments to our estimated reserves could potentially be material to us.

See "Critical Accounting Policies and Estimates" included in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 to the Consolidated Financial Statements for a discussion of our significant accounting policies and significant assumptions related to accounting for natural gas, NGLs and oil producing activities and impairment of our oil and gas properties. See also Item 1A., "Risk Factors – Natural gas, NGLs and oil price declines, and changes in our development strategy, have resulted in impairment of certain of our assets. Future declines in commodity prices, increases in operating costs or adverse changes in well performance or additional changes in our development strategy may result in additional write-downs of the carrying amounts of our assets, including long-lived intangible assets, which could materially and adversely affect our results of operations in future periods."

Our operations consist of one reportable segment. We have a single, company-wide management team that administers all properties as a whole rather than by discrete operating segments. We measure financial performance as a single enterprise and not on an area-by-area basis. Substantially all of our assets and operations are located in the Appalachian Basin.

 

The following tables summarizetable summarizes our proved developed and undeveloped natural gas, NGLs and crude oil reserves using average first-day-of-the-month closing prices for the prior twelve months and disaggregated by product and play.product. Substantially all of our reserves reside in continuous accumulations.

The following table summarizes our proved developed and undeveloped reserves using average first-day-of-the-month closing prices for the prior twelve months and disaggregated by state.

Our 20222023 total proved reserves increased by 412,594 Bcfe, or 0.2%10.4%, compared to 20212022 due to extensions, discoveries and other additions of 2,4953,412 Bcfe and acquisitions of 1412,600 Bcfe from the 2022 AssetTug Hill and XcL Midstream Acquisition, (defined in Note 6 to the Consolidated Financial Statements), partly offset by production of 1,9402,016 Bcfe and revisions to previous estimates of 6551,402 Bcfe.

Our 20222023 proved undeveloped reserves decreasedincreased by 254550 Bcfe, or 3.3%7.3%, compared to 2021.2022. The following table provides a rollforwardroll-forward of our proved undeveloped reserves.

As of December 31, 2022,2023, we had zero wells with proved undeveloped reserves that had remained undeveloped for more than five years from their time of booking.

The following table provides the estimated future net cash flows, excluding open derivative contracts, from proved reserves, the present value of those net cash flows discounted at a rate of 10% (PV-10) and the prices used in projecting net cash flows over the past three years. Our reserve estimates do not include any probable or possible reserves.

Future net cash flows represent projected revenues from the sale of proved reserves, net of production and development costs (including transportation and gathering expenses, operating expenses and production taxes) and net of estimated income taxes. Revenues are based on a twelve-month unweighted average of the first-day-of-the-month pricing, without escalation. Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current economic conditions at each year-end. There can be no assurance that the proved reserves will be produced in the future or that prices, production or development costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information. See Note 1614 to the Consolidated Financial

The following table provides the reconciliation of the Standardized Measure to PV-10.

If the prices used in the calculation of the Standardized Measure instead reflected five-year strip pricing as of December 30, 202229, 2023 and held constant thereafter using (i) the NYMEX five-year strip adjusted for regional differentials using Texas Eastern Transmission Corp. M-2, Transcontinental Gas Pipe Line, Leidy Line, and Tennessee Gas Pipeline Co., Zone 4-300 Leg for gas and (ii) the NYMEX WTI five-year strip for oil, adjusted for regional differentials consistent with those used in the Standardized Measure, and holding all other assumptions constant, our total proved reserves would be 24,97128,042 Bcfe, the Standardized Measure after taxes of our proved reserves would be $22,625$18,176 million, and the discounted future net cash flows before taxes would be $29,169 million. The$22,903 million and the average realized product prices weighted by production over the remaining lives of the properties would be $50.13$49.71 per barrel of oil, $27.30$23.08 per barrel of NGLs and $3.565$2.846 per Mcf of gas.

The NYMEX strip price for proved reserves and related metrics are intended to illustrate reserve sensitivities to market expectations of commodity prices and should not be confused with SEC pricing for proved reserves and do not comply with SEC pricing assumptions. We believe that the presentation of reserve volume and related metrics using NYMEX forward strip prices provides investors with additional useful information about our reserves because the forward prices are based on the market's forward-looking expectations of oil and gas prices as of a certain date. The price at which we can sell our production in the future is the major determinant of the likely economic producibility of our reserves. We hedge certain amounts of future production based on futures prices. In addition, we use such forward-looking market-based data in developing our drilling plans, assessing our capital expenditure needs and projecting future cash flows. While NYMEX strip prices represent a consensus estimate of future pricing, such prices are only an estimate and are not necessarily an accurate projection of future oil and gas prices. Actual future prices may vary significantly from NYMEX prices; therefore, actual revenue and value generated may be more or less than the amounts disclosed. Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC pricing, when considering our reserves.

Based on our mix of proved undeveloped probable and probablepossible reserves, we estimate that we have an undeveloped drilling inventory of approximately 2,400 net locations in the Pennsylvania and West Virginia Marcellus Shale.4,000 gross locations. At our current drilling pace, these net locations provide more than 2030 years of drilling inventory based on netgross undeveloped Marcellus acres, average expected lateral length of 12,000 feet and well spacing of 1,000 feet. We believe that our combo-development strategy, coupled with our undeveloped inventory located in a premier core asset base, will lead to sustainable free cash flow generation and higher returns on invested capital.

For the years ended December 31, 2023, 2022 2021 and 2020,2021, lease operating expenses excluding production taxes per Mcfe were $0.08, $0.07$0.08 and $0.07, respectively.

The majority of our acreage is held by lease or occupied under perpetual easements or other rights acquired, for the most part, without warranty of underlying land titles. Approximately 32%36% of our total gross acres is developed. We retain deep drilling rights on the majority of our acreage.

The following table summarizes our acreage disaggregated by state.

We have an active lease renewal program in areas targeted for development. In the event that production is not established or we do not extend or renew the terms of our expiring leases, 25,797, 27,72835,844, 22,097 and 17,09630,206 of our net undeveloped acreage as of December 31, 20222023 will expire in the years ending December 31, 2023, 2024, 2025 and 2025,2026, respectively.

The following table summarizes our natural gas, NGLs and oil produced and sold volume by state.

The following table summarizes our productive and in-process natural gas wells. We had no productive or in-process oil wells as of December 31, 2022.2023.

The following table summarizes our completed net productive development wells. During the years ended December 31, 2023, 2022 2021 and 2020,2021, we did not drill any net dry development, net productive exploratory or net dry exploratory wells.

The following table summarizes the gross and net wells on which we commenced drilling operations (spud) in 2022.2023.

 

For additional information on pricing, see "Average Realized Price Reconciliation" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations."

We have access to approximately 3.6 Bcf per day of firm pipeline takeaway capacity and 0.9 Bcf per day of firm processing capacity. In addition, we are committed to an initial 1.29 Bcf per day of firm capacity on the Mountain Valley Pipeline upon its in-service date.once in service. These firm transportation and processing agreements may require minimum volume delivery commitments, which we expect to principally fulfill with production from existing reserves.

We have contractually agreed to deliver firm quantities of gas and NGLs to various customers, which we expect to fulfill with production from existing reserves. We regularly monitor our proved developed reserves to ensure sufficient availability to meet commitments for the next one to three years. The following table summarizes our total gross commitments as of December 31, 2022.2023.

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or summers may also impactaffect demand.

 

Other natural gas producers compete with us in the acquisition of properties; the search for, and development of, reserves; the production and sale of natural gas and NGLs; and the securing of services, labor, equipment and transportation required to conduct operations. Our competitors include independent oil and gas companies, major oil and gas companies, individual producers, operators and marketing companies and other energy companies that produce substitutes for the commodities that we produce.

 

Our operations are also subject to conservation and correlative rights regulations, including the following: regulation of the size of drilling and spacing units or field rule units; setbacks; the number of wells that may be drilled in a unit or in close proximity to other wells; drilling in the vicinity of coal mining operations and certain other structures; and the unitization or pooling of natural gas properties. Ohio allows the statutory pooling or unitization of tracts to facilitate development and exploration. In Pennsylvania, lease integration legislation authorizes joint development of existing contiguous leases. West Virginia historically only allowed statutory pooling of Utica acreage and for other deep wells, which required operators to rely on voluntary pooling of lands and leases to develop Marcellus acreage. However, in March 2022, the West Virginia legislature passed Senate Bill 694 allowingallows the operator of a proposed horizontal well (regardless of formation) to develop the acreage of non-consenting and unlocatable and unknown owners if 75% of the mineral interest owners and 55% of the working interest owners in the proposed well unit consent to the development. Senate Bill 694, and the corresponding unitization provisions thereunder, went into effect on June 7, 2022. Additionally, state conservation and oil and gas laws generally limit the venting or flaring of natural gas. Various states also impose certain regulatory requirements to transfer wells to third parties or discontinue operations in the event of divestitures by us.

We maintain limitedalso have gathering and processing operations used for our own produced natural gas and NGLs that are subject to various federal and state environmental laws and local zoning ordinances, including the following: air permitting requirements for compressor station and dehydration units and other permitting requirements; erosion and sediment control requirements for compressor station and pipeline construction projects; waste management requirements and spill prevention plans for compressor stations; various recordkeeping and reporting requirements for air permits and waste management practices; compliance with safety regulations, including regulations by the Department of Transportation's Pipeline and Hazardous Materials Safety Administration; and siting and noise regulations for compressor stations. These regulations may increase the costs of operating existing pipelines and compressor stations and increase the costs of, and the time to develop, new or expanded pipelines and compressor stations.

We use financial derivative instruments to hedge the impact of fluctuations in natural gas, NGLs and oil prices on our results of operations and cash flows. In 2010, Congress adopted comprehensive financial reform legislation that established federal oversight and regulation of the OTC derivative market and entities, such as us, that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), required the CFTC, the SEC and other regulatory agencies to promulgate rules and regulations implementing this legislation. Among other things, the Dodd-Frank Act established margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail or alter their derivative activities. The Dodd-Frank Act also created new categories of regulated market participants, such as “swap dealers”"swap dealers" (SDs) and “security-based"security-based swap dealers”dealers" (SBSDs) that are subject to significant new capital, registration, recordkeeping, reporting, disclosure, business conduct and other regulatory requirements, a large number of which have been implemented. This regulatory framework has significantly increased the costs of entering into derivatives transactions for end-users of derivatives, such as ourselves. In particular, new margin requirements and capital charges, even when not directly applicable to us, have increased the pricing of derivatives that we transact in.

New exchange trading margin regulations, trade reporting requirements and position limits may lead to changes in the liquidity of our derivative transactions or higher pricing. That said, our hedging activities are not subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing, although we are subject to certain recordkeeping and reporting obligations associated with the Dodd-Frank Act. Additionally, our uncleared swaps are not subject to regulatory margin requirements. Finally, we believe that the majority, if not all, of our hedging activities constitute bona fide hedging under applicable federal and exchange-mandated position limits rules and are not materially impacted by the limitations under such rules.

In addition to U.S. laws and regulations relating to derivatives, certain non-U.S. regulatory authorities have passed or proposed, or may propose in the future, legislation similar to that imposed by the Dodd-Frank Act. For example, European Union legislation imposes position limits on certain commodity transactions, and the European Market Infrastructure Regulation (EMIR) requires reporting of derivatives and various risk mitigation techniques to be applied to derivatives entered into by parties that are subject to EMIR. Other similar regulations are in development throughout the globe and may increase our cost of doing business even if not directly binding on us.

Regulators periodically review or audit our compliance with applicable regulatory requirements. We anticipate that compliance with existing laws and regulations governing our current operations will not have a material adverse effect on our capital expenditures, earnings or competitive position. Additional proposals that affect the oil and gas industry are regularly considered

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978. Various federal laws enacted since 1978 have resulted in the removal of all price and non-price controls for sales of domestic natural gas sold in first sales, which include all of our sales of our own production. Under the Energy Policy Act of 2005, the FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties of almostover $1.5 million per day for each violation and disgorgement of profits associated with any violation. While our production activities have not been regulated by the FERC as a natural gas company under the NGA, we are required to report the aggregate volume of natural gas purchased or sold at wholesale to the extent such transactions use, contribute to or may contribute to the formation of price indices. In addition, Congress may enact legislation or the FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject us to civil penalties.

The CFTC also holds authority to monitor certain segments of the physical, futures and other derivatives energy commodities markets, including natural gas, NGLs and oil. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation and disruptive trading practices laws and related regulations enforced by the CFTC. The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties.

The FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of natural gas and release of our natural gas pipeline capacity. Commencing in 1985, the FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide non-unduly discriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. The FERC's initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by the FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas-related activities.

Under the FERC's current regulatory regime, transportation services must be provided on an open-access, nondiscriminatory basis at cost-based rates or negotiated rates, both of which are subject to FERC approval. The FERC also allows jurisdictional natural gas pipeline companies to charge market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of FERC-jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC as a natural gas company under the NGA. Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC's determinations as to the classification of facilities are done on a case-by-case basis. To the extent that the FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, and, depending on the scope of that decision, our costs of transporting natural gas to point of sale locations may increase. We believe that the third-party natural gas pipelines on which our gas is gathered meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to regulation as a natural gas company. However, the distinction between the FERC-regulated transportation services and federally unregulated gathering services could be subject to potential litigation, and the classification and regulation of those gathering facilities are subject to change based on future determinations by the FERC, the courts or Congress. State regulation of natural

The price we receive from the sale of our produced oil and NGLs may be affected by the cost of transporting such products to market. Some of our transportation of oil and NGLs is through FERC-regulated interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. The FERC's regulation of crude oil and NGLs transportation rates may tend to increase the cost of transporting crude oil and NGLs by interstate pipelines, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. The FERC's five-year index level for 2021 through 2026 went into effect on July 1, 2021. In January 2022, the FERC issued an order on rehearing, lowering the index level and directing oil pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022 to ensure compliance with the new index level.

Moreover, the trend has been for stricter regulation of activities that have the potential to affect the environment. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, federal agencies, the states, local governments and the courts. We cannot predict when or whether any such proposals may become effective. Therefore, we are unable to predict the future costs or impact of compliance. The regulatory burden on the industry increases the cost of doing business and affects profitability. We have established procedures, however, for the ongoing evaluation of our operations to identify potential environmental exposures and to track compliance with regulatory policies and procedures.

The following is a summary of the more significant environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our financial condition, earnings or cash flows.

The Resource Conservation and Recovery Act (RCRA) and analogous state laws establish detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced water and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA, or state agencies under RCRA's less stringent nonhazardous solid waste provisions, or under state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes currently classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. Any changes to state or federal programs could result in an increase in our costs to manage and dispose waste, which could have a material adverse effect on our results of operations and financial condition.

We currently own, lease or operate numerous properties that have been used for oil and natural gas exploration and production activities for many years. Although we believe that we have used operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including offsite locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. We are able to directly control directly the operation of only those wells with respect to which we act or have acted as operator. The failure of a prior owner or operator to comply with applicable environmental regulations may, in certain circumstances, be attributed to us as the current owner or operator under CERCLA. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, regardless of fault, which could include removal of previously disposed substances and wastes, clean-up of contaminated property or performance of remedial plugging or waste pit closure operations to prevent future contamination.

In June 2016,November 2021, the EPA finalized regulations establishingannounced a proposed rule expanding upon its New Source Performance Standards (NSPS), known as Subpart OOOOa, rule, establishing standards for methane and volatile organic compounds (VOC)(VOCs) from new and modified oil and natural gas production and natural gas processing and transmission facilities. In September 2020, the EPA finalized two sets of amendments to the 2016 Subpart OOOOa standards. The first amendment, known as the "2020 Technical Rule", reduced the 2016 rule's fugitive emissionsfacilities which would establish standards for existing wells, impose more frequent and stringent leak monitoring, requirements and expanded exceptions tomandate that all pneumatic pump requirements, among other changes. The second amendment, known as the "2020 Policy Rule", rescinded the methane-specific requirements for certain oil and natural gas sources in the production and processing segments. On January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the 2020 Technical Rule by September 2021 and consider revising the 2020 Policy Rule. On June 30, 2021, President Biden signed a Congressional Review Act (CRA) resolution passed by Congress that revoked the 2020 Policy Rule. The CRA did not address the 2020 Technical Rule.

As a result of these regulatory changes, the scope of any final air emissions regulations or the costs for complying with such regulations are uncertain. We may incur costs as necessary to remain in compliance with these regulations. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

In August 2022, President Biden signed into lawrecent years, the U.S. Congress has considered legislation to reduce GHG emissions. While Congress has not passed comprehensive climate legislation regulating the emission of GHGs, energy legislation and other regulatory initiatives have been enacted or proposed that are relevant to GHG emissions and climate change. In particular, in November 2021, Congress approved a $1 trillion legislative infrastructure package known as the Inflation Reduction Act of 2022 (Inflation Reduction Act),(IRA) which amongincludes a number of climate-focused spending initiatives. The IRA also provides significant funding and incentives for research and development of low-carbon energy production methods, carbon capture, and other things, includesprograms directed at addressing climate change, including instituting a methane emissions reduction program that amendsknown as the CAA to include a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems. This program requires the EPA to impose a “wastefee known as a "waste emissions charge”charge" on methane emissions from certain natural gas and oil and gas sourcesfacilities that are already required to report under the EPA’s Greenhouse Gas Reporting Program (GHGRP). The waste emissions charge will become effective on January 1, 2024 and will apply to a facility’s emissions (as reported under the EPA’s GHGRP) in excess of a specified threshold, as set forth inthreshold. In January 2024, the Inflation Reduction Act based uponEPA proposed a rule implementing the emitting facility’s segment category.IRA's methane emissions charge. The feemethane emissions charge imposed under the program for emissions in excess of the specified threshold will initially be2024 is $900 per metric ton ofemitted over the annual methane emitted in 2024emissions threshold, and will increase to $1,200 in 2025, and $1,500 in 2026. The proposed rule includes potential methodologies for calculating the amount by which a facility's reported methane emissions are below or exceed the waste emissions thresholds and contemplates approaches for implementing certain exemptions created by the IRA. For petroleum and natural gas production facilities, the threshold is methane emissions in excess of 0.2% of the natural gas sent to sale from the facility. If a facility’sfacility's methane emissions do not exceed the 0.2% threshold, no fee would be assessed under the rule. Ourprogram. Further, in July 2023, the EPA proposed to expand the scope of the Greenhouse Gas Reporting Program for petroleum and natural gas systems (Subpart W), as required by the IRA. Among other things, the proposed rule expands the emissions events that are subject to reporting requirements to include "other large release events" and applies reporting requirements to certain new sources and sectors, which may result in an increase in reported methane and other GHG emissions under Subpart W for many operators, including us. The rule is currently scheduled to be finalized in the spring of 2024 and would take effect on January 1, 2025 in advance of the deadline for reporting emissions for calendar year 2024 under Subpart W.

current methaneFurthermore, in May 2023, the EPA issued proposed carbon emission limits and guidelines for new, modified, reconstructed and existing fossil fuel-fired (i.e., coal, oil and gas-fired) power plants. The proposed rule purports to reflect the best system of emissions do not exceed the 0.2% threshold,reduction and accordingly, we do not believe we will be assessed a fee under the Methane Emissions and Waste Reduction Incentive Program.

Additionally, a number of U.S. state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of carbon taxes, policies and incentives, and cap-and-trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting GHGs.programs. In October 2019, Pennsylvaniathen-Pennsylvania Governor Tom Wolf signed an Executive Order directing the Pennsylvania Department of Environmental Protection (PADEP) to draft regulations establishing a cap-and-trade program under its existing authority to regulate air emissions, with the intent of enabling Pennsylvania to join the Regional Greenhouse Gas Initiative (RGGI), a multi-state regional cap-and-trade program comprised of several Eastern U.S. states. In September 2020, the Pennsylvania Environmental Quality Board (EQB) approved promulgation of the RGGI regulation, and a public comment period and hearings regarding the regulation commenced at the end of 2020. Pennsylvania ultimately became a member of RGGI though itsin April 2022; however, since joining RGGI, Pennsylvania's membership is currentlyhas been the subject of various legal challenges. Depending onMost recently, in November 2023, the outcomePennsylvania Commonwealth Court held that the state's participation in RGGI is unconstitutional, and funds raised by the state through its participation in RGGI constitute an invalid tax, which ruling has been appealed. At this time, it is unclear to what extent, if any, Pennsylvania will continue to seek participation in RGGI or a similar emissions cap-and-trade program.

Regulations requiring the disclosure of GHG emissions and other climate-related information or information substantiating climate-related claims are also increasingly being adopted or proposed at the federal and state level. For example, the SEC issued a proposed rule in March 2022 that would mandate extensive disclosure of climate-related data, risks, and opportunities, including financial impacts, physical and transition risks, related governance and strategy, and GHG emissions, for certain public companies. At the state level, California enacted legislation in October 2023 that will ultimately require certain companies that do business in California to publicly disclose their Scopes 1, 2, and 3 GHG emissions, with third party assurance of such litigation, Pennsylvania's membershipdata, and issue public reports on their climate-related financial risk and related mitigation measures, as well as legislation that requires companies operating in RGGI will result in increased operating costs should we be requiredCalifornia to purchase emission allowances in connection with our operations.disclose information that supports certain climate-related claims.

Any legislation or regulatory programs at the international, federal, state or city levels designed to reduce methane or other GHG emissions could increase the cost of consuming, and thereby reduce demand for, the natural gas, NGLs and oil we produce. Consequently, legislation and regulatory programs designed to reduce emissions of methane or other GHGs could have an adverse effect on our business, financial condition and results of operations.

Although itIt is not possible at this time to predict how legislation or new regulations that may be adopted to address climate change, methane and other GHG emissions would impact our business,business. However, existing laws and regulations and any such future laws and regulations of this nature, including those imposing reporting obligations on, or imposing a tax or fee or otherwise limiting emissions of methane or other GHG emissions from, our equipment and operations could require us to incur costs to comply with such regulations. Substantial limitations or fees on methane or other GHG emissions could also adversely affect demand for the natural gas, NGLs and oil we produce and lower the value of our reserves.

Notwithstanding potential risks related to climate change, natural gas continues to represent a major share of global energy use, and certain private sector studies project continued growth in demand for the next two decades. Nonetheless,Further, recent activism directed at shifting funding away from fossil fuel companies could result in limitations or restrictions on certain sources of funding for the sector. Moreover, activist shareholders have introduced proposals that may seekto certain companies seeking to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult to engage in exploration and production activities.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that may have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events. If any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water and thus could have an adverse effect on our exploration and production operations.

Hydraulic fracturing typically is regulated by state oil and natural gas agencies, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (SDWA) over certain hydraulic fracturing activities involving the use of diesel fuels and has prohibited the discharge of wastewater from hydraulic fracturing operations to publicly owned

See Note 1311 to the Consolidated Financial Statements for a description of expenditures related to environmental matters.

 

As of December 31, 2022,2023, we had 744 permanent881 employees (excluding temporary employees and contractors), none of whom were subject to a collective bargaining agreement. Of our total permanent employee base, 74%76% are male and 26%24% are female. Approximately 66%64% of our permanent employees work remotely, with 91%94% residing in Pennsylvania, Texas or West Virginia.

We aim to develop a workforce that produces peer leading results. To further that goal, we have focused on creating a modern, innovative, collaborative and digitally-enabled work environment. Our cloud-based digital work environment serves as our primary platform for communication and collaboration as well as the home for our critical work processes and drives decision-making based on a shared and transparent view of operational data. We use our digital work environment to engage directly with our employees by sharing company updates and personnel accomplishments as well as to solicit suggestions and comments from all employees. We believe that this helps promote real-time feedback and a greater degree of employee engagement, which lays the foundation for the success of our remote workforce.

We understand that providing employees with the resources and support they need to live a physically, mentally and financially healthy life is critical for sustaining a workplace of choice. We offer benefits that include subsidized health insurance, a company contribution and company match on 401(k) retirement savings, an employee stock purchase plan, paid maternity and paternity leave, flexible work arrangements, volunteer time off and a company match on employee donations to qualified non-profits. We also offer our employees the flexibility to elect to work a "9/80" work schedule, under which, during the standard 80-hour pay period, an employee works eight 9-hour days and one 8-hour day (Friday), with a tenth day off (alternating Fridays).

We also offer an "equity-for-all" program, pursuant to which, we grant annual equity awards to all of our permanent employees. With the equity-for-all program, all of our permanent employees become owners of EQT and have the opportunity to share directly in our financial success.

 

We make certain filings with the SEC, including our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through our investor relations website, http://ir.eqt.com, as soon as reasonably practicable after they are filed with or furnished to the SEC. Reports filed with the SEC are also available on the SEC's website, http://www.sec.gov.

We use our TwitterX (formerly known as Twitter) account, @EQTCorp, our Facebook account, @EQTCorporation, and our LinkedIn account, EQT Corporation, as additional ways of disseminating information that may be relevant to investors.

We generally post the following to our investor relations website shortly before or promptly following its first use or release: financially-related press releases, including earnings releases and supplemental financial information; various SEC filings; presentation materials associated with earnings and other investor conference calls or events; and access to live and recorded audio from earnings and other investor conference calls or events. In certain cases, we may post the presentation materials for other investor conference calls or events several days prior to the call or event. For earnings and other conference calls or events, we generally include within our posted materials a cautionary statement regarding forward-looking and non-GAAP financial information as well as non-GAAP to GAAP financial information reconciliations (if available). Such GAAP reconciliations may be in materials for the applicable presentation, in materials for prior presentations or in our annual, quarterly or current reports.

In certain circumstances, we may post information, such as presentation materials and press releases, to our corporate website, www.EQT.com, or our investor relations website to expedite public access to information regarding EQT in lieu of making a filing with the SEC for first disclosure of the information. When permissible, we expect to continue to do so without also providing disclosure of this information through filings with the SEC.

Where we have included internet addresses in this Annual Report on Form 10-K, we have included those internet addresses as inactive textual references only. Except as specifically incorporated by reference into this Annual Report on Form 10-K, information on those websites is not part hereof.

 

The following table presents total operating revenues for each class of our products and services.

 

We are a Pennsylvania corporation formed in 2008 in connection with a holding company reorganization of the former Equitable Resources, Inc.

In addition to the other information contained in this Annual Report on Form 10-K, the following risk factors should be considered in evaluating our business and future prospects. Note that additional risks not presently known to us or that are currently considered immaterial may also have a negative impact on our business and operations. If any of the events or circumstances described below actually occur, our business, financial condition or results of operations could suffer and the trading price of our common stock could decline.

Many factors may curtail, delay or cancel our scheduled drilling projects, or the development schedule of wells which we do not operate but in which we have a working interest (referred to as non-operated wells), including the following:

Any of these risks can cause a delay in our development program or the scheduled development of non-operated wells in which we have a working interest, or result in substantial financial losses, personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. Additionally, we cannot control or otherwise influence the development schedule of non-operated wells in which we have a working interest. Adjustments to our planned development schedule or the development schedule of non-operated wells in which we have a working interest could impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.

Our business is subject to all of the inherent hazards and risks normally incidental to drilling for, producing, transporting, storing, processing, gathering and storingcompressing natural gas, NGLs and oil, such as fires, explosions, slips, landslides, blowouts, and well cratering; pipe and other equipment and system failures; delays imposed by, or resulting from, compliance with regulatory requirements; formations with abnormal or unexpected pressures; shortages of, or delays in, obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities; adverse weather conditions, such as freeze offs of wells and pipelines due to cold weather; issues related to compliance with environmental regulations; environmental hazards, such as natural gas leaks, oil and diesel spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized releases of brine, well stimulation and completion fluids, wastewater, toxic gases or other pollutants into the environment, especially those that reach surface water or groundwater; inadvertent third-party damage to our assets; and natural disasters. We also face various

infrastructure, such as processing plants, compressor stations and pipelines. Any of these risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property, equipment and natural resources, pollution or other environmental damage, loss of hydrocarbons, disruptions to our operations, regulatory investigations and penalties, suspension of our operations, repair and remediation costs, and loss of sensitive confidential information. Moreover, in the event that one or more of these hazards occur, there can be no assurance that a response will be adequate to limit or reduce damage.

As a result of these risks, we are also sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business. There can be no assurance that the insurance policies we maintain to limit our liability for such losses will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that such levels of insurance will be available in the future at economical prices or to cover all risks. In addition, pollution and environmental risks generally are not fully insurable, and we may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. The occurrence of an event that is not fully covered by insurance could materially adversely affect our business, results of operations, cash flows and financial position.

Growing geopolitical instability and armed conflicts (including the armed conflict between Russia and Ukraine)Ukraine and in the Middle East) has resulted in energy infrastructure becoming a more prominent target of attack by terrorists and conflicting countries. Natural gas, NGLs and oil related facilities, including those operated by us or our service providers, could be direct targets of physical or cyber attacks,cyber-attacks, and, if infrastructure integral to our operations is destroyed or damaged, we may experience a significant disruption in our operations. Any such disruption could materially adversely affect our financial condition, results of operations and cash flows. Costs for insurance and other security may increase as a result of increased threats, and certain insurance coverage may become more difficult to obtain, if available at all.

Our management team has specifically identified and scheduled certain well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our business strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas, NGLs and oil prices; the

availability and cost of capital; drilling and production costs; the availability of drilling services and equipment; drilling results; lease expirations; topography; gathering system and pipeline transportation costs and constraints; access to and availability of sand and water and corresponding materials sourcing and distribution systems, including railroads; coordination with coal mining; regulatory approvals; and other factors. Because of these uncertain factors, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce natural gas, NGLs or oil from these or any other drilling locations. In addition, if production is not established within the spacing units covering our undeveloped acres in accordance with the requisite timeframe set forth in the applicable lease, our leases for such acreage will expire. Further, certain of the horizontal wells we intend to drill in the future may require pooling or unitization with adjacent leaseholds controlled by third parties. If these third parties are unwilling to pool or unitize such leaseholds with ours, the total locations we can drill may be limited. As such, our actual drilling activities may materially differ from those presently identified.

Mineral rights are typically owned by individuals who may enter into property leases with us to allow for the development of natural gas. Such leases expire after an initial term, typically five years, unless certain actions are taken to preserve the lease. If we cannot preserve a lease, the lease terminates. Approximately 6%7% of our net undeveloped acres are subject to leases that could expire over the next three years. Lack of access to capital, changes in government regulations, changes in future development plans or commodity prices, reduced drilling activity, or the reduction in the fair value of undeveloped properties in the areas in which we operate could impact our ability to preserve, trade or sell our leases prior to their expiration, resulting in the termination or impairment of leases for properties that we have not developed.

We evaluate capitalized costs of unproved oil and gas properties at least annually to determine recoverability on a prospective basis. Indicators of potential impairment include changes brought about by economic factors, potential shifts in our business strategy and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the

Our inability to cure any title defects in our leases in a timely and cost-efficient manner may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase our production and reserves. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial position.

Because the rate of production from natural gas and oil wells, and associated NGLs, generally declines as reserves are depleted, our future success depends upon our ability to develop additional reserves that are economically recoverable and to optimize existing well production, and our failure to do so may reduce our earnings. Additionally, a failure to effectively and efficiently operate existing wells may cause our production volume to fall short of our projections. Our drilling and subsequent maintenance of wells can involve significant risks, including those related to timing, cost overruns and operational efficiency, and these risks can be affected by the availability of capital, leases, rigs, equipment, a qualified work force, and adequate capacity for the treatment and recycling or disposal of wastewater generated in our operations, as well as weather conditions, natural gas, NGLs and oil price volatility, regulatory approvals, title and property access problems, geology, equipment failure or accidents and other factors. Drilling for natural gas and oil can be unprofitable, not only due to dry wells, but also as a result

of productive wells that perform below expectations or that do not produce sufficient revenues to return a profit. Low natural gas, NGLs and oil prices may further limit the types of reserves that we can develop and produce economically.

Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as reserves are produced. Our future natural gas, NGLs and oil production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot be certain that we will be able to find or acquire and develop additional reserves at an acceptable cost. Without continued successful development or acquisition activities, together with efficient operation of existing wells, our reserves and production, together with associated revenues, will decline as a result of our current reserves being depleted by production.

Reserve engineering is a subjective process involving estimates of underground accumulations of natural gas, NGLs and oil and assumptions concerning future prices, production levels and operating and development costs, some of which are beyond our control. These estimates and assumptions are inherently imprecise, and we may adjust our estimates of proved reserves based on changes in these estimates or assumptions. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Any significant variance from our assumptions could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas, NGLs and oil, the classifications of reserves based on risk of recovery and estimates of future net cash flows. To the extent we experience a sustained period of reduced commodity prices, there is a risk that a portion of our proved reserves could be deemed uneconomic and no longer be classified as proved. Although we believe our estimates are reasonable, actual production, revenues and costs to develop reserves will likely vary from our estimates and these variances could be material. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas, NGLs and oil we ultimately recover being different from our reserve estimates.

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated natural gas, NGLs and crude oil reserves. In accordance with SEC requirements, we based the discounted future net cash flows from our proved reserves on the twelve-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net cash flows from our reserves will be affected by factors such as the actual prices we receive for natural gas, NGLs and oil, the

We review the carrying values of our proved oil and gas propertiesassets for indications of impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. A significant amount of judgment is involved in performing these evaluations because the results are based on estimated future events and estimated future cash flows. The estimated future cash flows used to test our proved oil and gas properties for recoverability are based on proved and, if determined reasonable by management, risk-adjusted probable reserves, utilizing assumptions generally consistent with the assumptions used by our management for internal planning and budgeting purposes. Key assumptions used in our analyses include, among other things, the intended use of the asset, the anticipated production from reserves, future market prices for natural gas, NGLs and oil, future operating and development costs, inflation and the anticipated proceeds that may be received upon divestiture if there is a possibility that the asset will be divested prior to the end of its useful life. Commodity pricing is estimated by using a combination of the five-year NYMEX forward strip prices and assumptions related to gas quality, locational basis adjustments and inflation. Proved oil and

gas properties that have carrying amounts in excess of estimated future cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount rate assumptions that marketplace participants would use in their estimates of fair value.

Future declines in natural gas, NGLs or oil prices, increases in operating costs or adverse changes in well performance, among other circumstances, may result in our having to make significant future downward adjustments to our estimated proved reserves and/or could result in additional non-cash impairment charges to write-down the carrying amount of our assets, including other long-lived intangible assets, which may have a material adverse effect on our results of operations in future periods. Any impairment of our assets, including other long-lived intangible assets, would require us to take an immediate charge to earnings. Such charges could be material to our results of operations and could adversely affect our results of operations and financial position. See "Critical Accounting Policies and Estimates" included in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 to the Consolidated Financial Statements for a discussion of our significant accounting policies and significant assumptions related to accounting for natural gas, NGLs and oil producing activities and impairment of our oil and gas properties.

Our primary business involves the exploration, production and sale of hydrocarbons, and in particular, natural gas. Consequently, our revenue, profitability, future rate of growth, liquidity and financial position depend upon the market prices for natural gas and, to a lesser extent, NGLs and oil. Because our production and reserves predominantly consist of natural gas (approximately 94%93% of our equivalent proved developed reserves), changes in natural gas prices have significantly greater impact on our financial results than oil prices.

The prices for natural gas, NGLs and oil have historically been volatile and have been particularly volatile in recent years. The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $9.85$3.78 per MMBtu to a low of $3.46$1.74 per MMBtu between the period from January 1, 20222023 through December 31, 2022,2023, and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of $123.64$93.67 per barrel to a low of $71.05$66.61 per barrel during the same period. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, which adds further volatility to the pricing of NGLs. We expect commodity price volatility to continue or increase in the future due to rising macroeconomic uncertainty and geopolitical tensions, including the Russian invasion of Ukraine, which began in February 2022 and has put upward pressure on natural gas and oil prices.

Commodity prices are affected by a number of factors beyond our control, which include:

We use financial models to attempt to project future prices for the hydrocarbons we produce and sell, and we make decisions regarding our production, operations and hedging strategy in part based on such modelling. However, due to the volatility of commodity prices and the multitude of external factors that impact commodity prices, many of which are unknown and unforeseeable, we are unable to predict with certainty future potential movements in the market prices for natural gas, NGLs and oil. The success of our plans and strategies could be negatively affected if our projections of future hydrocarbon prices are significantly different from the ultimate actual price.

Prolonged low, and/or significant or extended declines in, natural gas, NGLs and oil prices may adversely affect our revenues, operating income, cash flows, financial projections, and financial position, particularly if we are unable to control our development costs during periods of lower natural gas, NGLs and oil prices. Declines in prices could also adversely affect our drilling activities and the amount of natural gas, NGLs and oil that we can produce economically, which may result in our having to make significant downward adjustments to the value of our assets and could cause us to incur non-cash impairment charges to earnings. Reductions in cash flows from lower commodity prices may require us to incur additional debt or reduce our capital spending, which could reduce our production and our reserves, negatively affecting our future rate of growth. Reduced cash flows could also result in us having to make downward adjustments to our financial projections, such as free cash flow, and could cause us to revise our shareholder returns initiatives, including the amount of dividends paid on our common stock, which could negatively impact the price of our common stock and our ability to access the capital markets. Lower prices for natural gas, NGLs and oil may also adversely affect our credit ratings and result in a reduction in our borrowing capacity and access to other capital. See "Critical Accounting Policies and Estimates" included in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 to the Consolidated Financial Statements for a discussion of our significant accounting policies and significant assumptions related to accounting for natural gas, NGLs and oil producing activities and impairment of our oil and gas properties.

Increases in natural gas, NGLs and oil prices may be accompanied by or result in increased well drilling costs, increased production taxes, increased lease operating expenses, increased volatility in seasonal gas price spreads for our storage assets and increased end-user conservation or conversion to alternative fuels. Significant natural gas price increases may subject us to margin calls on our commodity price derivative contracts (hedging arrangements, including swap, collar and option agreements and exchange-traded instruments), which would potentially require us to post significant amounts of cash collateral or letters of credit with our hedge counterparties and would negatively impact our liquidity. The cash collateral provided to our hedge counterparties, which is interest-bearing, is returned to us in whole or in part upon a reduction in forward market prices, depending on the amount of such reduction, or in whole upon settlement of the related derivative contract. In addition, toTo the

We are also exposed to the risk of non-performance by our hedge counterparties in the event that changes, positive or negative, in natural gas prices result in our derivative contracts having a positive fair value in our favor. Further, adverse economic and market conditions could negatively affect the collectability of our trade receivables and cause our hedge counterparties to be unable to perform their obligations or to seek bankruptcy protection.

Concerns over global economic conditions, stock market volatility, energy costs, geopolitical issues (including continued hostilities between Russia and Ukraine)Ukraine as well as other conflicts, including in the Middle East), inflation and U.S. Federal Reserve interest rate increases in response thereto, the availability and cost of credit, and slowing of economic growth in the United States and abroad and fears of a recession have contributed and may continue to contribute to increased economic uncertainty and diminished expectations for the global economy. Global economic conditions, geopolitical issues and inflation

have constrained global and domestic supply chains, which has impacted and could in the future continue to impact our ability to develop our reserves in accordance with our drilling and completions schedule. Additionally, global economic conditions have a significant impact on commodity prices and any stagnation or deterioration in global economic conditions could result in decreased demand and, thus, lower prices for natural gas, NGLs or oil. Such uncertainty could also result in higher natural gas, NGLNGLs and oil prices, which could potentially result in increased inflation worldwide and could negatively impact demand for natural gas, NGLs and oil.

In December 2021, we outlinedWe have published a leverage and debt retirement strategy with the ultimate goal of retiring a significant amount ofreducing our totalabsolute debt by the end of 2023to $3.5 billion (our Debt Retirement Plan). We intend to fund our Debt Retirement Plan through free cash flow, and have aligned our hedge strategy in a manner that we believe will mitigate the risk of volatility of future natural gas and NGLs prices, which we anticipate will enable us to execute on our Debt Retirement Plan and other capital allocation strategies; however, there can be no assurance that we will be able to generate sufficient free cash flow to execute our Debt Retirement Plan on our anticipated timeframe, if at all. If we are not able to successfully execute our Debt Retirement Plan or otherwise reduce our total debt to a level we believe appropriate, our credit ratings may be lowered, we may reduce or delay our planned capital expenditures or investments, and we may revise our shareholder returns strategy or other strategic plans.

Our business is capital intensive. We make and expect to continue to make substantial capital expenditures for the development and acquisition of natural gas, NGLs and oil reserves. reserves, as well as processing facilities, pipelines and related infrastructure. Additionally, the construction of additions or modifications to our existing midstream systems involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If these projects are undertaken, they may not be completed on schedule, at the budgeted cost or at all. The construction of additions to our existing assets may require us to obtain new land rights and regulatory permits prior to constructing new pipelines or facilities, which may not be obtained in a timely, cost-effective fashion or in a way that allows us to connect new natural gas supplies to existing gathering pipelines or capitalize on other attractive expansion opportunities.

We typically fund our capital expenditures with existing cash and cash generated by operations and, to the extent our capital expenditures exceed our cash resources, from borrowings under our revolving credit facility and other external sources of capital. If we do not have sufficient borrowing availability under our revolving credit facility, we may seek alternate debt or equity financing, sell assets or reduce our capital expenditures. The issuance of additional indebtedness would require that a portion of our cash flows from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flows from operations to fund working capital, capital expenditures, shareholder returns initiatives and acquisitions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.

Our cash flows from operations and access to capital are subject to a number of variables, including:

If our cash flows from operations or the borrowing capacity under our revolving credit facility are insufficient to fund our capital expenditures and we are unable to obtain the capital necessary for our planned capital budget or our operations, we could be required to curtail our operations and the development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, results of operations and financial position.

As of December 31, 2022,2023, our senior notes were rated "Ba1""Baa3" with a "positive""stable" outlook by Moody's Investors Services (Moody's), "BBB-"BBB–" with a "stable" outlook by Standard & Poor's Ratings Service (S&P) and "BBB-"BBB–" with a "stable" outlook by Fitch Ratings Service (Fitch). Although we are not aware of any current plans of Moody's, S&P or Fitch to downgrade its rating of our senior notes, we cannot be assured that one or more of these rating agencies will not downgrade or withdraw entirely its rating of our senior notes. Low prices for natural gas, NGLs and oil, an increase in the level of our indebtedness or other factors may result in Moody's, S&P or Fitch downgrading its rating of our senior notes. Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our lines of credit, the interest rate on our revolving credit facility and Term Loan Facility (defined in Note 108 to the Consolidated Financial Statements) and senior notes with adjustable rates, the rates available on new long-term debt, our pool of investors and funding sources, the borrowing costs

and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts.

As of December 31, 2022,2023, we had approximately $5.7$5.8 billion of debt outstanding, and we may incur additional indebtedness in the future. Increases in our level of indebtedness may:

Our debt agreements also require us to comply with certain covenants. If the price that we receive for our natural gas, NGLs and oil production deteriorates from current levels orand continues for an extended period, it could lead to reduced revenues, cash flow and earnings, which in turn could lead to a default due to lack of covenant compliance. For more information about our debt agreements, read "Capital Resources and Liquidity" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations."

Our business and operating results can be adversely affected by increases in interest rates or other increases in the cost of capital resulting from a reduction in our credit rating or otherwise. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flows used for operating and capital expenditures and place us at a competitive disadvantage.

Disruptions or volatility in the financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. A significant reduction in the availability of credit could materially and adversely affect our ability to implement our business strategy and achieve favorable operating results. In addition, we are exposed to credit risk related to our revolving credit facility to the extent that one or more of our lenders may be unable to provide necessary funding to us under our existing line of credit if it experiences liquidity problems.

To manage our exposure to price risk, we currently and may in the future enter into derivative arrangements, utilizing commodity derivatives with respect to a portion of our future production. Such hedges are designed to lock in prices in order to limit volatility and increase the predictability of cash flow. These transactions limit our potential gains if natural gas, NGLs and oil prices rise above the price established by the hedge, and we may be required to post cash collateral or letters of credit with

We cannot be certain that any derivative transaction we may enter into will adequately protect us from declines in the prices of natural gas, NGLs or oil. Furthermore, where we choose not to engage in derivative transactions in the future, we may be more adversely affected by changes in natural gas, NGLs or oil prices than our competitors who engage in derivative transactions. Lower natural gas, NGLs and oil prices may also negatively impact our ability to enter into derivative contracts at favorable prices.

Derivative transactions also expose us to a risk of financial loss if a counterparty fails to perform under a derivative contract or enters bankruptcy or encounters some other similar proceeding or liquidity constraint. In this case, we may not be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities. During periods of falling commodity prices our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

Our future prospects are dependent upon our ability to identify optimal strategies for our business. Our operational strategy focuses on developing several multi-well pads in tandem through a process known as combo-development. We have allocated a substantial portion of our financial, human capital and other resources to pursuing this strategy, including investing in new technologies and equipment, restructuring our workforce, and pursuing various ESG and energy transition initiatives geared towards enhancing our strategy. We may not realize some or any of the anticipated strategic, financial, operational, environmental and other anticipated benefits from our operational strategy and the corresponding investments we have made in pursuing our strategy. Additionally, we cannot be certain that we will be able to successfully execute combo-development projects at the pace and scale that we project, which may delay or reduce our production and our reserves, negatively affecting our associated revenues. If we fail to identify and successfully execute optimal business strategies, including the appropriate operational strategy and corresponding initiatives, or fail to optimize our capital investments and the use of our other resources in furtherance of optimal business strategies, our financial position and growth may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our business plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

Our business and the natural gas industry in general have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications, and the maintenance of our financial and other records has long been dependent upon such technologies. We depend on this technology to record and store data, estimate quantities of natural gas, NGLs and oil reserves, analyze and share operating data and communicate internally and externally. Computers and mobile devices control nearly all of the natural gas, NGLs and oil distribution systems in the U.S., which are necessary to transport our products to market.

The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber or other security or physical threats, and the continuing armed conflict between Russia and Ukraine and associated economic sanctions on Russia may have increased the likelihood of such threats. We can provide no assurance that we will not suffer such attacks in the future. Deliberate attacks on, or unintentional events affecting, our digital work environment or other technologies and infrastructure, the systems or infrastructure of third parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery of natural gas, NGLs and oil, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, personal injury, property damage, other operational disruptions and third-party liability. Further, as cyber incidents continue to evolve and cyber attackers become more sophisticated, we may be required to expend additional resources to continue to

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers, and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages or higher costs. Historically, there have been shortages of personnel and equipment as demand for personnel and equipment has increased along with the number of wells being drilled. We cannot

predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could materially adversely affect our business, results of operations, cash flows and financial position.

The hydraulic fracture stimulation process on which we depend to drill and complete natural gas wells requires the use and disposal of significant quantities of water. Our ability to access sources of water and the availability of disposal alternatives to receive all of the water produced from our wells and used in hydraulic fracturing may affect our drilling and completion operations. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, or to timely obtain water sourcing permits or other rights, could adversely affect our operations. Additionally, the imposition of new, or modification of existing, environmental initiatives and regulations could include restrictions on our ability to obtain water or dispose of waste, which would adversely affect our business and results of operations, which could result in decreased cash flows.

In addition, in recent years, federal and state regulatory agencies have investigated the possible connection between the operation of injection wells used for natural gas and oil waste disposal and increased seismic activity in certain areas. In some cases, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volume or suspend operations. Increased regulation and attention given to induced seismicity in the states where we operate could lead to restrictions on our disposal well injection volume and increased scrutiny of and delay in obtaining new disposal well permits, which could result in increased operating costs whichthat could be material, or a curtailment of our operations.

Our operations are dependent upon key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, the success of our operations will depend, in part, on our ability to identify, attract, develop and retain experienced personnel. There is competition within our industry for experienced technical personnel and certain other professionals, which could increase the costs associated with identifying, attracting and retaining such personnel. If we cannot identify, attract, develop and retain our technical and professional personnel or attract additional experienced technical and professional personnel, our ability to compete in our industry could be harmed.

Our delivery of natural gas, NGLs and oil depends upon the availability, proximity and capacity of pipelines, other transportation facilities and gathering and processing facilities primarily owned by third parties, and our ability to contract with these third parties at competitive rates or at all. The capacity of transmission, gathering and processing facilities may be insufficient to accommodate potential production from existing and new wells, which may result in substantial discounts in the prices we receive for our natural gas, NGLs and oil or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Competition for access to pipeline infrastructure within the Appalachian Basin is intense, and our ability to secure access to pipeline infrastructure on favorable economic terms could affect our competitive position.

We are dependentAlthough we own and operate certain midstream infrastructure for our own use, we depend on third-party providers to provide us with access to additional midstream infrastructure to get a significant portion of our produced natural gas, NGLs and oil to market. To the extent these services are delayed or unavailable, we would be unable to realize revenue from wells served by such facilitiesthird-party infrastructure until suitable arrangements are made to market our production. Access to midstream assets may be unavailable due to market conditions or mechanical or other reasons. In addition, due to regulatory and economic constraints, construction of new pipelines and building of such infrastructure may occur more slowly. A lack of access to needed infrastructure, or an extended interruption of access to or service from third-party pipelines and facilities for any reason, including vandalism, terroristic acts, sabotage or cyber-attacks on such pipelines and facilities or service interruptions due to gas quality, could result in adverse consequences to us, such as delays in producing and selling our natural gas, NGLs and oil.

Finally, in order to ensure access to certain midstream facilities, we have entered into agreements that obligate us to pay demand charges to various pipeline operators. We also have commitments with third parties for processing capacity. We may be obligated to make payments under these agreements even if we do not fully use the capacity we have reserved, and these payments may be significant.

Historically, we have received the substantial majority of our natural gas gathering, transmission and storage and water services from EQM.Equitrans Midstream. Additionally, on February 26, 2020, we executed a gas gathering agreement with EQMa wholly-owned subsidiary of Equitrans Midstream (the Consolidated GGA), which, among other things, consolidated the majority of our prior gathering agreements with EQMEquitrans Midstream and its subsidiaries into a single agreement, established a new fee structure for gathering and compression fees charged by EQM,Equitrans Midstream, increased our minimum volume commitments with EQM,Equitrans Midstream, committed certain of our remaining undedicated acreage to EQMEquitrans Midstream and extended our and EQM'sEquitrans Midstream's contractual obligations with each other to 2035. Because we have significant long-term contractual commitments with EQM,Equitrans Midstream, we expect to receive the majority of our midstream and water services from EQMEquitrans Midstream for the foreseeable future. Therefore, any event, whether in our areas of operation or otherwise, that adversely affects Equitrans Midstream's operations, water assets, pipelines, other transportation facilities, gathering and processing facilities, financial condition, leverage, results of operations or cash flows will have a disproportionately adverse effect on our business and operating results as compared to similar events experienced by our other third-party service providers. Accordingly, we are subject to the business risks of Equitrans Midstream, including the following:

    

In addition, many of our midstream services obligations with EQMEquitrans Midstream are "firm" commitments, under which we have reserved an agreed upon amount of pipeline or storage capacity with EQMEquitrans Midstream regardless of the capacity that we actually use during each month, and we are generally obligated to pay a fixed, monthly charge, at an amount agreed upon in the contract. Because these

Substantially all of our producing properties are geographically concentrated in the Appalachian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by, and costs associated with, governmental regulation, state and local political activities, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other weather-related conditions, interruption of the processing or transportation of natural gas, NGLs or oil and changes in state and local laws, judicial precedents, political regimes and regulations. Such conditions could materially adversely affect our results of operations and financial position.

In addition, a number of areas within the Appalachian Basin have historically been subject to mining operations. For example, third parties may engage in subsurface coal and other mining operations near or under our properties, which could cause subsidence or other damage to our properties, adversely impact our drilling operations or adversely impact third-party midstream activities on which we rely. In such event, our operations may be impaired or interrupted, and we may not be able to recover the costs incurred as a result of temporary shut-ins or the plugging and abandonment of any of our wells. Furthermore, the existence of mining operations near our properties could require coordination to avoid adverse impacts as a result of drilling and mining in close proximity. These restrictions on our operations, and any similar restrictions, could cause delays or interruptions or prevent us from executing our business strategy, which could materially adversely affect our results of operations and financial position.

Further, insufficient takeaway capacity in the Appalachian Basin could cause significant fluctuations in our realized natural gas prices. The Appalachian Basin has experienced periods in which production has surpassed local takeaway capacity, resulting in substantial discounts in the price received by producers such as us and production possibly being shut in. Although additional Appalachian Basin takeaway capacity has been added in recent years, the existing and expected capacity may not be sufficient to keep pace with the increased production caused by accelerated drilling in the area in the short term.

Due to the concentrated nature of our portfolio of natural gas properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.

Climate change lawsexpectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings could lead to increased negative investor sentiment towards us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and cost of capital. In addition, failure or a perception (whether or not valid) of failure to implement our ESG strategy or achieve sustainability goals and targets we have set, could damage our reputation, causing our investors or consumers to lose confidence in our company, and negatively impact our operations. Our continuing efforts to research, establish, accomplish and accurately report on the implementation of our ESG strategy, including any climate or other ESG goals, may also create additional operational risks and expenses and expose us to reputational, legal and other risks. For example, growing interest on the part of investors and regulators in ESG factors and increased demand for, and scrutiny of, ESG-related disclosure by stakeholders has also increased the risk that companies could be perceived as, or accused of, making inaccurate or misleading statements regarding their ESG-related claims, goals, targets, efforts or initiatives, often referred to as "greenwashing." Such perception or allegation could damage our reputation and result in litigation or regulatory actions.

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, in recent years severalnumerous laws and regulations at the federal and state level have been adopted, and more are being considered, to regulate the emission of carbon dioxide, methane and other GHGs.

In February 2021, the U.S. formally rejoined the Paris Agreement, an international treaty signed by nearly 200 counties which calls for countries to set their own GHG emissions targets and to be transparent about the measures they will implement to achieve their GHG emissions targets. In furtherance of the objectives of the Paris Agreement, in April 2021,November 2022 at COP27, the Biden Administration announced goals aimed at reducing the U.S.’s GHG emissions by 50-52% (compared to 2005 levels) by 2030. The federal government has correspondingly instituted several regulations and initiatives in alignment with the goal of reducing the U.S.’s GHG emissions. Most recently, at COP27, President Biden announced the EPA’s proposed standards to reduce methane emissions from existing oil and gas sources, and agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. VariousIn November 2023, the European Union reached a provisional political agreement on a regulation to track and reduce methane emissions in the energy sector. The regulation introduces new requirements for the oil and gas sectors to measure, report and verify methane emissions and implements mitigation measures to avoid such emissions. The regulation also introduces new methane reporting and verification measures required to be applied by exporters to the European Union by January 1, 2027 and "maximum methane intensity values" must be met by 2030. Each member state will have the power to impose administrative penalties for failure to comply with such regulation and local governments have also publicly committedthe standard will be mandatory for supply contracts signed after the law takes effect. The U.S. federal government has correspondingly instituted several regulations and initiatives in alignment with the goal of reducing the U.S.'s methane and other GHG emissions. Most recently, at COP28, President Biden announced the EPA's final standards to furtheringreduce methane emissions from new and existing oil and gas sources. Additionally, at COP28, nearly 200 countries, including the United States, entered into an agreement that calls for actions towards achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030. The goals of the Paris Agreement.agreement, among other things, are to accelerate efforts towards the phase-down of unabated coal power, phase out certain fossil fuel subsidies, and take other measures directed at driving the transition away from fossil fuels in energy systems.

In June 2021, President Biden signed legislation reinstituting regulations which were previously repealed byrecent years, the Trump Administration establishing NSPS forEPA has proposed and adopted amendments to existing rules as well as new rules directed at restricting the amount of methane and VOCother GHG emissions from new and modifiedexisting oil and natural gas production and natural gas processing and transmission facilities. Additionally, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD construction and Title V operating permit reviewsSee Item 1., "Business-Regulation-Air Emissions" for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet "best available control technology" standards that will be established by the states or, in some cases, by the EPA on a case‑by‑case basis. Furthermore, in November 2021, the EPA announced proposed rules expanding upon the NSPS rule which would establish standards for existing wells, impose more frequent and stringent leak monitoring, and mandate that all pneumatic controllers have zero emissions. On November 11, 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to identify large emissions events, referred to in the proposed rule as “super emitters.” The EPA is expected to issue a final rule by May 2023.information. These federal rulemakings and regulations could adversely affect our operations and restrict or delay our ability to obtain air permits.

InAt the U.S. federal level, in November 2021, Congress approved a $1 trillion legislative infrastructure package known as the Inflation Reduction Act of 2022, which includes a number of climate-focused spending initiatives, targeted at climate resilience, enhanced response and preparation for extreme weather events, and clean energy and transportation investments. The Inflation Reduction Act also provides significant funding and incentives for research and development of low-carbon energy production methods, carbon capture, and other programs directed at addressing climate change, including imposing a fee onknown as a facility’s"waste emission charge" on methane emissions from certain natural gas and oil facilities that are in excess of a specified threshold. In January 2024, the EPA proposed a rule implementing the IRA's methane emissions charge. The proposed rule includes potential methodologies for calculating the amount by which a facility's reported methane emissions are below or exceed the waste emissions thresholds and contemplates approaches for implementing certain exemptions created by the IRA. Further, in July 2023, the EPA proposed to expand the scope of emissions events that are reportable under the Greenhouse Gas Reporting Program for petroleum and natural gas systems (Subpart W), which may result in an increase in reported methane and other GHG emissions under Subpart W for many operators, including us. The rule is currently scheduled to be finalized in the spring of 2024 and would take effect on January 1, 2025.

At the state level, several states including Pennsylvania have proceeded withAdditionally, a number of U.S. state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of carbon taxes, policies and incentives to encourage the use of renewable energy or alternative low-carbon

fuels, the development of greenhouse gas incentives, cap-and-trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. In October 2019, Pennsylvania Governor Tom Wolf signed an Executive Order directing the PADEP to draft regulations establishing a cap-and-trade program under its existing authority to regulate air emissions, with the intent of enabling Pennsylvania to join RGGI, a multi-state regional cap-and-trade program comprised of several Eastern U.S. states. Pennsylvania became a member of RGGI in April 2022, though its membership is currently the subject of legal challenges. Depending on the outcome of such litigation, Pennsylvania’s membership in RGGI will result in increased operating costs should we be required to purchase emission allowances in connection with our operations.

It is not possible at this time to predict how legislation or new regulations that may be adopted to addressreduce or restrict methane and other GHG emissions would impact our business,business. However, any suchlegislation or regulatory programs at the international, federal, state or city levels designed to reduce methane or other GHG emissions could increase the cost of consuming, and thereby reduce demand for, the natural gas, NGLs and oil we produce. Existing laws and regulations and any future laws and regulations of this nature, including those imposing reporting obligations, on, or imposing a tax or fee or otherwise limiting emissions of methane or other GHGs from our equipment and operations could require us to incur costs to comply with such regulations.regulations, including costs to monitor and report on GHG emissions, install new equipment to reduce emissions of GHGs associated with our operations, acquire emissions allowances or comply with new regulatory requirements. Substantial limitations or taxes or fees on methane or other GHG emissions, as well as other regulatory incentives or requirements to conserve energy, use alternative sources or reduce GHG emissions in product supply chains, could also adversely affect demand for the natural gas, NGLs and oil we produce, stimulate demand for alternative forms of energy that do not rely on combustion of fossil fuels, and lower the value of our reserves.

Our exploration and production operations are subject to various types of federal, state and local laws and regulations, including regulations related to the location of wells; the method of drilling, well construction, well stimulation, hydraulic fracturing and casing design; water withdrawal and procurement for well stimulation purposes; well production; spill prevention plans; the use, transportation, storage and disposal of water and other fluids and materials, including solid and hazardous wastes, incidental to natural gas and oil operations; surface usage and the reclamation of properties upon which wells or other facilities have been located; the plugging and abandoning of wells; the calculation, reporting and disbursement of royalties and taxes; and the gathering of production in certain circumstances.

Our operations are also subject to conservation and correlative rights regulations, including the regulation of the size of drilling and spacing units or field rule units; setbacks; the number of wells that may be drilled in a unit or in close proximity to other wells; drilling in the vicinity of coal mining operations and certain other structures; and the unitization or pooling of properties. Some states allow the statutory pooling and unitization of tracts to facilitate development and exploration, as well as joint development of existing contiguous leases. In addition, state conservation and natural gas and oil laws generally limit the venting or flaring of natural gas and may set production allowances on the amount of annual production permitted from a well.

Environmental and occupational health and safety legal requirements govern discharges of substances into the air, ground and water; the management and disposal of hazardous substances and wastes; the clean-up of contaminated sites; groundwater quality and availability; plant and wildlife protection; locations available for drilling; environmental impact studies and assessments prior to permitting; restoration of drilling properties after drilling is completed; and work practices related to employee health and safety.

To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Maintaining compliance with the laws, regulations and other legal requirements applicable to our business and any delays in obtaining related authorizations may affect the costs and timing of developing our natural gas, NGLs and oil resources. These requirements could also subject us to claims for personal injuries, property damage and other damages. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs

could materially adversely affect our results of operations, cash flows and financial position. Our failure to comply with the laws, regulations and other legal requirements applicable to our business, even if as a result of factors beyond our control, could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages as well as corrective action costs.

We are subject to taxation by various governmental authorities at the federal, state and local levels in the jurisdictions in which we operate. New legislation could be enacted by these governmental authorities, which could increase our tax burden and increase the cost to produce natural gas. Members of Congress periodically introduce legislation to revise U.S. federal income tax laws which could have a material impact on us. Most recently, on August 16, 2022,In recent years, legislation commonly known ashas been proposed that would, if enacted, make significant changes to U.S. tax laws, including the Inflation Reduction Act was signed into law. Among other things,reduction or elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the Inflation Reduction Act includes a 1% excise tax on corporate stock repurchases, applicable to repurchases made after December 31, 2022, and also a new minimum tax based on book income. We are in the process of evaluating the potential impactsrepeal of the Inflation Reduction Act to us. While we do not currently expectpercentage depletion allowance for oil and natural gas properties, (ii) the Inflation Reduction Act to have a material impact on our financial statements, our analysiselimination of current deductions for intangible drilling and development costs, and (iii) an extension of the effectamortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of the Inflation Reduction Act on us is ongoingany legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions or credits that are currently available with respect to oil and incomplete,natural gas exploration and it is possible that the Inflation Reduction Act (or implementing regulations and other guidance)development, which could adversely impact our currentearnings, cash flows and deferred federal tax liability.financial position. Additionally, state and local taxing authorities in

We use financial derivative instruments to hedge the impact of fluctuations in natural gas, NGLs and oil prices on our results of operations and cash flows. As disclosed above in Item 1., "Business-Regulation," the Dodd-Frank Act, the rules adopted thereunder and various other foreign regulations could increase the cost of our derivative contracts, alter the terms of our derivative contracts, reduce the availability of derivatives to protect against the price risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and lessen the number of available counterparties and, in turn, increase our exposure to less creditworthy counterparties. If our use of derivatives is reduced as a result of the Dodd-Frank Act, related regulations or such foreign regulations, our results of operations may become more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for, and fund, our capital expenditure requirements. Any of these consequences could have a material adverse effect on our business, financial position and results of operations. We have experienced increased, and anticipate additional, compliance costs and changes to current market practices as participants continue to adapt to a changing financial regulatory environment.

We use hydraulic fracturing in the completion of our wells. Hydraulic fracturing typically is regulated by state natural gas and oil commissions, but the EPA prohibits the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Certain governmental reviews have been conducted or are underway that focus on the environmental aspects of hydraulic fracturing practices. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have sought to ban hydraulic fracturing altogether. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from constructing wells. See Item 1., "Business-Regulation-Environmental, Health and Safety Regulation" for more information.

We may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our exploration, development and production activities. These delays, costs and liabilities could arise under a wide range of federal, state and local laws and regulations relating to protection of the environment and occupational health and workplace safety, including regulations and enforcement policies that have tended to become increasingly strict over time, resulting in longer waiting periods to receive permits and other regulatory approvals. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of clean-up and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.

Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental and occupational health and workplace safety impacts of our operations. We have been named from time to time as a defendant in litigation related to such matters.

In addition, new or additional laws and regulations, new interpretations of existing requirements or changes in enforcement policies could impose unforeseen liabilities, significantly increase compliance costs or result in delays of, or denial of rights to

Our operations can be adversely affected by regulations designed to protect various wildlife, including threatened and endangered species and their critical habitat. The implementation of measures to protect wildlife or the designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in constraints on our exploration, production and productionmidstream activities. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

We periodically engage in acquisitions, dispositions and other strategic transactions, including joint ventures. These transactions involve various inherent risks, such as our ability to obtain the necessary regulatory and third-party approvals; the timing of and conditions imposed upon us by regulators in connection with such approvals; the assumption of, or retaining, potential environmental or other liabilities; and our ability to realize the benefits expected from the transactions. In addition, various factors, including prevailing market conditions, could negatively impact the benefits we receive from these transactions. With respect to dispositions in particular, various factors could materially affect our ability to dispose of assets if and when we decide to do so, including the availability of purchasers willing to purchase the assets at prices acceptable to us, particularly in times of reduced and volatile commodity prices. Competition for strategic transaction opportunities in our industry is intense and may increase the cost of, reduce the benefits from, or cause us to refrain from, completing such transactions. Joint

Moreover, joint venture arrangements may restrict our operational and corporate flexibility.

venture. Our inability to complete a transaction or to achieve our strategic or financial goals in any transaction could have significant adverse effects on our earnings, cash flows and financial position.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements. Even if such a lawsuit is without merit, defending against these

Successful property acquisitions including assets we intend to acquire in the Tug Hill and XcL Midstream Acquisition, require an assessment of a number of factors beyond our control. These factors include estimates of recoverable reserves; exploration potential; future natural gas, NGLs and oil prices and their appropriate differentials; availability and cost of transportation of production to markets; availability and cost of drilling equipment and of skilled personnel; development and operating costs, including access to water; production taxes; potential environmental and other liabilities; and regulatory, permitting and similar matters. These assessments are complex and inherently imprecise. Our review of the properties and other assets we acquire may not reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well or lease that we acquire, and even when we inspect a well or lease, we may not discover structural, subsurface or environmental problems that may exist or arise. In connection with our assessment of the assets of the Upstream Seller, we have performed a review of the subject properties that we believe to be generally consistent with industry practices. The review was based on our analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines without review by an independent petroleum engineering firm. Data used in such review was furnished by the Sellers or obtained from publicly available sources. Our review may not reveal all existing or potential problems or permit us to fully assess the deficiencies and potential recoverable reserves for all of the Upstream Seller's assets, and the reserves and production related to the Upstream Seller's assets may differ materially after such data is reviewed by an independent petroleum engineering firm or further by us. Inspections were not performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken.

There may be threatened or contemplated claims against the assets or businesses we acquire related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We often assume certain liabilities, and we may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and our contractual indemnification may not be effective. At times, we acquire interests in properties on an "as is" basis with limited representations and warranties and limited remedies for breaches of such representations and warranties. In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties.

Also, our ability to achieve the anticipated benefits of an acquisition including the Tug Hill and XcL Midstream Acquisition, will depend in part upon whether we can integrate the acquired assets and their operations into our existing business in an efficient and effective manner. The integration process may be subject to delays or changed circumstances, and we can give no assurance that acquired assets we acquire will perform in accordance with our expectations or that our expectations with respect to integration or cost savings as a result of an acquisition such as the Tug Hill and XcL Midstream Acquisition, will materialize.

In connection with our 2018 spin-off of Equitrans Midstream as a separate, publicly-traded company, we obtained a private letter ruling from the IRS and an opinion of outside counsel regarding the qualification of the distribution of Equitrans Midstream shares to our shareholders (the Distribution), together with certain related transactions, as a transaction that is generally tax-free, for U.S. federal income tax purposes, under Sections 355 and 368(a)(1)(D) of the U.S. Internal Revenue Code, as amended, and certain other U.S. federal income tax matters relating to the Distribution and certain related transactions. The IRS private letter ruling and the opinion of counsel are based on and rely on, among other things, various facts and assumptions, as well as certain representations, statements and undertakings of us and Equitrans Midstream, including those relating to the past and future conduct of us and Equitrans Midstream. If any of these representations, statements or undertakings is, or becomes, inaccurate or incomplete, or if we or Equitrans Midstream breach any representations or covenants contained in any of the spin-off-related agreements and documents or in any documents relating to the IRS private letter ruling

and/or the opinion of counsel, we and our shareholders may not be able to rely on the IRS private letter ruling or the opinion of counsel.

Notwithstanding receipt of the IRS private letter ruling and the opinion of counsel, the IRS could determine on audit that the Distribution and/or certain related transactions should be treated as taxable transactions for U.S. federal income tax purposes if it determines that any of the representations, assumptions or undertakings upon which the IRS private letter ruling was based are false or have been violated or if it disagrees with the conclusions in the opinion of counsel that are not covered by the ruling or for other reasons. An opinion of counsel represents the judgment of such counsel and is not binding on the IRS or any court, and the IRS or a court may disagree with the conclusions in such opinion of counsel. Accordingly, notwithstanding receipt of the IRS private letter ruling and the opinion of counsel, there can be no assurance that the IRS will not assert that the Distribution and/or certain related transactions should be treated as taxable transactions or that a court would not sustain such a challenge. In the event the IRS were to prevail with such challenge, we, Equitrans Midstream and our shareholders could be subject to material U.S. federal and state income tax liabilities. In connection with the spin-off, we and Equitrans Midstream entered into a tax matters agreement, which described the sharing of any such liabilities between us and Equitrans Midstream.

 

None.

 

See Item 1., "Business" for a description of our properties. Our corporate headquarters is located in leased office space in Pittsburgh, Pennsylvania. We also own or lease office space in Pennsylvania, West Virginia and Texas.

 

In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against us. While the amounts claimed may be substantial, we are unable to predict with certainty the ultimate outcome of such claims and proceedings. We accrue legal and other direct costs related to loss contingencies when actually incurred. We have established reserves in amounts that we believe to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, we believe that the ultimate outcome of any pending matter involving us will not materially affect our financial position, results of operations or liquidity.

 

Not Applicable.

All executive officers have either elected to participate in the EQT Corporation Executive Severance Plan, which includes confidentiality and non-compete provisions, or executed non-compete agreements with EQT Corporation, and each of the executive officers serve at the pleasure of our Board of Directors. Officers are appointed annually to serve during the ensuing year or until their successors are elected and qualified, or until death, resignation or removal.

 

Our common stock is traded on the New York Stock Exchange under the symbol "EQT."

 

As of February 10, 2023,9, 2024, there were 1,8201,735 shareholders of record of our common stock.

 

On February 9, 2023,8, 2024, our Board of Directors declared a quarterly cash dividend of $0.15$0.1575 per share of EQT Corporation common stock, payable on March 1, 2023,2024, to shareholders of record at the close of business on February 21, 2023.20, 2024.

The amount and timing of dividends declared and paid by us, if any, are subject to the discretion of our Board of Directors and depends on business conditions, such as our results of operations and financial condition, strategic direction and other factors. Our Board of Directors havehas the discretion to change the dividend rate at any time for any reason.

The following table sets forth our repurchases ofWe did not repurchase any equity securities registered under Section 12 of the Exchange Act that have occurred during the three months ended December 31, 2022.2023.

 

The following graph below compares the most recent cumulative five-year total return provided to shareholders of our common stock relative to the cumulative five-year total returns of the S&P 500 Index, the S&P MidCap 400 Index and two customized peer groups, the 20212022 Self-Constructed Peer Group and 2022the 2023 Self-Constructed Peer Group, whose company composition is discussed in footnotes (a) and (b), respectively, below. Our common stock was included in the S&P 500 Index until November 2018, at which time our common stock was added to the S&P MidCap 400 Index. Our common stock was added back to the S&P 500 Index in October 2022. Accordingly, we have presented both indices for comparison in the following graph. An investment of $100, with reinvestment of all dividends, is assumed to have been made in our common stock, in the S&P 500 Index, the S&P MidCap 400 Index and in each of the peer groups on December 31, 20172018 and its relative performance is tracked through December 31, 2022. Historical prices prior to November 2018 have been adjusted to reflect the spin-off of our midstream business in 2018.2023. The stock price performance shown in the graph below is not necessarily indicative of future stock price performance.

 

 

Net income attributable to EQT Corporation for 20222023 was $1,735 million, $4.22 per diluted share, compared to $1,771 million, $4.38 per diluted share, compared to net loss attributable to EQT Corporation for 2021 of $1,143 million, $3.54 per diluted share.2022. The changedecrease was attributable primarily to increaseddecreased sales of natural gas, NGLs and oil, partly offset by income tax expense, greatera gain on derivatives in 2023 compared to a loss on derivatives thein 2022, impairment of ourthe contract asset (discussed in Note 5 to the Consolidated Financial Statements), increased transportation and processing in 2022, decreased income tax expense and increaseda loss on debt extinguishment.extinguishment in 2022.

Results of operations for 2022 and for the period beginning July 21, 2021 and endingAugust 22, 2023 through December 31, 20212023 include the results of our operation of assets acquired in the AltaTug Hill and XcL Midstream Acquisition. See Note 6 to the Consolidated Financial Statements for further discussion.discussion of the Tug Hill and XcL Midstream Acquisition.

See "Sales Volume and Revenues" and "Operating Expenses" for discussions of items affecting operating income and "Other Income Statement Items" for a discussion of other income statement items. See "Investing Activities" under "Capital Resources and Liquidity" for a discussion of capital expenditures.

Our sales volume and operating expenses for 2022on a per Mcfe basis during the first half of 2023 were negatively impacted by fewer wells turned-in-line and adjustmentsduring 2022 compared to our 2022 planned development schedule due to third-party supply chain constraints. In addition, as a result of third-party supply chain constraints. Strong underlying well performanceconstraints in 2022, we shifted the planned development of approximately 30 wells from 2022 to 2023 (the Rescheduled Wells). All of the Rescheduled Wells were completed and field optimization helped mitigateturned-to-sales as of July 2023, resulting in our third quarter 2023 sales volumes returning to our normalized level of production; however, our sales volume during the impactssecond half of 2023 was negatively impacted by approximately 13 Bcfe of curtailments (inclusive of non-operated wells in which we have a working interest) principally in response to 2022 sales volume; however,lower natural gas prices in the Appalachian Basin. Future supply chain constraints or declines in natural gas prices may continueresult in adjustments to our 2024 planned development schedule or the development schedule of non-operated wells in which we have a working interest. Further, we cannot control or otherwise influence the development schedule of non-operated wells in which we have a working interest. Adjustments to our 2024 planned development schedule or the development schedule of non-operated wells in which we have a working interest, including due to declines in natural gas prices, the pace of well completions, access to sand and water to conduct drilling operations, access to sufficient pipeline takeaway capacity, unscheduled downtime at processing facilities or otherwise, could impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.

The annual inflation rate in the United States was particularly highincreased rapidly during 2022, and, many analysts anticipatealthough the inflation will remainrate decreased through 2023, it still remains elevated through 2023.compared to the rate of inflation over the prior five years. Inflationary pressures have multiple impacts on our business, including increasing our operating expenses and our cost of capital. Furthermore,While the prices for certain of the raw materials and services we use in our operations have generally decreased from the peak prices experienced during 2022, we will not fully realize the benefit of such reduced prices until we enter into new contracts for such materials and services, and inflationary pressures may cause prices to fluctuate. Additionally, certain of our commitments for demand charges under our existing long-term contracts and processing capacity are subject to consumer price index adjustments. Although we believe our scale and supply chain contracting strategy of using multi-year sand and frac crew contracts allows us to maximize capital and operating efficiencies, future increases in the inflation rate will negatively impact our long-term contracts with consumer price index adjustments.

While the prices for natural gas, NGLs and oil have historically been volatile, price volatility was especially pronounced during 2022. The daily spot prices for NYMEX Henry Hub2022, with natural gas ranged from a highprices peaking in August 2022, then steadily declining into the first half of $9.85 per MMBtu to a low2023. The second half of $3.46 per MMBtu between the period from January 1, 2022 through December 31, 2022, and the daily spot2023 saw moderate increases in natural gas prices; however, on average, prices for NYMEX West Texas Intermediate crude oil ranged from a high of $123.64 per barrel to a low of $71.05 per barrel during the same period.in 2023 remained lower than in 2022. We expect commodity price volatilityprices to continue or increasebe volatile throughout 20232024 due to rising macroeconomic uncertainty and geopolitical tensions, including the Russiandevelopments pertaining to Russia's invasion of Ukraine which beganand conflicts in February 2022 and has put upward pressure on natural gas and oil prices.the Middle East. Our revenue, profitability, rate of growth, liquidity and financial position will continue to be impacted in the future by the market prices for natural gas and, to a lesser extent, NGLs and oil.

The following table presents detailed natural gas and liquids operational information to assist in the understanding of our consolidated operations, including the calculation of our average realized price ($/Mcfe), which is based on adjusted operating