EQT 10-K 2020-12-31

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

or

COMMISSION FILE NUMBER 001-03551

EQT CORPORATION

(Exact name of registrant as specified in its charter)

(412) 553-5700

(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

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.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

The aggregate market value of common stock held by non-affiliates of the registrant as of June 30, 2020: $3.0 billion

As of February 12, 2021, 278,854,465 shares of common stock, no par value, of the registrant were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

EQT Corporation's definitive proxy statement relating to its 2021 annual meeting of shareholders will be filed with the Securities and Exchange Commission within 120 days after the close of EQT Corporation's fiscal year ended December 31, 2020 and is incorporated by reference in Part III to the extent described therein.

Table of Contents

TABLE OF CONTENTS

Table of Contents

Glossary of Commonly Used Terms, Abbreviations and Measurements

Unless the context otherwise indicates, all references in this report to "EQT," the "Company," "we," "us," or "our" are to EQT Corporation and its subsidiaries, collectively.

Commonly Used Terms

Appalachian Basin – the area of the United States composed of those portions of West Virginia, Pennsylvania, Ohio, Maryland, Kentucky and Virginia that lie in the Appalachian Mountains.

basis – when referring to commodity pricing, the difference between the futures price for a commodity and the corresponding sales price at various regional sales points. The differential commonly is related to factors such as product quality, location, transportation capacity availability and contract pricing.

British thermal unit – a measure of the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit.

collar – a financial arrangement that effectively establishes a price range for the underlying commodity. The producer bears the risk and benefit of fluctuation between the minimum (floor) price and the maximum (ceiling) price.

continuous accumulations – natural gas and oil resources that are pervasive throughout large areas, have ill-defined boundaries and typically lack, or are unaffected by, hydrocarbon-water contacts near the base of the accumulation.

conventional reservoir – an area believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps utilizing conventional recovery methods.

development well – a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

exploratory well – a well drilled to find a new field or new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.

extension well – a well drilled to extend the limits of a known reservoir.

gas – all references to "gas" in this report refer to natural gas.

gross – "gross" natural gas and oil wells or "gross" acres equal the total number of wells or acres in which we have a working interest.

hedging – the use of derivative commodity and interest rate instruments to reduce financial exposure to commodity price and interest rate volatility.

horizontal drilling – drilling that ultimately is horizontal or near horizontal to increase the length of the well bore penetrating the target formation.

horizontal wells – wells that are drilled horizontal or near horizontal to increase the length of the well bore penetrating the target formation.

natural gas liquids (NGLs) – those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation or other methods in gas processing plants. Natural gas liquids include primarily ethane, propane, butane and isobutane.

net – "net" natural gas and oil wells or "net" acres are determined by adding the fractional ownership working interests we have in gross wells or acres.

net revenue interest – the interest retained by us in the revenues from a well or property after giving effect to all third-party interests (equal to 100% minus all royalties on a well or property).

Table of Contents

option – a contract that gives the buyer the right, but not the obligation, to buy or sell a specified quantity of a commodity or other instrument at a specific price within a specified period of time.

play – a proven geological formation that contains commercial amounts of hydrocarbons.

productive well – a well that is producing oil or gas or that is capable of production.

proved reserves – quantities of natural gas, NGLs and oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

proved developed reserves – proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

proved undeveloped reserves (PUDs) – proved reserves that can be estimated with reasonable certainty to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.

reliable technology – a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonable certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

reservoir – a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

service well – a well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include, among other things, gas injection, water injection and salt-water disposal.

stratigraphic test well – a hole drilled for the sole purpose of gaining structural or stratigraphic information to aid in exploring for oil and gas.

well pad – an area of land that has been cleared and leveled to enable a drilling rig to operate in the exploration and development of a natural gas or oil well.

working interest – an interest that gives the owner the right to drill, produce and conduct operating activities on a property and receive a share of any production.

Abbreviations

Table of Contents

Measurements

Table of Contents

CAUTIONARY STATEMENTS

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, 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. 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," section "Impairment of Oil and Gas Properties" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of 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 such plans and programs); the projected scope and timing of our combo-development projects; estimated reserves, including potential future downward adjustments of reserves and reserve life; total resource potential and drilling inventory duration; projected production and sales volumes and growth rates (including liquids production and sales volumes and growth rates); natural gas prices, changes in basis and the impact of commodity prices on our business; potential impacts to our business and operations resulting from COVID-19 or a similar pandemic; potential future impairments of our assets; our ability to reduce our drilling and completions costs, other costs and expenses and capital expenditures, and the timing of achieving any such reductions; 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 benefits of such initiatives; projected reductions of our gathering and compression rates resulting from our consolidated gathering agreement with EQM Midstream Partners, LP, and the anticipated cost savings and other strategic benefits associated with the execution of such agreement; monetization transactions, including asset sales, joint ventures or other transactions involving our assets, and our planned use of the proceeds from any such monetization transactions; potential acquisitions or other strategic transactions, the timing thereof and our ability to achieve the intended operational, financial and strategic benefits from any such transactions; the timing and structure of any dispositions of our remaining retained shares of Equitrans Midstream Corporation's (Equitrans Midstream's) common stock, and the planned use of the proceeds from any such dispositions; the amount and timing of any repayments, redemptions or repurchases of our common stock, outstanding debt securities or other debt instruments; our ability to reduce our debt and the timing of such reductions, if any; projected dividend amounts and rates; projected cash flows and free cash flow; projected capital expenditures; 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; 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. The 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.

Any forward-looking statement speaks only as of the date on which such statement is made, and we do not intend to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by law.

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and our development program. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs and oil that are ultimately recovered.

In reviewing any agreements incorporated by reference in or filed with this Annual Report on Form 10-K, remember such agreements are included to provide information regarding the terms of such agreements and are not intended to provide any other factual or disclosure information about us. The agreements may contain representations and warranties by us, which should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to such agreements should those statements prove to be inaccurate. The representations and warranties were intended to be relied upon solely by the applicable party to such agreement and were made only as of the date of the relevant agreement or such other date or dates as may be specified in such agreement and are subject to more recent developments. Accordingly, such representations and warranties alone may not describe our actual state of affairs or the affairs of our affiliates as of the date they were made or at any other time and should not be relied upon as statements of fact.

Table of Contents

PART I

General

We are a natural gas production company with operations focused in the Marcellus and Utica Shales of the Appalachian Basin. Based on average daily sales volumes, we are the largest producer of natural gas in the United States. As of December 31, 2020, we had 19.8 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 1.8 million gross acres, including approximately 1.5 million gross acres in the Marcellus play.

Strategy

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 and sustainability, we seek to continuously improve the way we produce environmentally responsible, reliable low-cost energy. 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 water (as opposed to truck-transported water), 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 and environmental protection.

Combo-development projects require 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.

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. We believe that combo-development projects are key to delivering sustainably low well costs and higher returns on invested capital and that our long-term transformative plan has been designed to create value by leveraging our strategic advantage, both operational and environmental, over our peers.

2020 Highlights

• Achieved 2020 sales volumes of 1,498 Bcfe or average daily sales volumes of 4.1 Bcfe per day; received an average realized price of $2.37 per Mcfe.

• Reduced 2020 capital expenditures by $694 million, or 39.1%, compared to 2019, while delivering flat sales volumes.

• Increased total proved reserves by 2.3 Tcfe or 13% in 2020 compared to 2019.

• Decreased total debt by $368 million and addressed near-term maturities, improving our financial position.

• Executed a new gas gathering agreement and exchanged half of our equity stake in Equitrans Midstream, substantially reducing our future gathering fee structure.

Table of Contents

• Acquired strategic assets from Chevron U.S.A. Inc. located in the Appalachian Basin for an aggregate purchase price of $735 million (Chevron Acquisition).

• Divested certain non-strategic assets for an aggregate purchase price of $125 million.

• Executed long-term contract to use electric hydraulic fracturing services in our completions operations, promoting our ESG initiatives.

• Received approximately $440 million in federal income tax refunds, including interest.

Outlook

In 2021, we expect to spend approximately $1.1 to $1.2 billion in total capital expenditures, excluding amounts attributable to noncontrolling interests. We expect to fund planned capital expenditures with cash generated from operations, allocated as follows: approximately $800 to $850 million to fund reserve development, approximately $125 to $140 million to fund land and lease acquisitions, approximately $130 to $155 million to fund other production infrastructure and approximately $45 to $55 million applied towards capitalized overhead. Reserve development capital expenditures will be spent across our three primary operating areas, with approximately 65% spent in Pennsylvania Marcellus, approximately 30% spent in West Virginia Marcellus, and approximately 5% spent in Ohio Utica. Our 2021 capital expenditure program is expected to deliver sales volumes of 1,620 Bcfe to 1,700 Bcfe, an increase of 120-200 Bcfe when compared to 2020 sales volumes primarily driven by increased production from the Chevron Acquisition.

Our revenues, earnings, liquidity and ability to grow 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 "Impairment of Oil and Gas Properties" and "Critical Accounting Policies and Estimates" included in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of our accounting policies and significant assumptions related to accounting for gas, NGL and oil producing activities and our accounting policies and processes related to impairment reviews for proved and unproved property.

Segment and Geographical Information

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.

Reserves

The fol

Showing the first 8K of 82K characters. Open the full section

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 occurs, our business, financial condition or results of operations could suffer and the trading price of our common stock could decline.

Summary of Risk Factors

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

• Risks Associated with Natural Gas Drilling Operations.** As a natural gas producer, there are risks inherent in our primary business operations. These risks are not necessarily unique to us, but rather, these are risks that most operators in our industry have at least some exposure to.

• Financial and Market Risks.** Given that our primary product and source of revenue is the sale of natural gas and NGLs, one of our most material risks is the commodity market and the price of natural gas and NGLs, which is often volatile. Additionally, our operations are capital intensive. Pressures on the market as a whole, or our specific financial

Table of Contents

position – whether due to depressed commodity prices, our leverage, our credit ratings or otherwise – could make it difficult for us to obtain the funding necessary to conduct our operations.

• Risks Associated with Our Human Capital, Technology and Other Resources and Service Providers.** Our business, and the U.S. energy grid, is predominately operated on a digital system. Our employees rely on our cloud-based digital work environment to communicate and access data that is necessary to conduct our day-to-day operations. While these digital systems enable us to efficiently supply our natural gas and NGLs to the market, they are also susceptible to cyber security threats. Likewise, as a digitally-focused organization, we seek employees with a high degree of both technical skill and digital literacy, and it can be difficult to attract and retain personnel who satisfy these criteria. Further, we predominately operate in the Appalachia Basin, and a substantial majority of our midstream and water services are provided by one provider, EQM Midstream Partners, LP, making us vulnerable to risks associated with operating primarily in one major geographic area and obtaining a substantial amount of our services from a single provider within that operating area.

• Legal and Regulatory Risks.** There are many environmental, energy, financial, real property and other regulations that we are required to comply with in the context of conducting our operations, otherwise, we may be exposed to fines, penalties, investigations, litigation or other legal proceedings. Additionally, negative public perception of us or the natural gas industry, or increasing consumer demand for alternatives to natural gas, could adversely impact our earnings, cash flows and financial position.

• Risks Associated with Strategic Transactions.** We have historically been involved in, and anticipate that we will continue to explore, opportunities to create value through strategic transactions, whether through mergers and acquisitions, divestitures, joint ventures or similar business transactions. There are risks inherent in any strategic transaction, and such risks could negatively affect the benefits, outcomes and synergies anticipated to be obtained from executing such strategic transactions.

• Risks Related to the COVID-19 Pandemic.** While we did not experience any material adverse effects from the COVID-19 pandemic in 2020, the severity, magnitude and duration of the COVID-19 pandemic is still uncertain, rapidly changing and difficult to predict. We believe that our principal areas of operational risk resulting from a pandemic are availability of service providers and supply chain disruption. Additionally, active development operations, including drilling and fracking operations, represent the greatest risk for transmission given the number of personnel and contractors on our drilling sites. We believe that we are following best practices under COVID-19 guidance; however, the potential for transmission still exists, and in certain instances, it may be necessary or determined advisable for us to delay our development operations.

We describe these risks in greater detail below.

Risks Associated with Natural Gas Drilling Operations

Drilling for and producing natural gas is a high-risk and costly activity with many uncertainties. Our future financial position, cash flows and results of operations will depend on the success of our development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable natural gas production or that we will not recover all or any portion of our investment in drilled wells.

Many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

• delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from permitting, wastewater disposal, discharge of greenhouse gases, and limitations on hydraulic fracturing;

• shortages of or delays in obtaining equipment, rigs, materials and qualified personnel or in obtaining water for hydraulic fracturing activities;

• equipment failures, accidents or other unexpected operational events;

• lack of available gathering and water facilities or delays in construction of gathering and water facilities;

• lack of available capacity on interconnecting transportation pipelines;

• adverse weather conditions, such as flooding, droughts, freeze-offs, slips, blizzards and ice storms;

• 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 discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

Table of Contents

• declines in natural gas, NGLs and oil market prices;

• limited availability of financing at acceptable terms;

• ongoing litigation or adverse court rulings;

• public opposition to our operations;

• title, surface access, coal mining and right of way problems; and

• limitations in the market for natural gas, NGLs and oil.

Any of these risks can cause a delay in our development program 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.

We are subject to risks associated with the operation of our wells and facilities.

Our business is subject to all of the inherent hazards and risks normally incidental to drilling for, producing, transporting and storing 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 haz

Showing the first 8K of 106K characters. Open the full section

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, Ohio, 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 matter currently pending against us will not materially impact our financial position, results of operations or liquidity.

Environmental Proceedings

Produced Water Release, Marshall County, West Virginia. On November 12, 2019, we received a Notice of Violation (NOV) from the West Virginia Department of Environmental Protection (WVDEP) relating to the Goshorn Pad in Marshall County, West Virginia. The NOV alleged violations of Water Pollution Control Rules in connection with a release of produced water from secondary containment at a Goshorn Pad tank battery. We cooperated fully with WVDEP to take appropriate actions to address the secondary containment issues and remediation of the release, and this matter was substantially resolved in March 2020. We were not assessed any monetary penalty for this matter, and the resolution of this matter did not have a material impact on our financial position, results of operations or liquidity.

Secondary Containment underneath Gas Processing Units (GPUs), Allegheny, Greene and Washington Counties, Pennsylvania. On April 1, 2020, we received a draft Consent Order and Agreement from the Pennsylvania Department of Environmental Protection (PADEP) claiming that we failed to install secondary containment systems in accordance with 25 Pa. Code § 78a.64a(b) underneath 228 GPUs located in southwest Pennsylvania between October 8, 2016 and February 4, 2019. On February 4, 2019, we voluntarily disclosed a list of GPUs that did not meet the requirements of 25 Pa. Code § 78a.64a(b). On December 17, 2020, we entered into the Consent Order and Agreement with PADEP, pursuant to which we agreed to install

Table of Contents

secondary containment systems in compliance with 25 Pa. Code § 78a.64a(b) on all new GPU installations going forward, among other things, and this matter was resolved. We were not assessed any monetary penalty for this matter, and the resolution of this matter did not have a material impact on our financial position, results of operations or liquidity.

Other Legal Proceedings

Mary Farr Secrist, et al. v. EQT Production Company, et al., Circuit Court of Doddridge County, West Virginia. On May 2, 2014, royalty owners whose predecessors had entered into a 960-acre lease (the Stout Lease) and several additional leases comprising 6,356-acres (the Cities Services Lease) with EQT Production Company's predecessor, each covering acreage in Doddridge County, West Virginia, filed a complaint in the Circuit Court of Doddridge County, West Virginia. The complaint alleged that EQT Production Company and a number of related companies, including EQT Corporation, EQT Gathering, LLC, EQT Energy, LLC, and EQM Midstream Services, LLC (formerly known as EQT Midstream Services, LLC, the general partner of our former midstream affiliate), underpaid on royalties for gas produced under the leases and took improper post-production deductions from the royalties paid. With respect to the Stout Lease, the plaintiffs also asserted that we committed a trespass by drilling on the leased property, claiming that we had no right under the lease to drill in the Marcellus Shale formation. The plaintiffs also asserted claims for fraud, slander of title, punitive damages, pre-judgment interest and attorneys' fees. The plaintiffs sought more than $100 million in compensatory damages for the trespass claim under the Stout Lease, and approximately $20 million for insufficient royalties under both the Stout Lease and the Cities Services Lease, in addition to punitive damages and other relief. On June 27, 2018, the Court held that EQT Production Company and its marketing affiliate EQT Energy, LLC are alter egos of one another and that royalties paid under the leases should have been based on the price of gas produced under the leases when sold to unaffiliated third parties, and not on the price when the gas was sold from EQT Production Company to EQT Energy, LLC. Further, on January 14, 2019, the Court entered an Order granting the plaintiffs' motion for summary judgment and declaring that we did not have the right to drill in the Marcellus Shale formation under the Stout Lease. The Court also ruled that seven of our wells that have been producing gas under the Stout Lease are trespassing, and that a jury will determine whether the trespass was willful or innocent. On February 27, 2019, we filed a motion seeking permission to immediately appeal the trespass Order to the West Virginia Supreme Court; however, the motion was denied on March 25, 2019, and the Court continued the trial to September 2019. On May 28, 2019, the Court entered an Order excluding certain of our costs that could have otherwise offset any damages for innocent trespass under the Stout Lease. On August 8, 2019, we reached a settlement with the plaintiffs to resolve all claims under the Stout Lease and the Cities Services Lease for $54 million plus lease modifications to address the trespass issue and the calculation of future royalty payments under the leases. We paid $51 million of the settlement in October 2019 and the remaining $3 million of the settlement in January 2020, and the Stout Lease was subsequently amended to address the terms agreed to with the plaintiffs under the settlement. On October 7, 2020, the plaintiffs filed a motion to amend their complaint and to stay entry of an Order of Dismissal. On January 14, 2021, we filed a motion to enforce the settlement agreed to with the plaintiffs and to seek sanctions. All recent motions are pending.

Hammerhead Gathering Agreement Dispute. EQT Corporation and Equitrans Midstream, through certain of our and their subsidiaries, are parties to a gas gathering agreement (the Hammerhead Gathering Agreement) related to Equitrans Midstream's Hammerhead Gas Gathering System. Pursuant to the terms of the Hammerhead Gathering Agreement, if the "In-Service Date" did not occur on or before October 1, 2020, we may terminate the Hammerhead Gathering Agreement and purchase the Hammerhead Gas Gathering System from Equitrans Midstream for an amount equal to 88% of expenses actually incurred and other obligations made or to be incurred by Equitrans Midstream. The "In-Service Date" is defined in the Hammerhead Gathering Agreement as "the later of (i) the first Day of the Month immediately following the date on which Gatherer is first able to provide the Gathering Services to Shipper in accordance with the Hammerhead Gathering Agreement and (ii) the first Day of the Month immediately following the date on which the Interconnect Facilities connecting the Gathering System to the Mountain Valley Pipeline are first able to receive deliveries of the Contract MDQ." On September 24, 2020, we initiated arbitration proceedings against Equitrans Midstream, seeking a declaration that we are entitled to terminate the Hammerhead Gathering Agreement and purchase the Hammerhead Gas Gathering System. The deadline for us to provide notice of our election to terminate the Hammerhead Gathering Agreement and purchase the Hammerhead Gas Gathering System has been tolled while the contract claim is pending in arbitration.

Not Applicable.

Table of Contents

Information about our Executive Officers (as of February 17, 2021)

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 elected annually to serve during the ensuing year or until their successors are elected and qualified, or until death, resignation or removal.

Table of Contents

PART II

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

As of February 12, 2021, there were 1,985 shareholders of record of our common stock.

On March 26, 2020, we announced the suspension of our quarterly cash dividend on our common stock for purposes of accelerating cash flow to be used for our Deleveraging Plan. 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 have the discretion to change the annual dividend rate at any time for any reason.

Recent Sales of Unregistered Securities

None.

Market Repurchases

We did not repurchase any equity securities registered under Section 12 of the Securities Exchange Act of 1934, as amended, during the three months ended December 31, 2020.

Stock Performance Graph

The following graph 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 Standard & Poor’s (S&P) 500 Index, the S&P MidCap 400 Index and two customized peer groups, the 2019 Self-Constructed Peer Group and 2020 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 the Separation and Distribution in 2018, following which our common stock was added to the S&P MidCap 400 Index. 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, 2015 and its relative performance is tracked through December 31, 2020. Historical prices prior to the Separation and Distribution have been adjusted to reflect the value of the Separation and Distribution. The stock price performance shown in the graph below is not necessarily indicative of future stock price performance.

Table of Contents

*$100 invested on 12/31/15 in stock, index, or peer group, including reinvestment of dividends.

Copyright© 2021 Standard & Poor’s, a division of S&P Global. All right reserved.

(a)The 2019 Self-Constructed Peer Group includes the following twelve companies: Antero Resources Corp., Cabot Oil & Gas Corp., Chesapeake Energy Corp., Cimarex Energy Co., CNX Resources Corp., Gulfport Energy Corp., Murphy Oil Corp., Ovintiv Inc. (formerly Encana Corp.), QEP Resources, Inc., Range Resources Corp., SM Energy Co. and Southwestern Energy Co. WPX Energy Inc. was included in the self-constructed peer group that served as the basis for the stock performance graph in our Annual Report on Form 10-K for the year ended December 31, 2019, but it has been excluded from the 2019 Self-Constructed Peer Group because it was acquired during 2020.

(b)The 2020 Self-Constructed Peer Group includes the following eight companies: Antero Resources Corp., Cabot Oil & Gas Corp., Chesapeake Energy Corp., CNX Resources Corp., Comstock Resources, Inc., Gulfport Energy Corp., Range Resources Corp. and Southwestern Energy Co. The 2020 Self-Constructed Peer Group is comprised of the companies included in our 2020 performance peer group, as set forth in our definitive proxy statement relating to our 2020 annual meeting of shareholders, and were selected by the Management Development and Compensation Committee of the Board of Directors for purposes of evaluating our relative total shareholder return under the 2020 Incentive Performance Share Unit Program.

Table of Contents

Not Applicable.

The following discussion and analysis of financial condition and results of operations should be read in conjunction with the Consolidated Financial Statements and the notes thereto included in Item 8., "Financial Statements and Supplementary Data."

Consolidated Results of Operations

Net loss for 2020 was $967 million, $3.71 per diluted share, an improvement of $255 million compared to net loss for 2019 of $1,222 million, $4.79 per diluted share. The variance was attributable primarily to decreased impairments, the gain on the Equitrans Share Exchange (defined and discussed in Note 5 to the Consolidated Financial Statements), decreased other operating expenses, decreased depreciation and depletion expense and decreased transportation and processing expense, partly offset by decreased operating revenues, increased interest expense and decreased dividend and other income.

See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on Form 10-K for the year ended December 31, 2019, which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year ended December 31, 2018.

See "Sales Volumes 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.

Average Realized Price Reconciliation

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 revenues, a non-GAAP supplemental financial measure. Adjusted operating revenues is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends. Adjusted operating revenues should not be considered as an alternative to total operating revenues. See "Non-GAAP Financial Measures Reconciliation" for a reconciliation of adjusted operating revenues with total operating revenues, the most directly comparable financial measure calculated in accordance with GAAP.

Table of Contents

(a)Our volume weighted NYMEX natural gas price (actual average NYMEX natural gas price ($/MMBtu)) was $2.08 and $2.63 for the years ended December 31, 2020 and 2019, respectively.

(b)Basis represents the difference between the ultimate sales price for natural gas and the NYMEX natural gas price.

(c)NGLs, ethane and oil were converted to Mcfe at a rate of six Mcfe per barrel.

(d)Total natural gas and liquids sales, including cash settled derivatives, is also referred to in this report as adjusted operating revenues, a non-GAAP supplemental financial measure.

Table of Contents

Non-GAAP Financial Measures Reconciliation

The table below reconciles adjusted operating revenues, a non-GAAP supplemental financial measure, with total operating revenues, its most directly comparable financial measure calculated in accordance with GAAP. Adjusted operating revenues (also referred to in this report as total natural gas and liquids sales, including cash settled derivatives) is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends. Adjusted operating revenues excludes the revenue impacts of changes in the fair value of derivative instruments prior to settlement and net marketing services and other. We use adjusted operating revenues to evaluate earnings trends because, as a result of the measure's exclusion of the often-volatile changes in the fair value of derivative instruments prior to settlement, the measure reflects only the impact of settled derivative contracts. Net marketing services and other primarily includes the costs of, and recoveries on, pipeline capacity releases. Because we consider net marketing services and other to be unrelated to our natural gas and liquids production activities, adjusted operating revenues excludes net marketing services and other. We believe that adjusted operating revenues provides useful information to investors for evaluating period-to-period comparisons of earnings trends.

Sales Volumes and Revenues

(a)Includes Upper Devonian wells.

(b)NGLs, ethane and oil were converted to Mcfe at a rate of six Mcfe per barrel.

Sales of natural gas, NGLs and oil. Sales of natural gas, NGLs and oil decreased for 2020 compared to 2019 due to a lower average realized price and lower sales volumes. Average realized price decreased due to lower NYMEX and unfavorable differential, partly offset by higher cash settled derivatives. For 2020 and 2019, we received $898.8 million and $266.3 million, respectively, of net cash settlements, including net premiums received, on derivatives not designated as hedges, which are included in average realized price but may not be included in operating revenues. Sales volumes for 2020 decreased compared

Table of Contents

to 2019 due primarily to our strategic decisions to temporarily curtail production beginning in May 2020 and ending in November 2020 (the Strategic Production Curtailments) which resulted in a decrease to sales volumes of approximately 46 Bcfe. Sales volumes for 2020 also decreased compared to 2019 by 16 Bcfe as a result of the 2020 Divestitures (defined in Note 7 to the Consolidated Financial Statements). These decreases were partly offset by operational efficiencies realized throughout the year from increased production up-time and positively impacted sales volumes as well as an increase of approximately 12 Bcfe due to the Chevron Acquisition.

Gain on derivatives not designated as hedges. For 2020, we recognized a gain on derivatives not designated as hedges of $400.2 million compared to $616.6 million for 2019. The gains for 2020 and 2019 were related primarily to decreases in the fair market value of our NYMEX swaps and options due to increases in NYMEX forward prices.

Operating Expenses

The following table presents information on our production-related operating expenses.

Gathering. Gathering expense increased on an absolute and per Mcfe basis for 2020 compared to 2019 due to a higher gathering rate structure as a result of the Consolidated GGA (defined in Note 5 to the Consolidated Financial Statements**)**, partly offset by lower gathered volumes as a result of the Strategic Production Curtailments. We expect to realize fee relief and a lower gathering rate structure from the Consolidated GGA beginning on the Mountain Valley Pipeline in-service date.

Transmission. Transmission expense decreased on an absolute and per Mcfe basis for 2020 compared to 2019 due primarily to released capacity on, and credits received from, the Texas Eastern Transmission Pipeline, partly offset by higher costs associated with additional capacity on the Tennessee Gas Pipeline.

LOE. LOE increased on an absolute and per Mcfe basis for 2020 compared to 2019 due primarily to higher repairs and maintenance costs as a result of our increased focus on optimizing production from currently producing wells as well as higher salt water disposal costs.

Table of Contents

Production taxes. Production taxes decreased on an absolute and per Mcfe basis for 2020 compared to 2019 due primarily to lower severance taxes and Pennsylvania impact fees as a result of lower commodity prices.

Depreciation and depletion. Production depletion decreased on an absolute and per Mcfe basis for 2020 compared to 2019 due primarily to a lower annual depletion rate and lower volumes.

Amortization of intangible assets. Amortization of intangible assets for 2020 was $26.0 million compared to $35.9 million for 2019. The decrease was due primarily to the impairment of intangible assets recognized in the third quarter of 2019 as described below, which decreased the amortization rate. The intangible assets were fully amortized in November 2020.

Impairment/loss on sale/exchange of long-lived assets. During 2020, we recognized a loss on sale/exchange of long-lived assets of $100.7 million, of which $61.6 million related to the 2020 Asset Exchange Transactions (defined and discussed in Note 6 to the Consolidated Financial Statements) and $39.1 million related to asset sales (described in Note 7 to the Consolidated Financial Statements). During the fourth quarter of 2019, we recorded impairment of long-lived assets of $1,124.4 million, of which $1,035.7 million was associated with our non-strategic assets located in the Ohio Utica and $88.7 million was associated with our Pennsylvania and West Virginia Utica assets. The impairment was due primarily to depressed natural gas prices and changes in our development strategy. During the third quarter of 2019, we recorded a loss on exchange of long-lived assets of $13.9 million related to the 2019 Asset Exchange Transaction (defined and discussed in Note 6 to the Consolidated Financial Statements). See Note 1 to the Consolidated Financial Statements for a discussion of the 2019 impairment test.

Impairment of intangible and other assets. During the fourth quarter of 2020, we recognized impairment of $34.7 million, of which $22.8 million related to our assessment that the fair values of certain of our right-of-use lease assets were less than their carrying values and $11.9 million related to impairments of certain non-operating receivables as a result of expected credit losses. During the third quarter of 2019, we recognized impairment of $15.4 million of intangible assets associated with non-compete agreements for former Rice Energy Inc. executives who are now our employees.

Impairment and expiration of leases. Impairment and expiration of leases for 2020 was $306.7 million compared to $556.4 million for 2019. The decrease was driven by increased lease expirations in 2019 due to our change in strategic focus to core development opportunities as well as changes in market conditions.

Other operating expenses. Other operating expenses of $28.5 million in 2020 were related primarily to transactions, changes in legal reserves, including settlements and reorganization. Other operating expenses of $199.4 million in 2019 were related primarily to reorganization, due to reductions in workforce, which resulted in the recognition of severance and other termination benefits, changes in legal reserves, including settlements, contract terminations and the proxy contest. See Note 1 to the Consolidated Financial Statements.

Other Income Statement Items

Gain on Equitrans Share Exchange. During the first quarter of 2020, we recognized a gain on the Equitrans Share Exchange as described in Note 5 to the Consolidated Financial Statements.

Loss on investment in Equitrans Midstream Corporation. Our investment in Equitrans Midstream is recorded at fair value by multiplying the closing stock price of Equitrans Midstream's common stock by the number of shares of Equitrans Midstream's common stock that we own. Changes in fair value are recorded in loss on investment in Equitrans Midstream Corporation in the Statements of Consolidated Operations. Our investment in Equitrans Midstream fluctuates with changes in Equitrans Midstream's stock price, which was $8.04 and $13.36 as of December 31, 2020 and 2019, respectively. Note, the effect of the sale of 50% of our shares of Equitrans Midstream's common stock was recorded as a reduction to the investment in Equitrans Midstream in conjunction with our recognition of the gain on the Equitrans Share Exchange. See Note 5 to the Consolidated Financial Statements.

Dividend and other income. The decrease in 2020 as compared to 2019 is due primarily to lower dividends received from our investment in Equitrans Midstream driven by the decrease in the number of shares of Equitrans Midstream's common stock that we own.

Loss on debt extinguishment. During 2020, we recognized a loss on debt extinguishment related to the repayment of all or a portion of our 4.875% senior notes, 2.50% senior notes, 3.00% senior notes, floating rate notes and Term Loan Facility (defined and discussed in Note 10 to the Consolidated Financial Statements). See Note 10 to the Consolidated Financial Statements.

Table of Contents

Interest expense. Interest expense increased for 2020 compared to 2019 due to increased interest incurred on new debt issued in 2020 as well as interest incurred on letters of credit issued in 2020. These increases were partly offset by lower interest incurred due to the repayment of all or a portion of our 8.125% senior notes, 4.875% senior notes, floating rate notes and 2.50% senior notes and decreased borrowings on our credit facility. See Note 10 to the Consolidated Financial Statements.

The adjusted interest rate under the Adjustable Rate Notes (defined and discussed in Note 10 to the Consolidated Financial Statements) cannot exceed 2% of the original interest rate first set forth on the face of the Adjustable Rate Notes; however, if our credit ratings improve, the interest rate under the Adjustable Rate Notes could be reduced to as low as the original interest rate set forth on the face of the Adjustable Rate Notes.

Income tax benefit. See Note 9 to the Consolidated Financial Statements.

Impairment of Oil and Gas Properties

See "Critical Accounting Policies and Estimates" and Note 1 to the Consolidated Financial Statements for a discussion of our accounting policies and significant assumptions related to 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."

Capital Resources and Liquidity

Although we cannot provide any assurance, we believe cash flows from operating activities and availability under our credit facility should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, debt service obligations, planned capital expenditures and commitments for at least the next twelve months and, based on current expectations, for the long-term.

Credit Facility

We primarily use borrowings under our credit facility to fund working capital needs, timing differences between capital expenditures and other cash uses and cash flows from operating activities, margin deposit requirements on our derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts. See Note 10 to the Consolidated Financial Statements for further discussion of our credit facility.

Known Contractual and Other Obligations; Planned Capital Expenditures

Purchase obligations. We have commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines, some of which extend up to 20 years or longer. We have entered into agreements to release some of our capacity under these long-term contracts. We also have commitments for processing capacity in order to extract heavier liquid hydrocarbons from the natural gas stream. Aggregate future payments for these items as of December 31, 2020 were $24.8 billion, composed of $1.3 billion in 2021, $1.7 billion in 2022, $1.8 billion in 2023, $1.9 billion in 2024, $1.8 billion in 2025 and $16.3 billion primarily in 2026 through 2042. We also have commitments to purchase equipment, materials, frac sand for use as a proppant in our hydraulic fracturing operations and minimum volume commitments associated with certain water agreements. As of December 31, 2020, future commitments under these contracts were $96.5 million in 2021 and $14.3 million in 2022.

Contractual Commitments. We have contractual commitments under our debt agreements including interest payments and principal repayments. See Note 10 to the Consolidated Financial Statements for further discussion including the timing of principal repayments.

Unrecognized Tax Benefits. As discussed in Note 9 to the Consolidated Financial Statements, we had a total reserve for unrecognized tax benefits at December 31, 2020 of $181.2 million, of which $90.3 million is offset against deferred tax assets for general business tax credit carryforwards and NOLs. We are currently unable to make reasonably reliable estimates of the period of cash settlement of these potential liabilities with taxing authorities.

Table of Contents

Planned Capital Expenditures. In 2021, we expect to spend approximately $1.1 to $1.2 billion in total capital expenditures, excluding amounts attributable to noncontrolling interests. Because we are the operator of a high percentage of our acreage, the amount and timing of these capital expenditures are largely discretionary. We could choose to defer a portion of these planned 2021 capital expenditures depending on a variety of factors, including prevailing and anticipated prices for natural gas, NGLs and oil; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; and drilling, completion and acquisition costs.

Operating Activities

Net cash provided by operating activities was $1,538 million for 2020 compared to $1,852 million for 2019. The decrease was due primarily to lower cash operating revenues and unfavorable timing of working capital payments, partly offset by increased cash settlements received on derivatives not designated as hedges, income tax refunds, plus interest, received of $440 million during 2020 and lower cash operating expenses.

Our cash flows from operating activities are affected by movements in the market price for commodities. We are unable to predict such movements outside of the current market view as reflected in forward strip pricing. Refer to Item 1A., "Risk Factors – Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position." for further information.

Investing Activities

Net cash used in investing activities was $1,556 million for 2020 compared to $1,601 million for 2019. The decrease was due to lower capital expenditures as a result of our change in strategic focus from production growth to capital efficiency as well as cash received from asset sales and the Equitrans Share Exchange. The decrease was partly offset by cash paid for acquisitions as described in Note 6**.**

The following table summarizes our capital expenditures.

(a)Capital expenditures attributable to noncontrolling interests were $4.9 million for the year ended December 31, 2020.

(b)Represents the net impact of non-cash capital expenditures, including capitalized share-based compensation costs, the effect of timing of receivables from working interest partners and accrued capital expenditures. The impact of accrued capital expenditures includes the reversal of the prior period accrual as well as the current period estimate.

Financing Activities

Net cash provided by financing activities was $32 million for 2020 compared to net cash used in financing activities of $249 million for 2019. For 2020, the primary source of financing cash flows was net proceeds from the issuance of debt and equity and the primary use of financing cash flows was net repayments of debt. For 2019, the primary uses of financing cash flows were net repayments of debt and credit facility borrowings, and the primary source of financing cash flows was net proceeds from borrowings on the Term Loan Facility. See Note 10 to the Consolidated Financial Statements for further discussion of our debt.

On March 26, 2020, we announced the suspension of our quarterly cash dividend on our common stock for purposes of accelerating cash flow to be used for our Deleveraging Plan.

Table of Contents

Depending on our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may from time to time seek to retire or repurchase our outstanding debt or equity securities through cash purchases in the open market or privately negotiated transactions. The amounts involved in any such transactions may be material. Additionally, we plan to dispose of our remaining retained shares of Equitrans Midstream's common stock and use the proceeds to reduce our debt.

See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on Form 10-K for the year ended December 31, 2019, which is incorporated herein by reference, for discussion and analysis of operating, investing and financing activities for the year ended December 31, 2018.

Security Ratings and Financing Triggers

The table below reflects the credit ratings and rating outlooks assigned to our debt instruments at February 12, 2021. Our credit ratings and rating outlooks are subject to revision or withdrawal at any time by the assigning rating agency, and each rating should be evaluated independent from any other rating. We cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in the rating agency's judgment, circumstances so warrant. See Note 3 to the Consolidated Financial Statements for further discussion of what is deemed investment grade.

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 the Adjustable Rate Notes, 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. Margin deposits on our OTC derivative instruments are also subject to factors other than credit rating, such as natural gas prices and credit thresholds set forth in the agreements between us and hedging counterparties. As of February 12, 2021, we had sufficient unused borrowing capacity, net of letters of credit, under our credit facility to satisfy any requests for margin deposit or other collateral that our counterparties are permitted to request of us pursuant to our OTC derivative instruments, midstream services contracts and other contracts. As of February 12, 2021, such assurances could be up to approximately $1.0 billion, inclusive of letters of credit, OTC derivative instrument margin deposits and other collateral posted of approximately $0.9 billion in the aggregate. See Notes 3 and 10 to the Consolidated Financial Statements for further information.

Our debt agreements and other financial obligations contain various provisions that, if not complied with, could result in default or event of default under our credit facility, mandatory partial or full repayment of amounts outstanding, reduced loan capacity or other similar actions. The most significant covenants and events of default under the debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. Our credit facility contains financial covenants that require us to have a total debt-to-total capitalization ratio no greater than 65%. The calculation of this ratio excludes the effects of accumulated other comprehensive income. As of December 31, 2020, we were in compliance with all debt provisions and covenants.

See Note 10 to the Consolidated Financial Statements for a discussion of the borrowings under our credit facility.

Commodity Risk Management

The substantial majority of our commodity risk management program is related to hedging sales of our produced natural gas. The overall objective of our hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices. The derivative commodity instruments that we use are primarily swap, collar and option agreements. The

Table of Contents

following table summarizes the approximate volumes and prices of our NYMEX hedge positions through 2024 as of February 12, 2021.

(a)Full year 2021.

(b)The difference between the fixed price and NYMEX price is included in average differential presented in our price reconciliation in the "Average Realized Price Reconciliation." The fixed price natural gas sales agreements can be physically or financially settled.

For 2021, 2022, 2023 and 2024, we have natural gas sales agreements for approximately 18 MMDth, 18 MMDth, 88 MMDth and 11 MMDth, respectively, that include average NYMEX ceiling prices of $3.17, $3.17, $2.84 and $3.21, respectively. We have also entered into derivative instruments to hedge basis. We may use other contractual agreements to implement our commodity hedging strategy from time to time.

During 2020, we purchased $47 million of net options with the primary purpose of reducing future NYMEX based payments that could be due in 2021, 2022 and 2023 to Equitrans Midstream related to the Henry Hub Cash Bonus (defined and discussed in Note 5 to the Consolidated Financial Statements) provided for by the Consolidated GGA.

See Item 7A., "Quantitative and Qualitative Disclosures About Market Risk" and Note 3 to the Consolidated Financial Statements for further discussion of our hedging program.

Off-Balance Sheet Arrangements

See Note 17 to the Consolidated Financial Statements for a discussion of our guarantees.

Commitments and Contingencies

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 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 matter currently pending against us will not materially affect our financial condition, results of operations or liquidity. See Note 16 to the Consolidated Financial Statements for a discussion of our commitments and contingencies. See Item 3., "Legal Proceedings."

Recently Issued Accounting Standards

Our recently issued accounting standards are described in Note 1 to the Consolidated Financial Statements.

Critical Accounting Policies and Estimates

Our significant accounting policies are described in Note 1 to the Consolidated Financial Statements. Management's discussion and analysis of the Consolidated Financial Statements and results of operations are based on our Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of the Consolidated Financial Statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and

Table of Contents

expenses and the related disclosure of contingent assets and liabilities. The following critical accounting policies, which were reviewed by the Audit Committee of our Board of Directors (the Audit Committee), relate to our more significant judgments and estimates used in the preparation of our Consolidated Financial Statements. Actual results could differ from our estimates.

Accounting for Gas, NGL and Oil Producing Activities. We use the successful efforts method of accounting for our oil and gas producing activities.

The carrying values of our proved oil and gas properties are reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. To determine whether impairment of our oil and gas properties has occurred, we compare the estimated expected undiscounted future cash flows to the carrying values of those properties. Estimated future cash flows are based on proved and, if determined reasonable by management, risk-adjusted probable reserves and assumptions generally consistent with the assumptions used by us for internal planning and budgeting purposes, including, among other things, the intended use of the asset, anticipated production from reserves, future market prices for natural gas, NGLs and oil adjusted for basis differentials, future operating costs and inflation. Proved oil and gas properties that have carrying amounts in excess of estimated future undiscounted cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount rates and other assumptions that marketplace participants would use in their fair value estimates.

Capitalized costs of unproved oil and gas properties are evaluated for recoverability on a prospective basis at least annually. Indicators of potential impairment include changes due to economic factors, potential shifts in business strategy and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches and drilling activity has not commenced. If we do not intend to drill on the property prior to expiration of the lease or do not have the intent and ability to extend, renew, trade or sell the lease prior to expiration, impairment expense is recorded.

We believe accounting for gas, NGL and oil producing activities is a "critical accounting estimate" because the evaluations of impairment of proved properties involve significant judgment about future events, such as future sales prices of natural gas and NGLs and future production costs, as well as the amount of natural gas and NGLs recorded and timing of recoveries. Significant changes in these estimates could result in the costs of our proved and unproved properties not being recoverable; therefore, we would be required to recognize impairment. See "Impairment of Oil and Gas Properties" and Note 1 to the Consolidated Financial Statements for additional information on our impairments of proved and unproved oil and gas properties.

Oil and Gas Reserves. Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10, are those quantities of oil and gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire unless evidence indicates that renewal is reasonably certain regardless of whether deterministic or probabilistic methods are used for the estimation.

Our estimates of proved reserves are reassessed annually using geological, reservoir and production performance data. Reserve estimates are prepared by our engineers and audited by independent engineers. Revisions may result from changes in, among other things, reservoir performance, development plans, prices, operating costs, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in certain proved reserves due to reaching economic limits sooner. A material change in the estimated volumes of reserves could have an impact on the depletion rate calculation and our Consolidated Financial Statements.

We estimate future net cash flows from natural gas, NGLs and crude oil reserves based on selling prices and costs using a twelve-month average price, which is calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period and, as such, is subject to change in subsequent periods. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Income tax expense is based on future statutory tax rates and tax deductions and credits available under current laws.

We believe oil and gas reserves is a "critical accounting estimate" because we must periodically reevaluate proved reserves along with estimates of future production rates, production costs and the timing of development expenditures. Future results of operations and the strength of our Consolidated Balance Sheet for any quarterly or annual period could be materially affected by changes in our assumptions. Significant changes in these estimates could result in a change to our estimated reserves, which could lead to a material change to our production depletion expense. See "Impairment of Oil and Gas Properties" for additional information on our oil and gas reserves.

Table of Contents

Income Taxes. We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in our Consolidated Financial Statements or tax returns.

We have recorded deferred tax assets resulting from federal and state NOL carryforwards, an AMT credit carryforward, other federal tax credit carryforwards, unrealized capacity contract losses, incentive compensation and investments in securities. We have established a valuation allowance against a portion of the deferred tax assets related primarily to federal and state NOL carryforwards and our investment in Equitrans Midstream because we believe it is more likely than not that those deferred tax assets will not be fully realized. We established a valuation allowance against the state and part of the federal deferred tax asset related to our investment in Equitrans Midstream because the fair value loss is not expected to be fully realized for tax purposes due to capital loss limitations. No other significant valuation allowances have been established as we believe that future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize the deferred tax assets. Changes to our valuation allowance would impact our income tax expense and net income in the period in which such a determination is made.

We estimate the amount of financial statement benefit recorded for uncertain tax positions. See Note 9 to our Consolidated Financial Statements.

We believe income taxes are "critical accounting estimates" because we must assess the likelihood that our deferred tax assets will be recovered from future taxable income and exercise judgment on the amount of financial statement benefit recorded for uncertain tax positions. When evaluating whether or not a valuation allowance should be established, we exercise judgment on whether it is more likely than not (a likelihood of more than 50%) that a portion or all of the deferred tax assets will not be realized. To determine whether a valuation allowance is needed, we consider all available evidence, both positive and negative, including carrybacks, tax planning strategies, reversals of deferred tax assets and liabilities and forecasted future taxable income. To determine the amount of financial statement benefit recorded for uncertain tax positions, we consider the amounts and probabilities of outcomes that could be realized upon ultimate settlement of an uncertain tax position using facts, circumstances and information available at the reporting date. To the extent that a valuation allowance or uncertain tax position is established or increased or decreased during a period, we record an expense or benefit in income tax expense in our Statements of Consolidated Operations. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. A change to future taxable income or tax planning strategies could impact our ability to utilize deferred tax assets, which would increase or decrease our income tax expense and taxes paid.

Derivative Instruments. We enter into derivative commodity instrument contracts primarily to reduce exposure to commodity price risk associated with future sales of natural gas production.

We estimate the fair value of our financial instruments using quoted market prices when available. If quoted market prices are not available, the fair value is based on models that use market-based parameters, including forward curves, discount rates, volatilities and nonperformance risk, as inputs. Nonperformance risk considers the effect of our credit standing on the fair value of liabilities and the effect of the counterparty's credit standing on the fair value of assets. We estimate nonperformance risk by analyzing publicly available market information, including a comparison of the yield on debt instruments with credit ratings similar to our credit rating or the counterparty's credit rating and the yield on a risk-free instrument. The values reported in the Consolidated Financial Statements change as these estimates are revised to reflect actual results or as market conditions or other factors, many of which are beyond our control, change.

We believe derivative instruments are "critical accounting estimates" because our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments due to the volatility of both NYMEX natural gas prices and basis. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. Refer to Item 7A., "Quantitative and Qualitative Disclosures about Market Risk" for discussion of a hypothetical increase or decrease of 10% in the market price of natural gas.

Contingencies and Asset Retirement Obligations. We are involved in various legal and regulatory proceedings that arise in the ordinary course of business. We record a liability for contingencies based on our assessment that a loss is probable and the amount of the loss can be reasonably estimated. We consider many factors in making these assessments, including historical experience and matter specifics. Estimates are developed in consultation with legal counsel and are based on an analysis of potential results.

Table of Contents

We accrue a liability for asset retirement obligations based on an estimate of the amount and timing of settlement. For oil and gas wells, the fair value of our plugging and abandonment obligations is recorded at the time the obligation is incurred, which is typically at the time the well is spud.

We believe contingencies and asset retirement obligations are "critical accounting estimates" because we must assess the probability of loss related to contingencies and the expected amount and timing of asset retirement obligation settlement. In addition, we must determine the estimated present value of future liabilities. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. If we incur losses related to contingencies that are higher than we expect, we could incur additional costs to settle such obligations. If the expected amount and timing of our asset retirement obligations change, we will be required to adjust the carrying value of our liabilities in future periods.

Contract Asset. In the first quarter of 2020, we entered into two share purchase agreements with Equitrans Midstream to sell to Equitrans Midstream 50% of our ownership of Equitrans Midstream's common stock in exchange for a combination of cash and rate relief under certain of our gathering agreements with EQM, an affiliate of Equitrans Midstream. The rate relief was effected through the execution the Consolidated GGA (defined and discussed in Note 5 to the Consolidated Financial Statements). We recorded a contract asset representing the estimated fair value of the rate relief provided by the Consolidated GGA. Key assumptions used in the fair value calculation included an estimated production volume forecast, a market-based discount rate and a probability-weighted estimate of the in-service date of the Mountain Valley Pipeline. Beginning with the Mountain Valley Pipeline in-service date, we will recognize amortization of the contract asset over a period of approximately four years in a manner consistent with the expected timing of our realization of the economic benefits of the rate relief provided by the Consolidated GGA.

We believe the Consolidated GGA contract asset is a "critical accounting estimate" because the assumptions used in the valuation of the contract asset involved significant judgment. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. A change in the estimated production volume forecast, the market-based discount rate or the probability-weighted estimate of the in-service date of the Mountain Valley Pipeline could have resulted in a change in the valuation of the contract asset.

Convertible Notes. In the second quarter of 2020, we issued the Convertible Notes (defined and discussed in Note 10 to the Consolidated Financial Statements).

At issuance, we separated the Convertible Notes into liability and equity components. The carrying amount of the liability component was calculated by measuring the fair value of similar debt instruments that do not have associated convertible features. The carrying amount of the equity component, representing the conversion option, was determined by deducting the fair value of the liability component from the principal value of the Convertible Notes. The equity component is not remeasured as long as it continues to meet the condition for equity classification. The excess of the principal amount of the liability component over its carrying amount (the debt discount) will be amortized to interest expense over the term of the Convertible Notes using the effective interest rate method. Issuance costs were allocated to the liability and equity components of the Convertible Notes based on their relative fair values.

In connection with the Convertible Notes offering, we entered into the Capped Call Transactions (defined and discussed in Note 10 to the Consolidated Financial Statements). The Capped Call Transactions are separate from the Convertible Notes. The Capped Call Transactions were recorded in shareholders' equity and were not accounted for as derivatives. The cost to purchase the Capped Call Transactions was recorded as a reduction to equity and will not be remeasured.

Upon conversion of the Convertible Notes, we intend to use a combined settlement approach to satisfy our settlement obligation by paying or delivering to holders of the Convertible Notes cash equal to the principal amount of the obligation and EQT common stock for amounts that exceed the principal amount of the obligation. As such, we used the treasury stock method for the diluted earnings per share (EPS) calculation, and there is no adjustment to the diluted EPS numerator for the cash-settled portion of the instrument.

We believe the accounting complexity of the Convertible Notes is a "critical accounting estimate" because we used judgment to determine the balance sheet classification, to determine the treatment of the Capped Call Transactions and to determine the existence of any derivatives that may require separate accounting under applicable accounting guidance. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions.

Business Combinations. Accounting for a business combination requires a company to record the identifiable assets and liabilities acquired at fair value.

Table of Contents

In the fourth quarter of 2020, we completed the Chevron Acquisition. The most significant assumptions used in accounting for the Chevron Acquisition include those used to estimate the fair value of the oil and gas properties acquired, the acquired investment in midstream gathering assets and acquired contract liabilities. We calculated the fair value of the acquired proved oil and gas properties, including in-process wells, using a risk-adjusted after-tax discounted cash flow analysis that was based on the following key assumptions: future commodity prices, projections of estimated quantities of reserves, estimated future rates of production, projected reserve recovery factors, timing and amount of future development and operating costs and a weighted average cost of capital. We calculated the fair value of the acquired unproved properties using the guideline transaction method that was based on the following key assumptions: future development plans from a market participant perspective and value per undeveloped acre. We calculated the fair value of our investment in the midstream gathering assets primarily using a discounted cash flow analysis that was based on the following key assumptions: projected revenues, expenses and capital expenditures. We calculated the fair value of acquired contract liabilities using estimated future volumes and annual contract commitments calculated on a discounted basis that was based on the following key assumptions: estimated future volumes and market participant cost of debt.

We believe business combinations are "critical accounting estimates" because the valuation of acquired assets and liabilities involves significant judgment about future events. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions.

Commodity Price Risk and Derivative Instruments. Our primary market risk exposure is the volatility of future prices for natural gas and NGLs. Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas and NGLs at our ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations. Prolonged low, or significant, extended declines in, natural gas and NGLs prices could adversely affect, among other things, our development plans, which would decrease the pace of development and the level of our proved reserves. Increases in natural gas and NGLs 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. In addition, to the extent we have hedged our production at prices below the current market price, we will not benefit fully from an increase in the price of natural gas.

The overall objective of our hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices. Our use of derivatives is further described in Note 3 to the Consolidated Financial Statements and "Commodity Risk Management" under "Capital Resources and Liquidity" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations." Our OTC derivative commodity instruments are placed primarily with financial institutions and the creditworthiness of those institutions is regularly monitored. We primarily enter into derivative instruments to hedge forecasted sales of production. We also enter into derivative instruments to hedge basis and exposure to fluctuations in interest rates. Our use of derivative instruments is implemented under a set of policies approved by our Hedge and Financial Risk Committee and reviewed by our Board of Directors.

For derivative commodity instruments used to hedge our forecasted sales of production, which are at, for the most part, NYMEX natural gas prices, we set policy limits relative to the expected production and sales levels that are exposed to price risk. We have an insignificant amount of financial natural gas derivative commodity instruments for trading purposes.

The derivative commodity instruments we use are primarily swap, collar and option agreements. These agreements may require payments to, or receipt of payments from, counterparties based on the differential between two prices for the commodity. We use these agreements to hedge our NYMEX and basis exposure. We may also use other contractual agreements when executing our commodity hedging strategy. We monitor price and production levels on a continuous basis and make adjustments to quantities hedged as warranted.

A hypothetical decrease of 10% in the market price of natural gas on December 31, 2020 and 2019 would increase the fair value of our natural gas derivative commodity instruments by approximately $501 million and $389 million, respectively. A hypothetical increase of 10% in the market price of natural gas on December 31, 2020 and 2019 would decrease the fair value of our natural gas derivative commodity instruments by approximately $495 million and $395 million, respectively. For purposes of this analysis, we applied the 10% change in the market price of natural gas on December 31, 2020 and 2019 to our natural gas derivative commodity instruments as of December 31, 2020 and 2019 to calculate the hypothetical change in fair value. The change in fair value was determined using a method similar to our normal process for determining derivative commodity instrument fair value described in Note 4 to the Consolidated Financial Statements.

Table of Contents

The above analysis of our derivative commodity instruments does not include the offsetting impact that the same hypothetical price movement may have on our physical sales of natural gas. The portfolio of derivative commodity instruments held to hedge our forecasted produced gas approximates a portion of our expected physical sales of natural gas; therefore, an adverse impact to the fair value of the portfolio of derivative commodity instruments held to hedge our forecasted production associated with the hypothetical changes in commodity prices referenced above should be offset by a favorable impact on our physical sales of natural gas, assuming that the derivative commodity instruments are not closed in advance of their expected term and the derivative commodity instruments continue to function effectively as hedges of the underlying risk.

If the underlying physical transactions or positions are liquidated prior to the maturity of the derivative commodity instruments, a loss on the financial instruments may occur or the derivative commodity instruments might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first.

Interest Rate Risk. Changes in market interest rates affect the amount of interest we earn on cash, cash equivalents and short-term investments and the interest rates we pay on borrowings on our credit facility and, prior to its full redemption on June 30, 2020, our Term Loan Facility. None of the interest we pay on our senior notes fluctuates based on changes to market interest rates. A 1% increase in interest rates on our borrowings on our credit facility and term loan facility during the year ended December 31, 2020 would have increased 2020 annual interest expense by approximately $5 million. A 1% increase in interest rates on our borrowings under our credit facility, term loan facility and floating rate notes during the year ended December 31, 2019 would have increased 2019 annual interest expense by approximately $14 million.

Interest rates on the Adjustable Rate Notes fluctuate based on changes to the credit ratings assigned to our senior notes by Moody's, S&P and Fitch. For a discussion of credit rating downgrade risk, see Item 1A., "Risk Factors – Our exploration and production operations have substantial capital requirements, and we may not be able to obtain needed capital or financing on satisfactory terms." Changes in interest rates affect the fair value of our fixed rate debt. See Note 10 to the Consolidated Financial Statements for further discussion of our debt and Note 4 to the Consolidated Financial Statements for a discussion of fair value measurements, including the fair value of our debt.

Other Market Risks. We are exposed to credit loss in the event of nonperformance by counterparties to our derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value, which may change as market prices change. Our OTC derivative instruments are primarily with financial institutions and, thus, are subject to events that would impact those companies individually as well as the financial industry as a whole. We use various processes and analyses to monitor and evaluate our credit risk exposures, including monitoring current market conditions and counterparty credit fundamentals. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals. To manage the level of credit risk, we enter into transactions primarily with financial counterparties that are of investment grade, enter into netting agreements whenever possible and may obtain collateral or other security.

Approximately 47%, or $456 million, of our OTC derivative contracts outstanding at December 31, 2020 had a positive fair value. Approximately 75%, or $718 million, of our OTC derivative contracts outstanding at December 31, 2019 had a positive fair value.

As of December 31, 2020, we were not in default under any derivative contracts and had no knowledge of default by any counterparty to our derivative contracts. During the year ended December 31, 2020, we made no adjustments to the fair value of our derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in our established fair value procedure. We monitor market conditions that may impact the fair value of our derivative contracts.

We are exposed to the risk of nonperformance by credit customers on physical sales of natural gas, NGLs and oil. Revenues and related accounts receivable from our operations are generated primarily from the sale of produced natural gas, NGLs and oil to marketers, utilities and industrial customers located in the Appalachian Basin and in markets that are accessible through our transportation portfolio, which includes markets in the Gulf Coast, Midwest and Northeast United States and Canada. We also contract with certain processors to market a portion of NGLs on our behalf.

No one lender of the large group of financial institutions in the syndicate for our credit facility holds more than 10% of the financial commitments under such facility. The large syndicate group and relatively low percentage of participation by each lender are expected to limit our exposure to disruption or consolidation in the banking industry.

Table of Contents

Table of Contents

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of EQT Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of EQT Corporation and subsidiaries (the Company) as of December 31, 2020 and 2019, the related statements of consolidated operations, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2020, and the related notes and the financial statement schedule listed in the Index at Item 15 (a) (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2020 and 2019, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 17, 2021 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Table of Contents

Depreciation, depletion and amortization ('DD&A') of proved oil and natural gas properties

Showing the first 8K of 249K characters. Open the full section

Not applicable.

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of management, including the Company's Principal Executive Officer and Principal Financial Officer, an evaluation of the Company's disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)) was conducted as of the end of the period covered by this report. Based on that evaluation, the Principal Executive Officer and Principal Financial Officer concluded that the Company's disclosure controls and procedures were effective as of the end of the period covered by this report.

Management's Report on Internal Control over Financial Reporting

The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act). The Company's internal control system is designed to provide reasonable assurance to the Company's management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation.

The Company's management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2020. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013). Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2020. Management’s assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the assets acquired in the Chevron Acquisition on November 30, 2020. Total assets acquired and total operating revenues represented approximately 5% of the Company’s consolidated total assets at December 31, 2020 and less than 1% of the Company’s consolidated total operating revenues for the year ended December 31, 2020.

Ernst & Young LLP (Ernst & Young), the independent registered public accounting firm that audited the Company's Consolidated Financial Statements, has issued an attestation report on the Company's internal control over financial

Table of Contents

reporting. Ernst & Young's attestation report on the Company's internal control over financial reporting appears in Part II, Item 8., of this Annual Report on Form 10-K and is incorporated herein by reference.

Changes in Internal Control over Financial Reporting

There were no changes in internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of 2020 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

The Company is in the process of integrating the assets acquired in the Chevron Acquisition into the Company's internal controls over financial reporting.

Not Applicable.

PART III

The following information is incorporated herein by reference from the Company's definitive proxy statement relating to the 2021 annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the close of the Company's fiscal year ended December 31, 2020:

• Information required by Item 401 of Regulation S-K with respect to directors is incorporated herein by reference from the sections captioned "Director Nominees" and "Director Independence" under "Corporate Governance and Board Matters" in the Company's definitive proxy statement;

• Information required by Item 407(d)(4) of Regulation S-K with respect to disclosure of the existence of the Company's separately-designated standing Audit Committee and the identification of the members of the Audit Committee is incorporated herein by reference from the section captioned "Corporate Governance and Board Matters – Board Committees – Audit Committee" in the Company's definitive proxy statement; and

• Information required by Item 407(d)(5) of Regulation S-K with respect to disclosure of the Company's audit committee financial expert is incorporated herein by reference from the section captioned "Corporate Governance and Board Matters – Board Committees – Audit Committee" in the Company's definitive proxy statement.

Information required by Item 401 of Regulation S-K with respect to executive officers is included after Item 4 at the end of Part I of this Annual Report on Form 10-K under the caption "Information about our Executive Officers (as of February 17, 2021)," and is incorporated herein by reference.

The Company has adopted a code of business conduct and ethics applicable to all directors and employees, including the principal executive officer, principal financial officer and principal accounting officer. The code of business conduct and ethics is posted on the Company's website http://www.eqt.com (accessible by clicking on the "About" link on the main page, followed by the "Governance" heading, then the "Charters and Governance Documents" link), and a printed copy will be delivered free of charge on request by writing to the corporate secretary at EQT Corporation, c/o Corporate Secretary, 625 Liberty Avenue, Suite 1700, Pittsburgh, Pennsylvania 15222. The Company intends to satisfy the disclosure requirement regarding certain amendments to, or waivers from, provisions of its code of business conduct and ethics by posting such information on the Company's website.

The following information is incorporated herein by reference from the Company's definitive proxy statement relating to the 2021 annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the close of the Company's fiscal year ended December 31, 2020:

• Information required by Item 402 of Regulation S-K with respect to named executive officer and director compensation is incorporated herein by reference from the sections captioned "Compensation Discussion and

Table of Contents

Analysis," "Compensation Tables," "Compensation Policies and Practices and Risk Management," "Pay Ratio Disclosure" and "Corporate Governance and Board Matters – Directors' Compensation" in the Company's definitive proxy statement; and

• Information required by paragraph (e)(5) of Item 407 of Regulation S-K with respect to certain matters related to the Management Development and Compensation Committee of the Company's Board of Directors is incorporated herein by reference from the section captioned "Compensation Committee Report" in the Company's definitive proxy statement.

Information required by Item 403 of Regulation S-K with respect to stock ownership of significant shareholders, directors and executive officers is incorporated herein by reference to the sections captioned "Equity Ownership – Security Ownership of Certain Beneficial Owners" and "Equity Ownership – Security Ownership of Management" in the Company's definitive proxy statement relating to the 2021 annual meeting of shareholders, which will be filed with the SEC within 120 days after the close of the Company's fiscal year ended December 31, 2020.

Equity Compensation Plan Information

The following table and related footnotes provide information as of December 31, 2020 with respect to shares of the Company's common stock that may be issued under the Company's existing equity compensation plans, including the 2020 Long-Term Incentive Plan (2020 LTIP), 2019 Long-Term Incentive Plan (2019 LTIP), 2014 Long-Term Incentive Plan (2014 LTIP), the 2009 Long-Term Incentive Plan (2009 LTIP), the 2008 Employee Stock Purchase Plan (2008 ESPP), and the 2005 Directors' Deferred Compensation Plan (2005 DDCP):

(1)Consists of the 2020 LTIP, 2019 LTIP, 2014 LTIP, the 2009 LTIP, and the 2008 ESPP. Effective as of May 1, 2020, with the adoption of the 2020 LTIP, the Company ceased making new grants under the 2019 LTIP. Effective as of July 10, 2019 in connection with the adoption of the 2019 LTIP, the Company ceased making new grants under the 2014 LTIP. Effective as of April 30, 2014, in connection with the adoption of the 2014 LTIP, the Company ceased making new grants under the 2009 LTIP. The 2019 LTIP, 2014 LTIP, and the 2009 LTIP remain effective solely for the purpose of issuing shares upon the exercise or payout of awards outstanding under such plans on May 1, 2020 (for the 2019 LTIP), July 10, 2019 (for the 2014 LTIP) and April 30, 2014 (for the 2009 LTIP).

(2)Consists of (i) 2,053,512 shares subject to outstanding performance awards under the 2019 LTIP, inclusive of dividend reinvestments thereon (counted at a 3X multiple assuming maximum performance is achieved under the awards (representing 1,369,008 target awards and dividend reinvestments thereon)), (ii) 2,240,000 shares subject to outstanding stock options and stock appreciation rights under the 2019 LTIP, (iii) 33,886 shares subject to outstanding directors' deferred stock units under the 2019 LTIP, inclusive of dividend reinvestments thereon, (iv) 3,311,745 shares subject to outstanding performance awards under the 2014 LTIP, inclusive of dividend reinvestments thereon (counted at a 3X multiple assuming maximum performance is achieved under the awards (representing 2,304,439 target and confirmed awards and dividend reinvestments thereon)), (v) 1,598,415 shares subject to outstanding stock options under the 2014 LTIP, (vi) 117,680 shares subject to outstanding directors' deferred stock units under the 2014 LTIP, inclusive of dividend reinvestments thereon, (vii) 956,314 shares subject to outstanding stock options under the 2009 LTIP; and (viii) 22,261 shares subject to outstanding directors' deferred stock units under the 2009 LTIP, inclusive of dividend reinvestments thereon.

(3)The weighted-average exercise price is calculated solely based on outstanding stock options and stock appreciation rights under the 2019 LTIP, 2014 LTIP and the 2009 LTIP and excludes deferred stock units under the 2019 LTIP, 2014 LTIP, and the 2009 LTIP

Table of Contents

and performance awards under the 2019 LTIP, 2014 LTIP and 2009 LTIP. The weighted average remaining term of the outstanding stock options and stock appreciation rights was 5.3 years and 9.0 years, respectively, as of December 31, 2020.

(4)Consists of (i) 12,044,453 shares available for future issuance under the 2020 LTIP and (ii) 292,716 shares available for future issuance under the 2008 ESPP. As of December 31, 2020, no shares were subject to purchase under the 2008 ESPP.

(5)Consists of the 2005 DDCP which is described below.

(6)Consists entirely of shares invested in the EQT common stock fund, payable in shares of common stock, allocated to non-employee directors' accounts under the 2005 DDCP as of December 31, 2020.

(7)Consists entirely of shares available for future issuance under the 2005 DDCP as of December 31, 2020.

2005 Directors' Deferred Compensation Plan

The 2005 DDCP was adopted by the Compensation Committee, effective January 1, 2005. Neither the original adoption of the plan nor its amendments required approval by the Company's shareholders. The plan allows non-employee directors to defer all or a portion of their directors' fees and retainers. Amounts deferred are payable on or following retirement from the Company's Board of Directors unless an early payment is authorized after the director suffers an unforeseeable financial emergency. In addition to deferred directors' fees and retainers, the deferred stock units granted to directors on or after January 1, 2005 under the 2009 LTIP and the 2014 LTIP are administered under this plan.

Information required by Items 404 and 407(a) of Regulation S-K with respect to related person transactions and director independence is incorporated herein by reference to the sections captioned "Related Person Transactions," "Director Nominees" and "Director Independence" under "Corporate Governance and Board Matters" in the Company's definitive proxy statement relating to the 2021 annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the close of the Company's fiscal year ended December 31, 2020.

Information required by Item 9(e) of Schedule 14A is incorporated herein by reference to the section captioned "Audit Matters" in the Company's definitive proxy statement relating to the 2021 annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the close of the Company's fiscal year ended December 31, 2020.

Table of Contents

PART IV

EQT CORPORATION AND SUBSIDIARIES

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

FOR THE THREE YEARS ENDED DECEMBER 31, 2020

All other schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules.

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk ()*

We agree to furnish to the SEC, upon request, copies of instruments with respect to long-term debt that have not previously been filed.

None.

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.