UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE FISCAL YEAR ENDED DECEMBER 31, 2021

or

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE TRANSITION PERIOD FROM ___________ TO __________

COMMISSION FILE NUMBER 001-03551

EQT CORPORATION

(Exact name of registrant as specified in its charter)

Pennsylvania	25-0464690
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)
625 Liberty Avenue, Suite 1700
Pittsburgh, Pennsylvania	15222
(Address of principal executive offices)	(Zip Code)

(412) 553-5700

(Registrant's telephone number, including area code)

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

Title of each class	Trading symbol(s)	Name of each exchange on which registered
Common Stock, no par value	EQT	New York Stock Exchange

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.

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

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, 2021: $6.2 billion

As of February 4, 2022, 376,023,250 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 2022 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, 2021 and is incorporated by reference in Part III to the extent described therein.

TABLE OF CONTENTS

		Page
Glossary of Commonly Used Terms, Abbreviations and Measurements		3
Summary of Risk Factors		6
Cautionary Statements		7
PART I
Item 1.	Business	8
Item 1A.	Risk Factors	24
Item 1B.	Unresolved Staff Comments	42
Item 2.	Properties	42
Item 3.	Legal Proceedings	42
Item 4.	Mine Safety Disclosures	43
	Executive Officers of the Registrant	44
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	45
Item 6.	[Reserved]	46
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	47
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	59
Item 8.	Financial Statements and Supplementary Data	62
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	114
Item 9A.	Controls and Procedures	114
Item 9B.	Other Information	115
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	115
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	115
Item 11.	Executive Compensation	115
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	116
Item 13.	Certain Relationships and Related Transactions, and Director Independence	117
Item 14.	Principal Accountant Fees and Services	117
PART IV
Item 15.	Exhibits and Financial Statement Schedules	117
Item 16.	Form 10-K Summary	123
Signatures		124

2

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.

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).

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.

3

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 reasonably 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

CFTC – Commodity Futures Trading Commission

EPA – U.S. Environmental Protection Agency

ESG – Environmental, Social and Governance initiatives

FERC – Federal Energy Regulatory Commission

GAAP – U.S. Generally Accepted Accounting Principles

IRS – Internal Revenue Service

NYMEX – New York Mercantile Exchange

OTC – over the counter

SEC – U.S. Securities and Exchange Commission

4

Measurements

Bbl  =  barrel

Bcf  =  billion cubic feet

Bcfe  =  billion cubic feet of natural gas equivalents, with one barrel of NGLs and crude oil being equivalent to 6,000 cubic feet of natural gas

Btu  =  one British thermal unit

Dth  =  dekatherm or million British thermal units

Mbbl  =  thousand barrels

Mcf  =  thousand cubic feet

Mcfe  =  thousand cubic feet of natural gas equivalents, with one barrel of NGLs and crude oil being equivalent to 6,000 cubic feet of natural gas

MMbbl = million barrels

MMBtu  =  million British thermal units

MMcf  =  million cubic feet

MMcfe  =  million cubic feet of natural gas equivalents, with one barrel of NGLs and crude oil being equivalent to 6,000 cubic feet of natural gas

MMDth = million dekatherm

Tcfe  =  trillion cubic feet of natural gas equivalents, with one barrel of NGLs and crude oil being equivalent to 6,000 cubic feet of natural gas

5

SUMMARY OF RISK FACTORS

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

•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 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, NGLs and oil 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 operate in the Appalachian Basin, and a substantial majority of our midstream and water services are provided by one provider, Equitrans Midstream Corporation (Equitrans Midstream), 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.

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

6

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 (the Exchange Act), and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and are usually identified by the use of words such as "anticipate," "estimate," "could," "would," "will," "may," "forecast," "approximate," "expect," "project," "intend," "plan," "believe" and other words of similar meaning, or the negative thereof, in connection with any discussion of future operating or financial matters. 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 these plans and programs; total resource potential and drilling inventory duration; projected production and sales volume and growth rates; natural gas prices; changes in basis and the impact of commodity prices on our business; potential future impairments of our assets; projected well costs and capital expenditures; infrastructure programs; the cost, capacity and timing of obtaining regulatory approvals; our ability to successfully implement and execute our operational, organizational, technological and ESG initiatives, and achieve the anticipated results of such initiatives; projected gathering and compression rates; monetization transactions, including asset sales, joint ventures or other transactions involving our assets, and our planned use of the proceeds from such monetization transactions; potential acquisition transactions 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'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; the projected amount and timing of dividends; projected cash flows and free cash flow, and the timing thereof; liquidity and financing requirements, including funding sources and availability; our ability to maintain or improve our credit ratings, leverage levels and financial profile; our hedging strategy and projected margin posting obligations; the effects of litigation, government regulation and tax position; and the expected impact of changes to tax laws.

The forward-looking statements included in this Annual Report on Form 10-K involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. We have based these forward-looking statements on current expectations and assumptions about future events, taking into account all information currently known by us. While we consider these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, many of which are difficult to predict and beyond our control. 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.

7

PART I

Item 1.        Business

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 volume, we are the largest producer of natural gas in the United States. As of December 31, 2021, we had 25.0 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 2.0 million gross acres, including approximately 1.7 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 measure sustainability through our best-in-class team and culture, ESG-focused operations, substantial inventory of core drilling locations and strong balance sheet. We believe that the scale and contiguity of our acreage position differentiates us from our Appalachian Basin peers and that our evolution into a modern, digitally-enabled exploration and production business enhances our strategic advantage.

Our operational strategy focuses on the successful execution of combo-development projects. Combo-development refers to the development of several multi-well pads in tandem. Combo-development generates value across all levels of the reserves development process by maximizing operational and capital efficiencies. In the drilling stage, rigs spend more time drilling and less time transitioning to new sites. Advanced planning, a prerequisite to pursuing combo-development, facilitates the delivery of bulk hydraulic fracturing sand and piped fresh 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.

We believe our business model is sustainable and we expect to generate significant free cash flow over the next six years. Our capital allocation plan is focused on reducing our debt and leverage, while also returning capital to shareholders through a combination of dividends and a share repurchase program. We are focused on achieving and maintaining investment grade credit metrics as well as regaining our investment grade credit rating in the near term, which will allow us to capture a lower cost of capital and enhance shareholder returns.

8

2021 Highlights

•Achieved 2021 sales volume of 1,858 Bcfe, average daily sales volume of 5.1 Bcfe per day; received an average realized price of $2.50 per Mcfe.

•Increased 2021 total proved reserves by 5.2 Tcfe, or 26%, compared to 2020.

•Acquired strategic assets located in the Appalachian Basin from Alta Resources Development, LLC for total consideration of $2,925 million (the Alta Acquisition).

•Realized a meaningful reduction of gathering and transmission expense on a per Mcfe basis of $0.05 and $0.06, respectively, during 2021 compared to 2020.

•Achieved credit ratings upgrades from S&P, Moody's and Fitch.

•Extended the term of our credit facility and reduced outstanding letters of credit under our credit facility by $351 million.

•Obtained Equitable Origin and MiQ Certifications for a majority of our natural gas.

Outlook

In 2022, we expect to spend approximately $1.30 to $1.45 billion in total capital expenditures, excluding amounts attributable to noncontrolling interest. We expect to allocate the planned capital expenditures as follows: approximately $1.0 to $1.1 billion to fund reserve development, approximately $110 to $130 million to fund land and lease acquisitions, approximately $120 to $160 million to fund other production infrastructure and approximately $55 to $75 million applied towards capitalized overhead. Our 2022 capital expenditure program is expected to deliver sales volume of 1,950 to 2,050 Bcfe.

In December 2021, we reaffirmed our commitment to attaining investment grade credit metrics and outlined a leverage and debt reduction strategy with the goal of reducing total debt by at least $1.5 billion by the end of 2023. In addition, we announced our plan to return capital to shareholders, which included the commencement of a share repurchase program, under which we are authorized to repurchase $1.0 billion of our outstanding common stock, and the reinstatement of a quarterly cash dividend at an annual rate of $0.50 per share of our common stock starting in the first quarter of 2022. Our capital allocation plan is focused on maintaining production volumes. We have aligned our hedge strategy in a manner that we believe will mitigate the risk of volatility of future natural gas and NGLs prices, which will enable us to execute on our capital expenditure, debt reduction and shareholder return strategy.

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, NGLs 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.

9

Reserves

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

	December 31, 2021
	Natural Gas	NGLs and Crude Oil	Total
	(Bcf)	(MMbbl)	(Bcfe)
Proved developed reserves	16,152	178	17,219
Proved undeveloped reserves	7,372	62	7,743
Total proved reserves	23,524	240	24,962

	December 31, 2021
	Marcellus	Upper Devonian	Ohio Utica	Other	Total
	(Bcfe)
Proved developed reserves	15,528	806	787	98	17,219
Proved undeveloped reserves	7,733	—	10	—	7,743
Total proved reserves	23,261	806	797	98	24,962

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

	December 31, 2021
	Pennsylvania	West Virginia	Ohio	Total
	(Bcfe)
Proved developed producing reserves	12,642	3,292	781	16,715
Proved developed non-producing reserves	375	123	6	504
Proved undeveloped reserves	5,085	2,648	10	7,743
Total proved reserves	18,102	6,063	797	24,962
Gross proved undeveloped drilling locations	279	146	5	430
Net proved undeveloped drilling locations	195	118	1	314

Our 2021 total proved reserves increased by 5.2 Tcfe, or 26%, compared to 2020 due to acquisitions of 4,187 Bcfe from the Alta Acquisition and Reliance Asset Acquisition (defined in Note 6 to the Consolidated Financial Statements) and extensions, discoveries and other additions of 3,104 Bcfe, partly offset by production of 1,858 Bcfe and revisions to previous estimates of 274 Bcfe.

10

Our 2021 proved undeveloped reserves increased by 1,582 Bcfe, or 26%, compared to 2020. The following table provides a rollforward of our proved undeveloped reserves.

	Proved Undeveloped Reserves
	(Bcfe)
Balance at January 1, 2021	6,161
Conversions into proved developed reserves	(1,634)
Acquisition of in-place reserves	1,217
Revision of previous estimates (a)	(881)
Extensions, discoveries and other additions (b)	2,880
Balance at December 31, 2021	7,743

(a)Composed of (i) negative revisions of 819 Bcfe from proved undeveloped locations that are no longer expected to be developed within five years of initial booking as proved reserves as a result of changes to our development plan to support the continued implementation of our combo-development strategy; and (ii) negative revisions of 62 Bcfe due primarily to changes in working interests and net revenue interests.

(b)Composed of (i) 2,828 Bcfe from proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2021 reserve development that expanded the number of our proven locations, implementation of, and alignment with, our combo-development strategy and additions to our five-year drilling plan; and (ii) 52 Bcfe from the extension of lateral lengths of proved undeveloped reserves.

As of December 31, 2021, we had zero wells with proved undeveloped reserves that had remained undeveloped for more than five years from their time of booking.

See Note 18 to the Consolidated Financial Statements for further discussion of the preparation of, and year-over-year changes in, our reserves estimate and calculation of the standardized measure of estimated future net cash flows from natural gas and crude oil reserves.

As of December 31, 2021, the standardized measure of our estimated future net cash flows from natural gas and crude oil reserves, which is calculated using average first-day-of-the-month closing prices for the prior twelve months (referred to as SEC pricing), was $17,281 million, as described in Note 18 to the Consolidated Financial Statements. If the prices used in the calculation of the standardized measure instead reflected five-year strip pricing as of December 31, 2021 and held constant thereafter using (i) the NYMEX five-year strip adjusted for regional differentials using Texas Eastern Transmission Corp. M-2, Transcontinental Gas Pipe Line, Leidy Line, and Tennessee Gas Pipeline Co., Zone 4-300 Leg for gas and (ii) the NYMEX WTI five-year strip for oil, adjusted for regional differentials consistent with those used in the standardized measure, and holding all other assumptions constant, our total proved reserves would be 24,913 Bcfe, the standardized measure of our discounted net future cash flows after taxes of our proved reserves would be $16,059 million and the discounted future net cash flows before taxes would be $19,672 million. The average realized product prices weighted by production over the remaining lives of the properties would be $46.84 per barrel of oil, $27.22 per barrel of NGLs and $2.448 per Mcf of gas (compared to $51.57 per barrel of oil, $29.95 per barrel of NGLs and $2.694 per Mcf of gas using SEC pricing, as described in Note 18 to the Consolidated Financial Statements).

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

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Based on our mix of proved undeveloped and probable reserves, we estimate that we have an undeveloped drilling inventory of approximately 2,400 net locations in the Pennsylvania and West Virginia Marcellus Shale. At our current drilling pace, these net locations provide more than 20 years of drilling inventory based on net undeveloped Marcellus acres, average expected lateral length of 12,000 feet and well spacing of 1,000 feet. We believe that our combo-development strategy, coupled with our undeveloped inventory located in a premier core asset base, will lead to sustainable free cash flow generation and higher returns on invested capital.

The following table summarizes our capital expenditures for reserve development.

	Years Ended December 31,
	2021		2020		2019
	(Millions)
Marcellus	$	788	$	737	$	1,184
Utica	40		102		193
Total	$	828	$	839	$	1,377

For the years ended December 31, 2021, 2020 and 2019, lease operating costs, excluding production taxes were $0.07, $0.07 and $0.06, respectively.

Properties

The majority of our acreage is held by lease or occupied under perpetual easements or other rights acquired, for the most part, without warranty of underlying land titles. Approximately 28% of our total gross acres is developed. We retain deep drilling rights on the majority of our acreage.

The following table summarizes our acreage disaggregated by state.

	December 31, 2021
	Pennsylvania		West Virginia		Ohio		Total
Total gross productive acreage	396,356		117,972		51,109		565,437
Total gross undeveloped acreage	938,848		364,456		124,151		1,427,455
Total gross acreage	1,335,204		482,428		175,260		1,992,892
Total net productive acreage	336,228		123,734		38,589		498,551
Total net undeveloped acreage	805,349		319,486		108,443		1,233,278
Total net acreage	1,141,577		443,220		147,032		1,731,829
Average net revenue interest of proved developed reserves (a)	59.8	%	82.0	%	48.9	%	62.5	%

(a)As of December 31, 2021, the average net revenue interest of proved developed reserves was 30.9% for northeastern Pennsylvania and 79.0% for southwestern Pennsylvania.

We have an active lease renewal program in areas targeted for development. In the event that production is not established or we do not extend or renew the terms of our expiring leases, 57,361, 36,799 and 31,123 of our net undeveloped acreage as of December 31, 2021 will expire in the years ending December 31, 2022, 2023 and 2024, respectively.

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The following tables summarize our productive and in-process natural gas wells. We had no productive or in-process oil wells as of December 31, 2021.

	December 31, 2021
Productive wells:
Total gross	4,527
Total net	3,510
In-process wells:
Total gross	282
Total net	248

	December 31, 2021
	Pennsylvania	West Virginia	Ohio	Total
Total gross productive wells (a)	3,543	710	274	4,527
Total net productive wells	2,693	677	140	3,510

(a)Of our total gross productive wells, there are 610 gross conventional wells in Pennsylvania and 3 gross conventional wells in West Virginia. We have no gross conventional wells in Ohio.

We drilled 99, 120 and 145 net productive development wells during the years ended December 31, 2021, 2020 and 2019, respectively. During the years ended December 31, 2021, 2020 and 2019, we drilled zero net dry development, net productive exploratory and net dry exploratory wells.

During 2021, we commenced drilling operations (spud) on 96 gross wells (67 net), composed of 50 Pennsylvania Marcellus gross wells (34 net), 41 West Virginia Marcellus gross wells (32 net) and 5 Ohio Utica gross wells (1 net).

Our sales volume in 2021 from the Marcellus Shale was 1,685 Bcfe. The following table summarizes our produced and sold volume by state.

	Pennsylvania	West Virginia	Ohio	Total
	(MMcfe)
Produced and sold natural gas, NGLs and oil for the years ended December 31,
2021	1,422,294	271,747	163,776	1,857,817
2020	1,051,869	267,708	178,215	1,497,792
2019	1,001,973	274,378	231,545	1,507,896

Markets and Customers

Natural Gas Sales. Natural gas is a commodity and, therefore, we typically receive market-based pricing for our produced natural gas. The market price for natural gas in the Appalachian Basin is typically lower relative to NYMEX Henry Hub, Louisiana (the location for pricing NYMEX natural gas futures) as a result of increased supply of natural gas in the Northeast United States. To protect cash flow from undue exposure to the risk of changing commodity prices, we hedge a portion of our forecasted natural gas production at, for the most part, NYMEX natural gas prices. We also enter into derivative instruments to hedge basis. For information on our hedging strategy and our derivative instruments, refer to "Commodity Risk Management" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations," Item 7A., "Quantitative and Qualitative Disclosures About Market Risk" and Note 3 to the Consolidated Financial Statements.

NGLs Sales. We primarily sell NGLs recovered from our natural gas production. We primarily contract with MarkWest Energy Partners, L.P. (MarkWest) to process our natural gas and extract from the produced natural gas heavier hydrocarbon streams (consisting predominately of ethane, propane, isobutane, normal butane and natural gasoline). We also contract with MarkWest to market a portion of our NGLs. In addition, we have contractual arrangements with Williams Ohio Valley Midstream LLC to process our natural gas and market a portion of our NGLs.

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Average Sales Price. The following table presents our average sales price per unit of natural gas, NGLs and oil, with and without the effects of cash settled derivatives, as applicable.

	Years Ended December 31,
	2021		2020		2019
Natural gas ($/Mcf):
Average sales price, excluding cash settled derivatives	$	3.54	$	1.73	$	2.48
Average sales price, including cash settled derivatives	2.38		2.37		2.65
NGLs, excluding ethane ($/Bbl):
Average sales price, excluding cash settled derivatives	$	44.50	$	20.51	$	23.63
Average sales price, including cash settled derivatives	32.18		20.39		25.82
Ethane ($/Bbl):
Average sales price, excluding cash settled derivatives	$	8.85	$	3.48	$	6.16
Average sales price, including cash settled derivatives	8.85		3.48		7.18
Oil ($/Bbl):
Average sales price	$	56.82	$	25.57	$	40.90
Natural gas, NGLs and oil ($/Mcfe):
Average sales price, excluding cash settled derivatives	$	3.66	$	1.77	$	2.51
Average sales price, including cash settled derivatives	2.50		2.37		2.69

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

Natural Gas Marketing. EQT Energy, LLC, our indirect, wholly-owned marketing subsidiary, provides marketing services and contractual pipeline capacity management services primarily for our benefit. EQT Energy, LLC also engages in risk management and hedging activities to limit our exposure to shifts in market prices.

Customers. We sell natural gas and NGLs to marketers, utilities and industrial customers located in the Appalachian Basin and in markets that are accessible through our transportation portfolio, particularly where there is expected future demand growth, such as in the Gulf Coast, Midwest and Northeast United States and Canada. As of December 31, 2021, approximately 50% of our sales volume reaches markets outside of Appalachia. We do not depend on any single customer and believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, NGLs and oil.

We have access to approximately 3.0 Bcf per day of firm pipeline takeaway capacity and 0.9 Bcf per day of firm processing capacity. In addition, we are committed to an initial 1.29 Bcf per day of firm capacity on the Mountain Valley Pipeline upon its in-service date. These firm transportation and processing agreements may require minimum volume delivery commitments, which we expect to principally fulfill with production from existing reserves.

During 2021, we entered into a long-term asset management agreement with an investment grade entity, pursuant to which, we agreed to deliver and sell up to 525,000 Dth of natural gas per day to the investment grade entity for a period of up to six years while managing and using our committed capacity on the Mountain Valley Pipeline upon its in-service date. The asset management agreement is subject to currently unsatisfied conditions; therefore, its impacts have been excluded from the schedule of total gross commitments summarized in the table below.

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We have contractually agreed to deliver firm quantities of gas and NGLs to various customers, which we expect to fulfill with production from existing reserves. We regularly monitor our proved developed reserves to ensure sufficient availability to meet commitments for the next one to three years. The following table summarizes our total gross commitments as of December 31, 2021.

	Natural Gas	NGLs
	(Bcf)	(Mbbl)
Years Ending December 31,
2022	1,425	7,123
2023	936	1,825
2024	717	1,830
2025	464	1,825
2026	403	600
Thereafter	2,663	—

Seasonality

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

Competition

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

Regulation

Regulation of our Operations. Our exploration and production operations are subject to various federal, state and local laws and regulations, including regulations related to the following: the location of wells; the method of drilling, well construction, well stimulation, hydraulic fracturing and casing design; water withdrawal and procurement for well stimulation purposes; well production; spill prevention plans; the use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations; surface usage and the reclamation of properties upon which wells or other facilities have been located; the plugging and abandoning of wells; the calculation, reporting and disbursement of royalties and taxes; and the gathering of production in certain circumstances. These regulations, and any delays in obtaining related authorizations, may affect the costs and timing of developing our natural gas resources.

Our operations are also subject to conservation and correlative rights regulations, including the following: regulation of the size of drilling and spacing units or field rule units; setbacks; the number of wells that may be drilled in a unit or in close proximity to other wells; drilling in the vicinity of coal mining operations and certain other structures; and the unitization or pooling of natural gas properties. Ohio and, for Utica or other deep wells, West Virginia allow the statutory pooling or unitization of tracts to facilitate development and exploration. In West Virginia, we must rely on voluntary pooling of lands and leases for Marcellus acreage. In Pennsylvania, lease integration legislation authorizes joint development of existing contiguous leases. In addition, state conservation and oil and gas laws generally limit the venting or flaring of natural gas. Various states also impose certain regulatory requirements to transfer wells to third parties or discontinue operations in the event of divestitures by us.

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

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In 2010, Congress adopted comprehensive financial reform legislation that established federal oversight and regulation of the OTC derivative market and entities, such as us, that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), required the CFTC, the SEC and other regulatory agencies to promulgate rules and regulations implementing this legislation. Among other things, the Dodd-Frank Act established margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail their derivative activities. Although some of the rules necessary to implement the Dodd-Frank Act have yet to be adopted, regulators have issued numerous rules under the Dodd-Frank Act, including a rule establishing an "end-user" exception to mandatory clearing (End-User Exception), a rule requiring the posting of margin for certain uncleared swaps (Margin Rule) and a rule imposing federal position limits on certain futures contracts relating to energy products, including natural gas (Position Limits Rule).

We qualify as a "non-financial entity" for purposes of the End-User Exception and, as such, we are eligible for such exception. As a result, our hedging activities are not subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing, although we are subject to certain recordkeeping and reporting obligations associated with such rule. We also qualify as a "non-financial end user" for purposes of the Margin Rule; therefore, our uncleared swaps are not subject to regulatory margin requirements. Finally, we believe that the majority, if not all, of our hedging activities constitute bona fide hedging under the Position Limits Rule and are not materially impacted by the limitations under such rule. However, many of our hedge counterparties and other market participants are not eligible for the End-User Exception, are subject to mandatory clearing and the Margin Rule for swaps with some or all of their other swap counterparties, and may be subject to the Position Limits Rule, which may affect the pricing and/or availability of derivatives for us. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations related to derivatives which apply to our transactions with counterparties subject to such foreign regulations.

Regulators periodically review or audit our compliance with applicable regulatory requirements. We anticipate that compliance with existing laws and regulations governing current operations will not have a material adverse effect upon our capital expenditures, earnings or competitive position. Additional proposals that affect the oil and gas industry are regularly considered by Congress, the states, regulatory agencies and the courts. We cannot predict when or whether any such proposals may become effective or the effect that such proposals may have on us.

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

Natural Gas Sales and Transportation. The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. The FERC's regulations for interstate oil and natural gas transportation in some circumstances may also affect the intrastate transportation of oil and natural gas.

Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978. Various federal laws enacted since 1978 have resulted in the removal of all price and non-price controls for sales of domestic natural gas sold in first sales, which include all of our sales of our own production. Under the Energy Policy Act of 2005, the FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties of over $1.3 million per day for each violation and disgorgement of profits associated with any violation. While our production activities have not been regulated by the FERC as a natural gas company under the NGA, we are required to report aggregate volume of natural gas purchased or sold at wholesale to the extent such transactions use, contribute to or may contribute to the formation of price indices. In addition, Congress may enact legislation or the FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject us to civil penalties.

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

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

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

Oil and NGLs Price Controls and Transportation Rates. Sales prices of oil and NGLs are not currently regulated and are made at market prices. Our sales of these commodities are, however, subject to laws and regulations issued by the Federal Trade Commission (FTC) prohibiting manipulative or fraudulent conduct in the wholesale petroleum market. The FTC holds substantial enforcement authority under these regulations, including the ability to assess civil penalties of over $1.2 million per day per violation. Our sales of these commodities, and any related hedging activities, are also subject to CFTC oversight and enforcement authority as discussed above.

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

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Environmental, Health and Safety Regulation. Our business operations are also subject to numerous stringent federal, state and local environmental, health and safety laws and regulations pertaining to, among other things, the release, emission or discharge of materials into the environment; the generation, storage, transportation, handling and disposal of certain materials, including solid and hazardous wastes; the safety of employees and the general public; pollution; site remediation; and preservation or protection of human health and safety, natural resources, wildlife and the environment. We must take into account environmental, health and safety regulations in, among other things, planning, designing, constructing, operating and plugging and abandoning wells and related facilities. Violations of these laws can result in substantial administrative, civil and criminal penalties. These laws and regulations may require us to acquire permits before drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands and other protected areas or areas with endangered or threatened species restrictions; require some form of remedial action to prevent, remediate or mitigate pollution from operations, such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with applicable laws and regulations. In addition, these laws and regulations may restrict the rate of production.

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

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

Hazardous Substances and Waste Handling. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the "Superfund" law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, despite the "petroleum exclusion" of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we generate materials in the course of our operations that may be regulated as hazardous substances based on their characteristics; however, we are unaware of any liabilities arising under CERCLA for which we may be held responsible that would materially and adversely affect us.

The Resource Conservation and Recovery Act (RCRA) and analogous state laws establish detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA, or state agencies under RCRA's less stringent nonhazardous solid waste provisions, or under state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. In April 2019, following litigation and a resulting consent decree related to the EPA's requirements under RCRA to review oil and gas waste regulations, the EPA determined that revisions to the regulations were not required, concluding that any adverse effects related to oil and gas waste were more appropriately and readily addressed within the framework of existing state regulatory programs. Any changes to state or federal programs could result in an increase in our costs to manage and dispose waste, which could have a material adverse effect on our results of operations and financial condition.

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

Water Discharges. The Federal Water Pollution Control Act, known as the Clean Water Act (CWA), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or a state equivalent agency. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (Corps). In June 2015, the EPA and the Corps issued a rule defining the scope of the EPA's and the Corps' jurisdiction over waters of the United States (WOTUS), which never took effect before being replaced by the Navigable Waters Protection Rule (NWPR) in December 2019. A coalition of states and cities, environmental groups, and agricultural groups challenged the NWPR, which was vacated by a federal district court in August 2021. The EPA is undergoing a rulemaking process to redefine the definition of waters of the United States; in the interim, the EPA is using the pre-2015 definition. In addition, in an April 2020 decision further defining the scope of the CWA, the U.S. Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit. The Court rejected the EPA and Corps' assertion that groundwater should be totally excluded from the CWA. To the extent a new rule or further litigation expands the scope of the CWA's jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which could delay the development of our natural gas and oil projects. Also, pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or stormwater and to develop and implement spill prevention, control and countermeasure (SPCC) plans in connection with on-site storage of significant quantities of oil. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances and may impose substantial potential liability for the costs of removal, remediation and natural resource and other damages.

Air Emissions. Through the federal Clean Air Act (CAA) and comparable state and local laws and regulations, the EPA regulates emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits.

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

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Further, on November 15, 2021, the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources. The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA, including intermittent vent pneumatic controllers and associated gas and liquids unloading facilities. In addition, the proposed rule would establish "Emissions Guidelines," creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. Under the proposed rule, states would have three years to develop their compliance plan for existing sources and the regulations for new sources would take effect immediately upon issuance of a final rule. The EPA is expected to issue both a supplemental proposed rule, which may expand or modify the current proposed rule, and final rule by the end of 2022.

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

Climate Change and Regulation of Greenhouse Gas Emissions. In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in nearly 200 countries, including the United States, coming together to develop the Paris Agreement, which calls for the signatories to the agreement to undertake "ambitious efforts" to limit increases in the average global temperature. Although the agreement does not create any binding obligations for nations to limit their greenhouse gas (GHG) emissions, it does include pledges to voluntarily limit or reduce future emissions. On June 1, 2017, President Trump announced that the U.S. would withdraw from the Paris Agreement and completed the process of withdrawing from the Paris Agreement on November 4, 2020. However, on January 20, 2021, President Biden issued written notification to the United Nations of the U.S.'s intention to rejoin the Paris Agreement, which became effective on February 19, 2021. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions to at least 30% below 2020 levels by 2030. Since its formal launch at the United Nations Climate Change Conference (COP26), over 100 countries have joined the pledge.

On November 3, 2021, the U.S. House of Representatives passed budget reconciliation bill H.R. 5376, known as the Build Back Better Act. The House version of the bill includes a provision targeting methane emissions from oil and gas sources by proposing to implement fees for excess methane leaking from wells, storage sites and pipelines as well as fees for new producing and non-producing oil and gas leases and off-shore pipelines. It is unclear whether the Build Back Better Act will be passed in its current form by the U.S. Senate.

Additionally, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap-and-trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting GHGs. In October 2019, Pennsylvania Governor Tom Wolf signed an Executive Order directing the Pennsylvania Department of Environmental Protection (PADEP) to draft regulations establishing a cap-and-trade program under its existing authority to regulate air emissions, with the intent of enabling Pennsylvania to join the Regional Greenhouse Gas Initiative (RGGI), a multi-state regional cap-and-trade program comprised of several Eastern U.S. states. In September 2020, the Pennsylvania Environmental Quality Board (EQB) approved promulgation of the RGGI regulation, and a public comment period and hearings regarding the regulation commenced at the end of 2020. In September 2021, Pennsylvania's Independent Regulatory Review Commission adopted a regulation approving Pennsylvania's participation in RGGI; however, in October 2021 the Pennsylvania Senate approved a resolution to block the state's participation in RGGI, and such resolution was subsequently approved by the Pennsylvania House in December 2021. On January 10, 2022, Governor Wolf vetoed the Senate's resolution, and as a result, it is likely that Pennsylvania will join RGGI in 2022 unless the Pennsylvania legislature overrides the Governor's veto by the vote of two-thirds of the members of each of the Pennsylvania House and Senate. In the event that Pennsylvania ultimately becomes a member of RGGI, it will result in increased operating costs if we are required to purchase emission allowances in connection with our operations.

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

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

Notwithstanding potential risks related to climate change, the International Energy Agency estimates that natural gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. Nonetheless, recent activism directed at shifting funding away from fossil fuel companies could result in limitations or restrictions on certain sources of funding for the sector. Moreover, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult to engage in exploration and production activities.

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

Hydraulic Fracturing Activities. Vast quantities of natural gas deposits exist in shale and other formations. It is customary in our industry to recover natural gas from these shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations underground where water, sand and other additives are pumped under high pressure into a shale gas formation. These deeper formations are geologically separated and isolated from fresh ground water supplies by overlying rock layers. Our well construction practices include installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers. To assess water sources near our drilling locations, we conduct multiple pre-drill samplings for all water sources within 3,000 feet of our sites and post-drill samplings for sources within 1,500 feet of our sites.

Hydraulic fracturing typically is regulated by state oil and natural gas agencies, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (SDWA) over certain hydraulic fracturing activities involving the use of diesel fuels and has prohibited the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in January 2020, the EQB approved a well permit fee increase from $5,000 to $12,500 for all unconventional wells. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have sought to ban hydraulic fracturing altogether. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from constructing wells.

Occupational Safety and Health Act. We are also subject to the requirements of the federal Occupational Safety and Health Act (OSH Act) and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Health and Safety Administration's (OSHA) hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require us to maintain information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities, and citizens.

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Endangered Species Act and Migratory Bird Treaty Act. The federal Endangered Species Act (ESA) provides for the protection of endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species' habitat. The U.S. Fish and Wildlife Service (FWS) may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. In August 2019, the FWS and National Marine Fisheries Service (NMFS) issued three rules amending implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitat. A coalition of states and environmental groups have challenged the three rules and litigation remains pending. In addition, in December 2020, the FWS amended its regulations governing critical habitat designations; the amended regulations are subject to ongoing litigation. In June 2021, the FWS and the NMFS announced plans to begin rulemaking processes to rescind these rules. Protections similar to the ESA are offered to migratory birds under the Migratory Bird Treaty Act (MBTA), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. In January 2021, the Department of the Interior finalized a rule limiting application of the MBTA; however, the Department of the Interior revoked the rule in October 2021 and issued an advance notice of proposed rulemaking seeking comment on the Department's plan to develop regulations that authorize incidental taking under certain prescribed conditions. Future implementation of the rules implementing the ESA and the MBTA are uncertain. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for natural gas development. Further, the designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves.

See Note 16 to the Consolidated Financial Statements for a description of expenditures related to environmental matters.

Human Capital Resources

As of December 31, 2021, we had 693 permanent employees, none of whom were subject to a collective bargaining agreement. Of our total permanent employee base, 75% were male and 25% were female. Approximately 70% of our permanent employees worked remotely, with 93% residing in Pennsylvania or West Virginia.

We aim to develop a workforce that produces peer leading results. To further that goal, we have focused on creating a modern, innovative, collaborative and digitally-enabled work environment. In 2019, we simplified our organizational structure and instituted a cloud-based digital work environment with an emphasis on the democratization of data. Our digital work environment serves as our primary platform for communication and collaboration as well as the home for our critical work processes and drives decision-making based on a shared and transparent view of operational data. We use our digital work environment to engage directly with our employees by sharing company updates and personnel accomplishments as well as to solicit suggestions and comments from all employees. We believe that this helps promote real-time feedback and a greater degree of employee engagement, which lays the foundation for the success of our remote workforce.

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

In 2020, we launched an "equity-for-all" program, pursuant to which, in 2021, we granted equity awards to all of our permanent employees. In 2022, we continued our equity-for-all program by granting equity awards to all permanent employees. With the equity-for-all program, all of our permanent employees become owners of EQT and have the opportunity to share directly in our financial success. Equity-for-all grants are in addition to, and not in lieu of, the existing compensation opportunities for our employees.

Availability of Reports and Other Information

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

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

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

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

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

Composition of Operating Revenues

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

	Years Ended December 31,
	2021		2020		2019
	(Thousands)
Operating revenues:
Sales of natural gas, natural gas liquids and oil	$	6,804,020	$	2,650,299	$	3,791,414
(Loss) gain on derivatives not designated as hedges	(3,775,042)		400,214		616,634
Net marketing services and other	35,685		8,330		8,436
Total operating revenues	$	3,064,663	$	3,058,843	$	4,416,484

Jurisdiction and Year of Formation

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

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Item 1A.    Risk Factors

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

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 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 GHGs, and limitations on hydraulic fracturing;

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

•supply chain disruptions or labor shortage impacts related to the COVID-19 pandemic or other global pandemics;

•equipment failures, accidents or other unexpected operational events;

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

•lack of available capacity on interconnecting transportation pipelines;

•adverse weather conditions, such as flooding, droughts, freeze-offs, landslides, 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;

•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 issues; 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 hazards, such as natural gas leaks, oil and diesel spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized releases of brine, well stimulation and completion fluids, toxic gases or other pollutants into the environment, especially those that reach surface water or groundwater; inadvertent third-party damage to our assets, and natural disasters. We also face various risks or threats to the operation and security of our or third parties' facilities and infrastructure, such as processing plants, compressor stations and pipelines. Any of these risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property, equipment and natural resources, pollution or other environmental damage, loss of hydrocarbons, disruptions to our operations, regulatory investigations and penalties, suspension of our operations, repair and remediation costs, and loss of sensitive confidential information. Moreover, in the event that one or more of these hazards occur, there can be no assurance that a response will be adequate to limit or reduce damage.

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

Our drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of when they are drilled, if at all.

Our management team has specifically identified and scheduled certain well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our business strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas, NGLs and oil prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results, lease expirations, topography, gathering system and pipeline transportation costs and constraints, access to and availability of water sourcing and distribution systems, coordination with coal mining, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce natural gas, NGLs or oil from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, our leases for such acreage will expire. Further, certain of the horizontal wells we intend to drill in the future may require pooling or unitization with adjacent leaseholds controlled by third parties. If these third parties are unwilling to pool or unitize such leaseholds with ours, the total locations we can drill may be limited. As such, our actual drilling activities may materially differ from those presently identified.

Failure to timely develop our leased real property could result in increased capital expenditures and/or impairment of our leases.

Mineral rights are typically owned by individuals who may enter into property leases with us to allow for the development of natural gas. Such leases expire after an initial term, typically five years, unless certain actions are taken to preserve the lease. If we cannot preserve a lease, the lease terminates. Approximately 10% of our net undeveloped acres are subject to leases that could expire over the next three years. Lack of access to capital, changes in government regulations, changes in future development plans or commodity prices, reduced drilling activity, or the reduction in the fair value of undeveloped properties in the areas in which we operate could impact our ability to preserve, trade or sell our leases prior to their expiration, resulting in the termination or impairment of leases for properties that we have not developed.

We evaluate capitalized costs of unproved oil and gas properties at least annually to determine recoverability on a prospective basis. Indicators of potential impairment include changes brought about by economic factors, potential shifts in our business strategy and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches and drilling activity has not commenced. For the years ended December 31, 2021, 2020 and 2019, we recorded impairment and expiration of leases of $311.8 million, $306.7 million and $556.4 million, respectively. Refer to Note 1 to the Consolidated Financial Statements.

We may incur losses as a result of title defects in the properties in which we invest.

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

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The amount and timing of actual future natural gas, NGLs and oil production is difficult to predict and may vary significantly from our estimates, which may reduce our earnings.

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

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

Our proved reserves are estimates that are based on many assumptions that may prove to be inaccurate. Any significant change in these underlying assumptions will greatly affect the quantities and present value of our reserves.

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

The standardized measure of discounted future net cash flows from our proved reserves is not the same as the current market value of our estimated natural gas, NGLs and crude oil reserves.

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated natural gas, NGLs and crude oil reserves. In accordance with SEC requirements, we based the discounted future net cash flows from our proved reserves on the twelve-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net cash flows from our properties will be affected by factors such as the actual prices we receive for natural gas, NGLs and oil, the amount, timing and cost of actual production and changes in governmental regulations or taxation. The timing of both our production and our incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating the standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our operations or the natural gas, NGLs and oil industry in general.

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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.

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

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

Financial and Market Risks Applicable to Our Business

Natural gas, NGLs and oil prices are affected by a number of factors beyond our control, including many of which that are unknown and cannot be anticipated, and we cannot predict with certainty future potential movements in the price for these commodities.

Our primary business involves the exploration, production and sale of hydrocarbons, and in particular, natural gas. Consequently, our revenue, profitability, future rate of growth, liquidity and financial position depend upon the market prices for natural gas and, to a lesser extent, NGLs and oil. The prices for natural gas, NGLs and oil have historically been volatile, and we expect this volatility to continue in the future. The prices are affected by a number of factors beyond our control, which include:

•weather conditions and seasonal trends;

•the domestic and foreign supply of and demand for natural gas, NGLs and oil;

•prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices;

•national and worldwide economic and political conditions;

•new and competing exploratory finds of natural gas, NGLs and oil;

•changes in U.S. exports of natural gas, NGLs and oil;

•the effect of energy conservation efforts;

•the price, availability and consumer demand for alternative fuels;

•the availability, proximity, capacity and cost of pipelines, other transportation facilities, and gathering, processing and storage facilities and other factors that result in differentials to benchmark prices;

•technological advances affecting energy consumption and production;

•the actions of the Organization of Petroleum Exporting Countries;

•the level and effect of trading in commodity futures markets, including commodity price speculators and others;

•the cost of exploring for, developing, producing and transporting natural gas, NGLs and oil;

•risks associated with drilling, completion and production operations; and

•domestic, local and foreign governmental regulations, tariffs and taxes, including environmental and climate change regulation.

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The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $23.86 per MMBtu to a low of $2.43 per MMBtu from January 1, 2021 through December 31, 2021, and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of $85.64 per barrel to a low of $47.47 per barrel during the same period. In addition, the market price for natural gas in the Appalachian Basin is typically lower relative to NYMEX Henry Hub as a result of the increased production and supply of natural gas in the Northeast United States. Because our production and reserves predominantly consist of natural gas (approximately 94% of our equivalent proved developed reserves), changes in natural gas prices have significantly greater impact on our financial results than oil prices. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, which adds further volatility to the pricing of NGLs.

We use financial models to attempt to project future prices for the hydrocarbons we produce and sell, and we make decisions regarding our production, operations and hedging strategy in part based on such modelling. However, due to the volatility of commodity prices and the multitude of external factors that impact commodity prices, many of which are unknown and unforeseeable, such as reduced demand as a result of a general economic slowdown related to the COVID-19 pandemic or other global pandemics, we are unable to predict with certainty future potential movements in the market prices for natural gas, NGLs and oil. Accordingly, the success of our plans and strategies could be negatively affected if our projections of future hydrocarbon prices are significantly different from the ultimate actual price.

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.

Prolonged low, and/or significant or extended declines in, natural gas, NGLs and oil prices may adversely affect our revenues, operating income, cash flows and financial position, particularly if we are unable to control our development costs during periods of lower natural gas, NGLs and oil prices. Declines in prices could also adversely affect our drilling activities and the amount of natural gas, NGLs and oil that we can produce economically, which may result in our having to make significant downward adjustments to the value of our assets and could cause us to incur non-cash impairment charges to earnings. Reductions in cash flows from lower commodity prices may require us to incur additional debt or reduce our capital spending, which could reduce our production and our reserves, negatively affecting our future rate of growth. Lower prices for natural gas, NGLs and oil may also adversely affect our credit ratings and result in a reduction in our borrowing capacity and access to other capital. See "Impairment of Oil and Gas Properties" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations."

Increases in natural gas, NGLs and oil prices may be accompanied by or result in increased well drilling costs, increased production taxes, increased lease operating expenses, increased volatility in seasonal gas price spreads for our storage assets and increased end-user conservation or conversion to alternative fuels. Significant natural gas price increases may subject us to margin calls on our commodity price derivative contracts (hedging arrangements, including swap, collar and option agreements and exchange-traded instruments), which would potentially require us to post significant amounts of cash collateral or letters of credit with our hedge counterparties and would negatively impact our liquidity. The cash collateral provided to our hedge counterparties, which is interest-bearing, is returned to us in whole or in part upon a reduction in forward market prices, depending on the amount of such reduction, or in whole upon settlement of the related derivative contract. In addition, to the extent we have hedged our current production at prices below the current market price, we will not benefit fully from an increase in the price of natural gas.

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

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We may not be able to successfully execute our plan to deleverage our business or otherwise reduce our debt level.

In December 2021, we reaffirmed our commitment to attaining investment grade credit metrics and outlined a leverage and debt reduction strategy with the goal of reducing our total debt by $1.5 billion by the end of 2023 (our Debt Reduction Plan). We intend to fund our Debt Reduction Plan through free cash flow, and have aligned our hedge strategy in a manner that we believe will mitigate the risk of volatility of future natural gas and NGLs prices, which we anticipate will enable us to execute on our Debt Reduction Plan and other capital allocation strategies; however, there can be no assurance that we will be able to generate sufficient free cash flow to execute our Debt Reduction Plan on our anticipated timeframe, if at all. If we are not able to successfully execute our Debt Reduction Plan or otherwise reduce our total debt to a level we believe appropriate, our credit ratings may be lowered, we may reduce or delay our planned capital expenditures or investments, and we may revise or delay our shareholder returns strategy or other strategic plans.

Our exploration and production operations have substantial capital requirements, and we may not be able to obtain needed capital or financing on satisfactory terms.

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

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

•our level of proved reserves and production;

•the level of hydrocarbons we are able to produce from existing wells;

•our access to, and the cost of accessing, end markets for our production;

•the prices at which our production is sold;

•our ability to acquire, locate and produce new reserves;

•the levels of our operating expenses; and

•our ability to access the public or private capital markets or borrow under our credit facility.

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

As of December 31, 2021, our senior notes were rated "Ba1" with a "stable" outlook by Moody's Investors Services (Moody's), "BB+" with a "positive" outlook by Standard & Poor's Ratings Service (S&P) and "BB+" with a "stable" outlook by Fitch Ratings Service (Fitch). Although we are not aware of any current plans of Moody's, S&P or Fitch to downgrade its rating of our senior notes, we cannot be assured that one or more of these rating agencies will not downgrade or withdraw entirely its rating of our senior notes. Low prices for natural gas, NGLs and oil, an increase in the level of our indebtedness or other factors may result in Moody's, S&P or Fitch downgrading its rating of our senior notes. Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our lines of credit, the interest rate on the Adjustable Rate Notes (defined in Note 10 to the Consolidated Financial Statements), 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.

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Risks associated with our debt and the provisions of our debt agreements could adversely affect our business, financial position and results of operations.

As of December 31, 2021, we had approximately $5.5 billion of debt outstanding, and we may incur additional indebtedness in the future. Increases in our level of indebtedness may:

•require us to use a substantial portion of our cash flow to make debt service payments, which will reduce the funds that would otherwise be available for operations and future business opportunities;

•limit our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making certain investments, and paying dividends;

•place us at a competitive disadvantage compared to our competitors with lower debt service obligations;

•depending on the levels of our outstanding debt, limit our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes; and

•increase our vulnerability to downturns in our business or the economy, including declines in prices for natural gas, NGLs and oil.

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

We are subject to financing and interest rate exposure risks.

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

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

Derivative transactions may limit our potential gains and involve other risks.

To manage our exposure to price risk, we currently and may in the future enter into derivative arrangements, utilizing commodity derivatives with respect to a portion of our future production. Such hedges are designed to lock in prices in order to limit volatility and increase the predictability of cash flow. These transactions limit our potential gains if natural gas, NGLs and oil prices rise above the price established by the hedge, and we may be required to post cash collateral or letters of credit with our hedge counterparties to the extent our liability under the derivative contract exceeds specified thresholds, which would negatively impact our liquidity. We have previously sustained losses as a result of certain of our derivative arrangements (including a $3.8 billion loss in 2021), and we cannot assure you that we will not do so in the future. In addition, derivative transactions may expose us to the risk of financial loss in certain circumstances, including instances in which our production is less than expected or an event materially impacts natural gas, NGLs or oil prices or the relationship between the hedged price index and the natural gas, NGLs or oil sales price.

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

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

The accounting for the Convertible Notes may have a material effect on our reported financial results.

On April 28, 2020, we issued the Convertible Notes (defined in Note 10 to the Consolidated Financial Statements) due May 1, 2026 unless earlier redeemed, repurchased or converted. In accordance with GAAP, an issuer must separately account for the liability and equity components of certain convertible debt instruments that may be settled entirely or partially in cash upon conversion in a manner that reflects the issuer's economic interest cost. The effect on the accounting for the Convertible Notes is that the equity component is required to be included in additional paid-in capital of shareholders' equity on our Consolidated Balance Sheet, and the value of the equity component is treated as a debt discount for purposes of accounting for the debt component of the Convertible Notes. Accordingly, we will be required to record a greater amount of non-cash interest expense in current and future periods as a result of the amortization of the discounted carrying value of the Convertible Notes to their face amount over the term of the Convertible Notes. We will report lower net income (or greater net loss) in our financial results because GAAP requires interest to include both the current period's amortization of the debt discount and the instrument's coupon interest, which could adversely affect our reported or future financial results, the market price of our common stock and the trading price of the Convertible Notes.

In addition, because we have the ability and intent to settle the Convertible Notes, upon conversion, by paying or delivering cash equal to the principal amount of the obligation and common stock for amounts over the principal amount, the shares issuable upon conversion of the Convertible Notes are accounted for using the treasury stock method and, as such, are not included in the calculation of diluted earnings per share except to the extent that the conversion value of the Convertible Notes exceeds their principal amount. Further, under the treasury stock method, the transaction is accounted for as if the number of shares of common stock that would be necessary to settle such excess are issued. We cannot be sure that we will be able to continue to demonstrate the ability or intent to settle the Convertible Notes in cash or that the accounting standards will continue to permit the use of the treasury stock method. If we are unable to use the treasury stock method in accounting for the shares issuable upon conversion of the Convertible Notes, our diluted earnings per share could be adversely affected.

See Note 1 to the Consolidated Financial Statements for a discussion of the new accounting guidance that will be adopted on January 1, 2022 as well as the effects that it will have on the accounting for the Convertible Notes.

Risks Associated with Our Human Capital, Technology and Other Resources and Service Providers

Strategic determinations, including the allocation of resources to strategic opportunities, are challenging, and our failure to appropriately allocate resources among our strategic opportunities may adversely affect our financial position and reduce our future prospects.

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

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Cyber incidents targeting our digital work environment or other technologies or natural gas and oil industry systems and infrastructure may adversely impact our operations.

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

The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. We can provide no assurance that we will not suffer such attacks in the future. Deliberate attacks on, or unintentional events affecting, our digital work environment or other technologies and infrastructure, the systems or infrastructure of third parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery of natural gas, NGLs and oil, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, personal injury, property damage, other operational disruptions and third-party liability. Further, as cyber incidents continue to evolve and cyber attackers become more sophisticated, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. The cost to remedy an unintended dissemination of sensitive information or data may be significant. Furthermore, the continuing and evolving threat of cyber-attacks has resulted in increased regulatory focus on prevention. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.

The unavailability or high cost of additional drilling rigs, completion services, equipment, supplies, personnel, and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers, and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages or higher costs. Historically, there have been shortages of personnel and equipment as demand for personnel and equipment has increased along with the number of wells being drilled. Additionally, our operations may be disrupted or impaired if a significant portion of our or our service providers' employees or contractors are unable to work due to illness or if our field operations are suspended or temporarily shut-down or restricted due to control measures designed to contain the COVID-19 pandemic. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could materially adversely affect our business, results of operations, cash flows and financial position.

Our ability to drill for and produce natural gas is dependent on the availability of adequate supplies of water for drilling and completion operations and access to water and waste disposal or recycling services at a reasonable cost and in accordance with applicable environmental rules. Restrictions on our ability to obtain water or dispose of produced water and other waste may adversely affect our results of operations, cash flows and financial position.

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

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

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The loss of key personnel could adversely affect our ability to execute our strategic, operational and financial plans.

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

We depend on third-party midstream providers for a significant portion of our midstream services, and our failure to obtain and maintain access to the necessary infrastructure to successfully deliver natural gas, NGLs and oil to market on competitive terms may adversely affect our earnings, cash flows and results of operations.

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

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

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

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The substantial majority of our midstream and water services are provided by one provider, EQM Midstream Partners LP (EQM), a wholly-owned subsidiary of Equitrans Midstream. Therefore, any regulatory, infrastructure or other events that materially adversely affect Equitrans Midstream's business operations will have a disproportionately adverse effect on our business and operating results as compared to similar events experienced by our other third-party service providers. Additionally, our midstream services contracts with EQM involve significant long-term financial and other commitments on our part, which hinders our ability to diversify our slate of midstream service providers and seek better economic and other terms for the midstream services that are provided to us. We have no control over Equitrans Midstream's or EQM's business decisions and operations, and neither Equitrans Midstream nor EQM is under any obligation to adopt a business strategy that favors us.

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

•federal, state and local regulatory, political and legal actions that could adversely affect Equitrans Midstream's and EQM's operations, assets and infrastructure, including potential further delays associated with obtaining regulatory approval for the construction of the Mountain Valley Pipeline;

•construction risks associated with the construction or repair of EQM's pipelines and other midstream infrastructure, such as delays caused by landowners or advocacy groups opposed to the natural gas industry, environmental hazards, adverse weather conditions, the performance of third-party contractors, the lack of available skilled labor, equipment and materials and the inability to obtain necessary rights-of-way or approvals and permits from regulatory agencies on a timely basis or at all (and maintain such rights-of-way, approvals and permits once obtained);

•cyber-attacks or acts of sabotage or terrorism that could cause significant damage or injury to Equitrans Midstream's personnel, assets or infrastructure or lead to extended interruptions of Equitrans Midstream's operations;

•risks associated with Equitrans Midstream failing to properly balance supply and demand for its services, on a short-term, seasonal and long-term basis, which could result in Equitrans Midstream being unable to provide its customers, including us, with sufficient access to pipeline and other midstream infrastructure and water services as needed; and

•risks associated with Equitrans Midstream's leverage and financial profile, which could result in Equitrans Midstream being financially deterred or prohibited from providing services to its customers, including us, on a timely basis or at all.

In addition, many of our midstream services obligations with EQM are "firm" commitments, under which we have reserved an agreed upon amount of pipeline or storage capacity with EQM regardless of the capacity that we actually use during each month, and we are generally obligated to pay a fixed, monthly charge, at an amount agreed upon in the contract. Because these obligations involve significant long-term financial and other commitments on our part, they could reduce our cash flow during periods of low prices for natural gas, NGLs and oil when we may have lower volume of natural gas and NGLs and therefore less of a need for capacity and storage, or the market prices for such pipeline and storage capacity services may be lower than what we are contractually obligated to pay to EQM. 

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Further, the Consolidated GGA provides for a reduced fee structure for the gathering and compression fees charged by EQM; however this new fee structure does not take effect until the Mountain Valley Pipeline's in-service date. There can be no assurance that the in-service date of the Mountain Valley Pipeline will not be delayed, or that the project will not be cancelled entirely, which would consequently delay, possibly indefinitely, the effective date of the fee reductions contemplated in the Consolidated GGA. Neither Equitrans Midstream nor EQM is under any obligation to renegotiate their contracts with us, including the Consolidated GGA, in the event of a prolonged depressed commodity price environment or if the Mountain Valley Pipeline's in-service date is delayed. We have recorded in our Consolidated Balance Sheet a contract asset of $410 million representing the estimated fair value of the rate relief provided by the Consolidated GGA that would be realized beginning with the Mountain Valley Pipeline’s in-service date. We review the contract asset for indications of impairment when events or circumstances indicate the carrying value may not be recoverable. Future delays in the Mountain Valley Pipeline's in-service date may affect our ability to fully realize the value we recorded as a contract asset for the rate relief associated with the Consolidated GGA, which could adversely affect our results of operations in future periods.

Substantially all of our producing properties are concentrated in the Appalachian Basin, making us vulnerable to risks associated with operating primarily in one major geographic area.

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

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

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

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

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Legal and Regulatory Risks

Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

Opposition toward oil and natural gas drilling and development activities generally has been growing globally and is particularly pronounced in the U.S., and companies in our industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental matters, sustainability and business practices. Negative public perception regarding us and/or our industry may lead to increased litigation and regulatory, legislative and judicial scrutiny, which may, in turn, lead to new local, state and federal laws, regulations, guidelines and enforcement interpretations in safety, environmental, royalty and surface use areas. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, challenged or burdened by requirements that restrict our ability to profitably conduct our business. In addition, anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations, such as drilling and development. If activism against oil and natural gas exploration and development persists or increases, there could be a material adverse effect on our business, financial condition and results of operations.

Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the natural gas, NGLs and oil that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

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

In February 2021, the U.S. formally rejoined the Paris Agreement, an international treaty signed by nearly 200 counties which calls for countries to set their own GHG emissions targets and to be transparent about the measures they will implement to achieve their GHG emissions targets. In furtherance of the objectives of the Paris Agreement, in April 2021, the Biden Administration announced goals aimed at reducing the U.S.’s GHG emissions by 50-52% (compared to 2005 levels) by 2030. The federal government has correspondingly instituted several regulations and initiatives in alignment with the goal of reducing the U.S.’s GHG emissions.

In June 2021, President Biden signed legislation reinstituting regulations which were previously repealed by the Trump Administration establishing NSPS for methane and VOC from new and modified oil and natural gas production and natural gas processing and transmission facilities. Additionally, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet "best available control technology" standards that will be established by the states or, in some cases, by the EPA on a case‑by‑case basis. Furthermore, in November 2021, the EPA announced proposed rules expanding upon the NSPS rule which, if instituted, would establish standards for existing wells, impose more frequent and stringent leak monitoring, and mandate that all pneumatic controllers have zero emissions.

Separately, there have also been several instances of proposed legislation at the federal level which seek to impose a fee on methane emissions. Most recently, in November 2021, the U.S. House of Representatives passed a budget reconciliation bill known as the Build Back Better Act. The version of the bill approved by the House includes a provision that would impose charges on oil and gas facilities for their methane emissions. Under the bill, the EPA would levy "methane fees" starting at $900 per ton in 2023, increasing to $1,200 in 2024 and then $1,500 in 2025 and each year thereafter. The fee would apply to each ton of methane emissions in excess of 0.20% of the gas sold by the facility. The bill is currently under review by the U.S. Senate, and it is unclear at this time as to what the final terms of any proposed methane fee may be.

These federal rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits. Additionally, to the extent a fee on methane and/or carbon emissions is approved at the federal level, we, the utilities that purchase our natural gas, and/or the consumers of our natural gas and other hydrocarbons may bear increased costs associated with such fees, which may lead to an increase in our operating costs and/or a decrease in the demand for our produced hydrocarbons.

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At the state level, several states including Pennsylvania have proceeded with a number of state and regional efforts aimed at tracking and/or reducing GHG emissions by means of cap-and-trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. In October 2019, Pennsylvania Governor Tom Wolf signed an Executive Order directing the PADEP to draft regulations establishing a cap-and-trade program under its existing authority to regulate air emissions, with the intent of enabling Pennsylvania to join RGGI, a multi-state regional cap-and-trade program comprised of several Eastern U.S. states. In September 2020, the EQB approved promulgation of the RGGI regulation, and a public comment period and hearings regarding the regulation commenced at the end of 2020. In September 2021, Pennsylvania’s Independent Regulatory Review Commission adopted a regulation approving Pennsylvania’s participation in RGGI; however, in October 2021 the Pennsylvania Senate approved a resolution to block the state's participation in RGGI, and such resolution was subsequently approved by the Pennsylvania House in December 2021. On January 10, 2022, Governor Wolf vetoed the Senate's resolution, and as a result, it is likely that Pennsylvania will join RGGI in 2022 unless the Pennsylvania legislature overrides the Governor's veto by the vote of two-thirds of the members of each of the Pennsylvania House and Senate. In the event that Pennsylvania ultimately becomes a member of RGGI, it will result in increased operating costs if we are required to purchase emission allowances in connection with our operations.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the natural gas, NGLs and oil we produce and lower the value of our reserves.

Further, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Moreover, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult to engage in exploration and production activities.

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

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

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

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

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

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To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Maintaining compliance with the laws, regulations and other legal requirements applicable to our business and any delays in obtaining related authorizations may affect the costs and timing of developing our natural gas, NGLs and oil resources. These requirements could also subject us to claims for personal injuries, property damage and other damages. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could materially adversely affect our results of operations, cash flows and financial position. Our failure to comply with the laws, regulations and other legal requirements applicable to our business, even if as a result of factors beyond our control, could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages as well as corrective action costs.

Changes in tax laws and regulations could adversely impact our earnings and the cost, manner or feasibility of conducting our operations.

Members of Congress periodically introduce legislation to revise U.S. federal income tax laws which could have a material impact on us. The most significant potential tax law changes that could impact us include increases in the regular income tax rate, a new minimum tax based on net income, a new excise tax on stock repurchases, the repeal of expensing intangible drilling costs or percentage depletion, the repeal of like-kind exchange tax deferral rules on real property and further limited deductibility of interest expense, any of which could adversely impact our current and deferred federal and state income tax liabilities. Most recently, in November 2021, the U.S. House passed the Build Back Better Act, which includes some, but not all, of these proposals. The bill is currently under review by the U.S. Senate, and, it is unclear at this time, what, if any, changes to the tax laws applicable to us will be enacted. State and local taxing authorities in jurisdictions in which we operate or own assets may enact new taxes, such as the imposition of a severance tax on the extraction of natural resources in states in which we produce natural gas, NGLs and oil, or change the rates of existing taxes, which could adversely impact our earnings, cash flows and financial position.

Our hedging activities are subject to numerous and evolving financial laws and regulations which could inhibit our ability to effectively hedge our production against commodity price risk or increase our cost of compliance.

We use financial derivative instruments to hedge the impact of fluctuations in natural gas, NGLs and oil prices on our results of operations and cash flows. In 2010, Congress adopted the Dodd-Frank Act, which established federal oversight and regulation of the OTC derivative market and entities, such as us, that participate in that market. The Dodd-Frank Act required the CFTC, the SEC and certain federal agencies that regulate the banking and insurance sectors (Prudential Regulators) to promulgate rules and regulations implementing the legislation. Among other things, the Dodd-Frank Act established margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail their derivative activities. Although some of the rules necessary to implement the Dodd-Frank Act have yet to be adopted, the CFTC, the SEC and Prudential Regulators have issued numerous rules, including the End-User Exception, which exempts certain "end-users" from having to comply with mandatory clearing, a Margin Rule mandating margining for certain uncleared swaps, and a Position Limits Rule imposing federal position limits on certain futures contracts relating to energy products, including natural gas.

We qualify as a "non-financial entity" for purposes of the End-User Exception and, as such, we are eligible for such exception. As a result, our hedging activities are not subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing, although we are subject to certain recordkeeping and reporting obligations associated with such rule. We also qualify as a "non-financial end user" for purposes of the Margin Rule; therefore, our uncleared swaps are not subject to regulatory margin requirements. Finally, we believe that the majority, if not all, of our hedging activities constitute bona fide hedging under the Position Limits Rule and are not materially impacted by the limitations under such rule. However, many of our hedge counterparties and other market participants are not eligible for the End-User Exception, are subject to mandatory clearing and the Margin Rule for swaps with some or all of their other swap counterparties, and may be subject to the Position Limits Rule, which may affect the pricing and/or availability of derivatives for us. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations related to derivatives (collectively, Foreign Regulations) which apply to our transactions with counterparties subject to such Foreign Regulations.

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

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing and governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of natural gas and oil wells, which could adversely affect our production.

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

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.

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

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

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In addition, new or additional laws and regulations, new interpretations of existing requirements or changes in enforcement policies could impose unforeseen liabilities, significantly increase compliance costs or result in delays of, or denial of rights to conduct, our development programs. For example, in June 2015, the EPA and the Corps issued a rule under the CWA defining the scope of the EPA's and the Corps' jurisdiction over WOTUS, which never took effect before being replaced by the NWPR in December 2019. A coalition of states and cities, environmental groups, and agricultural groups challenged the NWPR, which was vacated by a federal district court in August 2021. In addition, in an April 2020 decision further defining the scope of the CWA, the U.S. Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit. The Court rejected the EPA and Corps’ assertion that groundwater should be totally excluded from the CWA. The EPA is undergoing a rulemaking process to redefine the definition of waters of the United States; in the interim, the EPA is using the pre-2015 definition. To the extent a new rule or further litigation expands the scope of the CWA's jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Such potential regulations or litigation could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which in turn could materially adversely affect our results of operations and financial position. Further, the discharges of natural gas, NGLs, oil, and other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties.

Regulations related to the protection of wildlife could adversely affect our ability to conduct drilling activities in some of the areas where we operate.

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

Fuel conservation measures, consumer tastes and technological advances could reduce demand for natural gas and oil.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to natural gas and oil, technological advances in fuel economy and energy generation devices could reduce demand for natural gas and oil. The impact of the changing demand for natural gas and oil could adversely impact our earnings, cash flows and financial position.

Risks Associated with Strategic Transactions

Entering into strategic transactions may expose us to various risks.

We periodically engage in acquisitions, dispositions and other strategic transactions, including joint ventures. These transactions involve various inherent risks, such as our ability to obtain the necessary regulatory and third-party approvals; the timing of and conditions imposed upon us by regulators in connection with such approvals; the assumption of potential environmental or other liabilities; and our ability to realize the benefits expected from the transactions. In addition, various factors, including prevailing market conditions, could negatively impact the benefits we receive from these transactions. Competition for transaction opportunities in our industry is intense and may increase the cost of, or cause us to refrain from, completing transactions. Joint venture arrangements may restrict our operational and corporate flexibility.

Moreover, joint venture arrangements involve various risks and uncertainties, such as committing us to fund operating and/or capital expenditures, the timing and amount of which we may have little or partial control over, and our joint venture partners may not satisfy their obligations to the joint venture. Our inability to complete a transaction or to achieve our strategic or financial goals in any transaction could have significant adverse effects on our earnings, cash flows and financial position.

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Acquisitions may disrupt our current plans or operations and may not be worth what we pay due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities.

Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include estimates of recoverable reserves, exploration potential, future natural gas, NGLs and oil prices, operating costs, production taxes and potential environmental and other liabilities. These assessments are complex and inherently imprecise. Our review of the properties we acquire may not reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well or lease that we acquire, and even when we inspect a well or lease we may not discover structural, subsurface, or environmental problems that may exist or arise.

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

If there is a later determination that our spin-off of Equitrans Midstream or certain related transactions are taxable for U.S. federal income tax purposes because the facts, assumptions, representations or undertakings underlying the IRS private letter ruling and/or opinion of counsel are incorrect or for any other reason, significant liabilities could be incurred by us, our shareholders or Equitrans Midstream.

In connection with our 2018 spin-off of Equitrans Midstream as a separate, publicly-traded company, we obtained a private letter ruling from the IRS and an opinion of outside counsel regarding the qualification of the Distribution (defined and discussed in Note 9 to the Consolidated Financial Statements), together with certain related transactions, as a transaction that is generally tax-free, for U.S. federal income tax purposes, under Sections 355 and 368(a)(1)(D) of the U.S. Internal Revenue Code, as amended, and certain other U.S. federal income tax matters relating to the Distribution and certain related transactions. The IRS private letter ruling and the opinion of counsel are based on and rely on, among other things, various facts and assumptions, as well as certain representations, statements and undertakings of us and Equitrans Midstream, including those relating to the past and future conduct of us and Equitrans Midstream. If any of these representations, statements or undertakings is, or becomes, inaccurate or incomplete, or if we or Equitrans Midstream breach any representations or covenants contained in any of the spin-off-related agreements and documents or in any documents relating to the IRS private letter ruling and/or the opinion of counsel, we and our shareholders may not be able to rely on the IRS private letter ruling or the opinion of counsel.

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

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We are a significant shareholder of Equitrans Midstream and the value of our investment in Equitrans Midstream may fluctuate substantially.

Following the spin-off of Equitrans Midstream, we retained approximately 19.9% of the outstanding shares of Equitrans Midstream's common stock. On February 26, 2020, we entered into share purchase agreements with Equitrans Midstream to sell approximately 50% of our equity interest in Equitrans Midstream to Equitrans Midstream (the Equitrans Share Exchange) in exchange for a combination of cash and fee relief under our gathering agreements with EQM. We subsequently sold additional shares of our retained interest in Equitrans Midstream through open market sales and we currently own 22,796,026 shares of Equitrans Midstream's common stock. The value of our investment in Equitrans Midstream may be adversely affected by negative changes in its results of operations, cash flows and financial position, which may occur as a result of the many risks attendant with operating in the midstream industry, including loss of gathering and transportation volume, the effect of laws and regulations on the operation of its business and development of its assets, increased competition, loss of contracted volume, adverse rate-making decisions, policies and rulings by the FERC, pipeline safety rulemakings initiated or finalized by the Department of Transportation's Pipeline and Hazardous Materials Safety Administration, delays in the timing of, or the failure to complete, expansion projects, lack of access to capital and operating risks and hazards.

We intend to dispose of our remaining interest in Equitrans Midstream through one or more divestitures of our shares of Equitrans Midstream's common stock. However, we can offer no assurance that we will be able to complete such disposition or as to the value we will realize. The occurrence of any of these and other risks faced by Equitrans Midstream could adversely affect the value of our investment in Equitrans Midstream.

See Item 7A., "Quantitative and Qualitative Disclosures About Market Risk" for further discussion of our exposure to market risks, including the risks associated with our use of derivative contracts to hedge commodity prices.

Item 1B.    Unresolved Staff Comments

None.

Item 2.        Properties

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

Item 3.        Legal Proceedings

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

Environmental Proceedings

Produced Water Release, Washington County, Pennsylvania. In December 2021, we discovered a produced water leak associated with a Gas Processing Unit (GPU) disposal line at one of our well pad sites located in Washington County, Pennsylvania. We self-reported the release to the PADEP spill hotline on December 4, 2021 and initiated cleanup of the released produced water. The initial release was determined to be in excess of one barrel and we entered the remediation project into PADEP's Land Recycling and Environmental Remediation Act 2 Program (Act 2) for voluntary cleanup. In January 2022, we determined the release was larger than initially discovered and we disclosed this information to PADEP on January 14, 2022. Site characterization of the release is ongoing and upon completion, we intend to initiate the remediation according to PADEP's Act 2 guidelines. While we anticipate that the penalties related to this matter will exceed $300,000, we expect that the resolution of this matter will not have a material impact on our financial condition, results of operations or liquidity.

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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 motions are pending.

Item 4.        Mine Safety Disclosures

Not Applicable.

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Information about our Executive Officers (as of February 10, 2022)

Name and Age	Current Title (Year Initially Elected an Executive Officer)	Business Experience
Tony Duran (43)	Chief Information Officer (2019)	Mr. Duran was appointed as the Chief Information Officer of EQT Corporation in July 2019. Prior to joining EQT Corporation, Mr. Duran ran PH6 Labs, a technology incubator he founded, from December 2017 to July 2019. Prior to that, he served as the Chief Information Officer of Rice Energy Inc. (independent natural gas and oil company acquired by EQT Corporation in November 2017) from January 2016 to November 2017; and as the Interim Chief Information Officer of Express Energy Services (oilfield services company for well construction and well testing services) from September 2015 to December 2015. Additionally, Mr. Duran held various positions at National Oilwell Varco (multinational corporation that provides equipment and components used in oil and gas drilling and production operations, oilfield services, and supply chain integration services to the upstream oil and gas industry) from May 2002 to August 2015, where he last held the role of Assistant Chief Information Officer.
Lesley Evancho (44)	Chief Human Resources Officer (2019)	Ms. Evancho was appointed as the Chief Human Resources Officer of EQT Corporation in July 2019. Prior to joining EQT Corporation, Ms. Evancho served as Vice President, Global Talent Management at Westinghouse Electric Company, LLC (nuclear power, fuel and services company) from April 2019 to July 2019; Senior Director, Human Resources at Thermo Fisher Scientific, Inc. (biotechnology product development company) from August 2018 to March 2019; Vice President, Human Resources at Edward Marc Brands (food services company) from March 2018 to August 2018; and Vice President, Human Resources at Rice Energy Inc. from April 2017 to November 2017. Additionally, Ms. Evancho served as Global Director, Talent Management at MSA Safety, Inc. (manufacturer of industrial safety equipment) from November 2011 to April 2017.
Todd M. James (39)	Chief Accounting Officer (2019)	Mr. James was appointed as the Chief Accounting Officer of EQT Corporation in November 2019. Prior to joining EQT Corporation, Mr. James served as the Corporate Controller and Chief Accounting Officer of L.B. Foster Company (manufacturer and distributor of products and services for transportation and energy infrastructure) from April 2018 to October 2019. Prior to that he served as the Senior Director, Technical Accounting and Financial Reporting at Rice Energy Inc. from December 2014 through its acquisition by EQT Corporation in November 2017 and until February 2018. Prior to joining Rice Energy, Mr. James was a Senior Manager, Assurance at PricewaterhouseCoopers LLP (public accounting firm), where he worked from August 2005 to November 2014.
William E. Jordan (41)	Executive Vice President, General Counsel and Corporate Secretary (2019)	Mr. Jordan was appointed as the Executive Vice President and General Counsel of EQT Corporation in July 2019 and assumed the role of Corporate Secretary in November 2020. Mr. Jordan served as an advisor to the Rice Investment Group (multi-strategy investment fund investing in all verticals of the oil and gas sectors) from May 2018 until July 2019. Prior to that, he served as the Senior Vice President, General Counsel and Corporate Secretary of Rice Energy Inc. and Senior Vice President, General Counsel and Corporate Secretary of Rice Midstream Partners LP (former midstream services affiliate of Rice Energy Inc.), in each case from January 2014 until their acquisition by EQT Corporation in November 2017. From September 2005 to December 2013, Mr. Jordan was an associate at Vinson & Elkins LLP (an international law firm) representing public and private companies in capital markets offerings and mergers and acquisitions, primarily in the oil and natural gas industry.
David M. Khani (58)	Chief Financial Officer (2020)	Mr. Khani was appointed as the Chief Financial Officer of EQT Corporation in January 2020. Prior to joining EQT Corporation, Mr. Khani served as the Executive Vice President and Chief Financial Officer of CONSOL Energy (energy company primarily focused on developing coal interests), from March 2013 to December 2019; and as Vice President, Finance at CONSOL Energy from September 2011 to March 2013. In addition, Mr. Khani served as Chief Financial Officer and as a member of the Board of Directors of CONE Midstream LLC (midstream services affiliate of CONSOL Energy) from September 2014 to January 2018; as a member of the Board of Directors of CNX Coal Resources (coal mining affiliate of CONSOL Energy) from July 2015 to August 2017; and as Chief Financial Officer and as a member of the Board of Directors of CONSOL Coal Resources (coal mining affiliate of CONSOL Energy) from August 2017 to December 2019.
Toby Z. Rice (40)	President and Chief Executive Officer (2019)	Mr. Rice was appointed as President and Chief Executive Officer of EQT Corporation in July 2019, when he also was elected to EQT Corporation's Board of Directors. Mr. Rice has served as a Partner at the Rice Investment Group, a multi-strategy fund investing in all verticals of the oil and gas sector, since May 2018. From October 2014 until its acquisition by EQT Corporation in November 2017, Mr. Rice was President and Chief Operating Officer of Rice Energy Inc. and served on the Board of Directors of Rice Energy Inc. from October 2013 to November 2017. Prior to that, he served in a number of positions with Rice Energy, its affiliates and predecessor entities beginning in February 2007, including as President and Chief Executive Officer of a predecessor entity from February 2008 through September 2013. Mr. Rice is the brother of Daniel J. Rice IV, a member of EQT Corporation's Board of Directors since November 2017.

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.

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PART II

Item 5.        Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

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

As of February 4, 2022, there were 1,927 shareholders of record of our common stock.

On February 3, 2022, our Board of Directors declared a quarterly cash dividend of $0.125 per share, payable on March 1, 2022, to shareholders of record at the close of business on February 14, 2022.

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

The following table sets forth our repurchases of equity securities registered under Section 12 of the Exchange Act that have occurred during the three months ended December 31, 2021.

	Total number of shares purchased	Average price paid per share (a)		Total number of shares purchased as part of publicly announced plans or programs (b)	Approximate dollar value of shares that may yet be purchased under plans or programs
October 1, 2021 – October 31, 2021	—	—		—	—
November 1, 2021 – November 30, 2021	—	—		—	—
December 1, 2021 – December 31, 2021	1,361,668	$	21.56	1,361,668	$	970,641,996
Total	1,361,668			1,361,668

 

(a)Excludes any fees, commissions or other expenses associated with the share repurchases.

(b)On December 13, 2021, we announced that our Board of Directors approved a share repurchase program to repurchase shares of our outstanding common stock for an aggregate purchase price up to $1 billion, excluding fees, commissions and expenses. Pursuant to the share repurchase authority, we may repurchase shares from time to time in open market or in privately negotiated transactions. The share repurchase authority does not obligate us to acquire any specific number of shares, was effective immediately and is valid through December 31, 2023. As of December 31, 2021, we had purchased shares for an aggregate purchase price of $29.4 million, excluding fees, commissions and expenses, under this authorization since its inception. The total number of shares purchased and the approximate dollar value of shares that may yet be purchased under our repurchase authority reported reflect shares purchased in December 2021 (based on the trade date) that did not settle until January 2022.

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 S&P 500 Index, the S&P MidCap 400 Index and two customized peer groups, the 2020 Self-Constructed Peer Group and 2021 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 (defined and discussed in Note 9 to the Consolidated Financial Statements) 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, 2016 and its relative performance is tracked through December 31, 2021. 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.

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*$100 invested on 12/31/16 in stock, index, or peer group, including reinvestment of dividends.

Copyright© 2022 Standard & Poor's, a division of S&P Global. All right reserved.

	12/16		12/17		12/18		12/19		12/20		12/21
EQT Corporation	$	100.00	$	87.43	$	53.52	$	31.14	$	36.51	$	62.65
S&P 500 Index	100.00		121.83		116.49		153.17		181.35		233.41
S&P MidCap 400 Index	100.00		116.24		103.36		130.44		148.26		184.96
2020 Self-Constructed Peer Group (a)	100.00		83.12		56.33		39.36		41.95		71.12
2021 Self-Constructed Peer Group (b)	100.00		88.70		56.49		50.76		34.79		77.19

(a)The 2020 Self-Constructed Peer Group includes the following eight companies: Antero Resources Corp., Chesapeake Energy Corp., CNX Resources Corp., Comstock Resources, Inc., Coterra Energy Inc. (formerly Cabot Oil & Gas Corp.), 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 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.

(b)The 2021 Self-Constructed Peer Group includes the following eleven companies: Antero Resources Corp., Apache Corp., CNX Resources Corp., Comstock Resources, Inc., Continental Resources, Inc., Coterra Energy Inc., Devon Energy Corp., Murphy Oil Corp., Ovintiv Inc., Range Resources Corp. and Southwestern Energy Co. The 2021 Self-Constructed Peer Group is comprised of the companies included in our 2021 performance peer group (with the exception of Cimarex Energy Co., which was excluded for purposes of the stock performance graph because it was acquired by Cabot Oil & Gas Corp. in October 2021 thereby forming Coterra Energy Inc.), as selected by the Management Development and Compensation Committee of the Board of Directors for purposes of evaluating our relative total shareholder return under the 2021 Incentive Performance Share Unit Program.

Item 6.        [Reserved]

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Item 7.        Management's Discussion and Analysis of Financial Condition and Results of Operations

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 attributable to EQT Corporation for 2021 was $1,156 million, $3.58 per diluted share, compared to net loss attributable to EQT Corporation for 2020 of $967 million, $3.71 per diluted share. The change was attributable primarily to the loss on derivatives not designated as hedges, increased depreciation and depletion, increased transportation and processing and the gain on the Equitrans Share Exchange (defined and discussed in Note 5 to the Consolidated Financial Statements) recognized in the first quarter of 2020, partly offset by increased sales of natural gas, NGLs and oil, the income from investments, higher income tax benefit and the gain on sale/exchange of long-lived assets.

Results of operations for 2021 include the results of approximately six months of our operation of assets acquired in the Alta Acquisition, which closed in July 2021, the results of a full year of our operation of assets acquired from Chevron U.S.A. Inc. (the Chevron Acquisition), which closed in November 2020, and nine months of our operation of assets acquired from Reliance Marcellus, LLC (the Reliance Asset Acquisition). See Note 6 to the Consolidated Financial Statements for further discussion of the Alta Acquisition, Chevron Acquisition and Reliance Asset Acquisition.

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, 2020, which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year ended December 31, 2019.

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

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.

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	Years Ended December 31,
	2021		2020
	(Thousands, unless otherwise noted)
NATURAL GAS
Sales volume (MMcf)	1,746,317		1,418,774
NYMEX price ($/MMBtu)	$	3.97	$	2.09
Btu uplift	0.20		0.11
Natural gas price ($/Mcf)	$	4.17	$	2.20
Basis ($/Mcf) (a)	$	(0.63)	$	(0.47)
Cash settled basis swaps not designated as hedges ($/Mcf)	(0.07)		0.05
Average differential, including cash settled basis swaps ($/Mcf)	$	(0.70)	$	(0.42)
Average adjusted price ($/Mcf)	$	3.47	$	1.78
Cash settled derivatives not designated as hedges ($/Mcf)	(1.09)		0.59
Average natural gas price, including cash settled derivatives ($/Mcf)	$	2.38	$	2.37
Natural gas sales, including cash settled derivatives	$	4,153,221	$	3,359,583
LIQUIDS
NGLs, excluding ethane:
Sales volume (MMcfe) (b)	64,202		44,702
Sales volume (Mbbl)	10,700		7,451
Price ($/Bbl)	$	44.50	$	20.51
Cash settled derivatives not designated as hedges ($/Bbl)	(12.32)		(0.12)
Average price, including cash settled derivatives ($/Bbl)	$	32.18	$	20.39
NGLs sales	$	344,260	$	151,877
Ethane:
Sales volume (MMcfe) (b)	37,548		29,489
Sales volume (Mbbl)	6,258		4,914
Price ($/Bbl)	$	8.85	$	3.48
Ethane sales	$	55,393	$	17,085
Oil:
Sales volume (MMcfe) (b)	9,750		4,827
Sales volume (Mbbl)	1,625		804
Price ($/Bbl)	$	56.82	$	25.57
Oil sales	$	92,334	$	20,574
Total liquids sales volume (MMcfe) (b)	111,500		79,018
Total liquids sales volume (Mbbl)	18,583		13,169
Total liquids sales	$	491,987	$	189,536
TOTAL
Total natural gas and liquids sales, including cash settled derivatives (c)	$	4,645,208	$	3,549,119
Total sales volume (MMcfe)	1,857,817		1,497,792
Average realized price ($/Mcfe)	$	2.50	$	2.37

(a)Basis represents the difference between the ultimate sales price for natural gas, including the effects of delivered price benefit or deficit associated with our firm transportation agreements, and the NYMEX natural gas price.

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

(c)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.

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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 consists of the costs of, and recoveries on, pipeline capacity releases, revenues for gathering services provided to third parties and other revenues. 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.

	Years Ended December 31,
	2021		2020
	(Thousands, unless otherwise noted)
Total operating revenues	$	3,064,663	$	3,058,843
Add (deduct):
Loss (gain) on derivatives not designated as hedges	3,775,042		(400,214)
Net cash settlements (paid) received on derivatives not designated as hedges	(2,091,003)		897,190
Premiums (paid) received for derivatives that settled during the period	(67,809)		1,630
Net marketing services and other	(35,685)		(8,330)
Adjusted operating revenues, a non-GAAP financial measure	$	4,645,208	$	3,549,119
Total sales volume (MMcfe)	1,857,817		1,497,792
Average realized price ($/Mcfe)	$	2.50	$	2.37

Sales Volume and Revenues

	Years Ended December 31,
	2021		2020		Change		% Change
	(Thousands, unless otherwise noted)
Sales volume by shale (MMcfe):
Marcellus	1,684,673		1,314,801		369,872		28.1
Ohio Utica	163,775		177,864		(14,089)		(7.9)
Other	9,369		5,127		4,242		82.7
Total sales volume	1,857,817		1,497,792		360,025		24.0
Average daily sales volume (MMcfe/d)	5,090		4,092		998		24.4
Operating revenues:
Sales of natural gas, natural gas liquids and oil	$	6,804,020	$	2,650,299	$	4,153,721	156.7
(Loss) gain on derivatives not designated as hedges	(3,775,042)		400,214		(4,175,256)		(1,043.3)
Net marketing services and other	35,685		8,330		27,355		328.4
Total operating revenues	$	3,064,663	$	3,058,843	$	5,820	0.2

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Sales of natural gas, NGLs and oil. Sales of natural gas, NGLs and oil increased for 2021 compared to 2020 due to increased sales volume and a higher average realized price.

Sales volume increased primarily as a result of sales volume increases of 170 Bcfe from the assets acquired in the Alta Acquisition, sales volume increases of 127 Bcfe from the assets acquired in the Chevron Acquisition, prior year sales volume decreases of 46 Bcfe from the 2020 Strategic Production Curtailments and sales volume increases as a result of the Reliance Asset Acquisition and from wells turned in-line during 2021, partly offset by sales volume decreases 9 Bcfe from the 2020 Divestiture (defined in Note 8 to the Consolidated Financial Statements).

The 2020 Strategic Production Curtailments refers to our strategic decisions to temporarily curtail 2020 production. In May 2020, we temporarily curtailed approximately 1.4 Bcf per day of gross production, equivalent to approximately 1.0 Bcf per day of net production. In July 2020, we began a moderated approach to bring back on-line the curtailed production. In September 2020, we curtailed approximately 0.6 Bcf per day of gross production, equivalent to approximately 0.4 Bcf per day of net production. In October 2020, we began a phased approach to bring back on-line the curtailed production, which was completed in November 2020.

Average realized price increased due to higher NYMEX prices and higher liquids prices, partly offset by lower cash settled derivatives and unfavorable differential. For 2021 and 2020, we paid $2,091.0 million and received $897.2 million, respectively, of net cash settlements on derivatives not designated as hedges, which are included in average realized price but may not be included in operating revenues.

(Loss) gain on derivatives not designated as hedges. For 2021 and 2020, we recognized a loss of $3,775.0 million and a gain of $400.2 million, respectively, on derivatives not designated as hedges. The loss for 2021 was related primarily to decreases in the fair market value of our NYMEX swaps and options due to increases in NYMEX forward prices. The gain for 2020 was related primarily to increases in the fair market value of our NYMEX swaps and options due to decreases in NYMEX forward prices.

Net marketing services and other. Net marketing services and other increased for 2021 compared to 2020 due primarily to the liquids uplift realized on gas purchased at the wellhead from other operators and third-party gathering revenues recognized on the midstream assets acquired in the Alta Acquisition.

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Operating Expenses

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

	Years Ended December 31,
	2021		2020		Change		% Change
	(Thousands, unless otherwise noted)
Operating expenses:
Gathering	$	1,228,153	$	1,068,590	$	159,563	14.9
Transmission	525,811		506,668		19,143		3.8
Processing	188,201		135,476		52,725		38.9
Lease operating expenses (LOE)	126,640		109,027		17,613		16.2
Production taxes	98,639		46,376		52,263		112.7
Exploration	24,403		5,484		18,919		345.0
Selling, general and administrative	196,315		174,769		21,546		12.3
Production depletion	$	1,658,113	$	1,375,542	$	282,571	20.5
Other depreciation and depletion	18,589		17,923		666		3.7
Total depreciation and depletion	$	1,676,702	$	1,393,465	$	283,237	20.3
Per Unit ($/Mcfe):
Gathering	$	0.66	$	0.71	$	(0.05)	(7.0)
Transmission	0.28		0.34		(0.06)		(17.6)
Processing	0.10		0.09		0.01		11.1
LOE	0.07		0.07		—		—
Production taxes	0.05		0.03		0.02		66.7
Exploration	0.01		—		0.01		100.0
Selling, general and administrative	0.11		0.12		(0.01)		(8.3)
Production depletion	0.89		0.92		(0.03)		(3.3)

Gathering. Gathering expense increased on an absolute basis for 2021 compared to 2020 due to increased sales volume. Gathering expense decreased on a per Mcfe basis for 2021 compared to 2020 due primarily to the lower gathering rate structures on the assets acquired in the Chevron Acquisition and Alta Acquisition and increased sales volume, which resulted in our utilization of lower overrun rates as part of the Consolidated GGA (defined and discussed in Note 5 to the Consolidated Financial Statements).

Transmission. Transmission expense increased on an absolute basis for 2021 compared to 2020 due primarily to additional capacity acquired as part of the Alta Acquisition. Transmission expense decreased on a per Mcfe basis for 2021 compared to 2020 due primarily to increased sales volume from the Chevron Acquisition and Alta Acquisition, which have a lower average transmission expense per Mcfe when compared to our historical transmission portfolio.

Processing. Processing expense increased on an absolute and per Mcfe basis for 2021 compared to 2020 due to increased liquid sales volume as a result of increased development of liquids-rich areas and increased processed volume from the Chevron Acquisition.

LOE. LOE increased on an absolute basis for 2021 compared to 2020 due primarily to additional lease operating costs as a result of the Alta Acquisition and Chevron Acquisition.

Production taxes. Production taxes increased on an absolute and per Mcfe basis for 2021 compared to 2020 due to increased West Virginia severance taxes, which resulted primarily from higher prices, and increased Pennsylvania impact fees, which resulted from higher prices and additional wells acquired in the Alta Acquisition and Chevron Acquisition.

Exploration. Exploration expense increased on an absolute and per Mcfe basis for 2021 compared to 2020 due primarily to our purchase of seismic data following the completion of the Alta Acquisition.

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Selling, general and administrative. Selling, general and administrative expense increased on an absolute basis for 2021 compared to 2020 due primarily to higher long-term incentive compensation costs as a result of changes in the fair value of awards as well as higher litigation expense. Selling, general and administrative expense decreased on a per Mcfe basis for 2021 compared to 2020 due primarily to increased sales volumes and nominal incremental selling, general and administrative spend with respect to the Alta Acquisition and Chevron Acquisition.

Depreciation and depletion. Production depletion expense increased on an absolute basis for 2021 compared to 2020 due to increased sales volume, partly offset by a lower annual depletion rate. Production depletion expense decreased on a per Mcfe basis for 2021 compared to 2020 due to a lower annual depletion rate.

Amortization of intangible assets. Amortization of intangible assets for 2020 was $26.0 million. Our intangible assets were fully amortized in November 2020.

(Gain) loss/impairment on sale/exchange of long-lived assets. During 2021, we recognized a gain on sale/exchange of long-lived assets of $21.1 million related primarily to changes in the fair value of the Contingent Consideration (defined and discussed in Note 8 to the Consolidated Financial Statements) from the 2020 Divestiture. 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 7 to the Consolidated Financial Statements) and $39.1 million related to asset sales, including the 2020 Divestiture.

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 of our non-operating receivables as a result of expected credit losses.

Impairment and expiration of leases. During 2021 and 2020 we recognized impairment and expiration of leases of $311.8 million and $306.7 million, respectively, related to impairment and expiration of leases that we no longer expect to develop based on our development strategy.

Other operating expenses. Other operating expenses for 2021 of $70.1 million were attributable primarily to transaction costs associated with the Alta Acquisition and Chevron Acquisition. Other operating expenses for 2020 of $28.5 million were attributable primarily to transactions, changes in legal reserves, including settlements, and reorganization. See Note 1 to the Consolidated Financial Statements for a summary of other operating expenses.

Other Income Statement Items

Gain on Equitrans Share Exchange. During the first quarter of 2020, we recognized a gain on the Equitrans Share Exchange of $187.2 million. See Note 5 to the Consolidated Financial Statements.

(Income) loss from investments. For 2021, we recognized income on our investments in Equitrans Midstream and Laurel Mountain Midstream (see Note 6 to the Consolidated Financial Statements). Our investment in Equitrans Midstream fluctuates with changes in Equitrans Midstream's stock price, which was $10.34 and $8.04 as of December 31, 2021 and 2020, respectively. For 2020, we recognized a loss on our investment in Equitrans Midstream due to a decrease in Equitrans Midstream's stock price.

Dividend and other income. Dividend and other income decreased for 2021 compared to 2020 due primarily to lower dividends received from our investment in Equitrans Midstream driven by a decrease in the number of shares of Equitrans Midstream's common stock that we owned as well as a decrease in the dividend amount per share.

Loss on debt extinguishment. During 2021, we recognized a loss on debt extinguishment of $9.8 million due to fees incurred for a bridge-loan commitment related to the Alta Acquisition and the repayment of our 4.875% senior notes. During 2020, we recognized a loss on debt extinguishment of $25.4 million 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. See Note 10 to the Consolidated Financial Statements.

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Interest expense. Interest expense increased for 2021 compared to 2020 due to increased interest incurred on new debt related to the Chevron Acquisition and Alta Acquisition, increased amortization expense due primarily to our convertible debt and higher periodic borrowings under our credit facility. See Note 10 to the Consolidated Financial Statements.

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, 2021 were $23.8 billion, composed of $1.7 billion in 2022, $1.8 billion in 2023, $1.8 billion in 2024, $1.8 billion in 2025, $1.7 billion in 2026 and $15.0 billion thereafter (primarily in 2027 through 2042).

In addition, we have commitments to pay for services and materials related to our operations, which primarily include minimum volume commitments to obtain water services and electric hydraulic fracturing services and commitments to purchase equipment, materials and sand. As of December 31, 2021, future commitments under these contracts were $135.6 million in 2022, $99.0 million in 2023, $47.5 million in 2024, $40.0 million in 2025, $40.0 million in 2026 and $178.3 million thereafter.

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 of the contractual commitments under our debt agreements, including the timing of principal repayments.

Unrecognized Tax Benefits. As discussed further in Note 9 to the Consolidated Financial Statements, as of December 31, 2021, we had a total reserve for unrecognized tax benefits of $94.1 million and an additional reserve of $97.2 million that was 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.

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Planned Capital Expenditures and Sales Volume. In 2022, we expect to spend approximately $1.30 to $1.45 billion in total capital expenditures, excluding amounts attributable to noncontrolling interest. We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our credit facility. 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 2022 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. Sales volume in 2022 is expected to be 1,950 to 2,050 Bcfe.

Operating Activities

Net cash provided by operating activities was $1,662 million for 2021 compared to $1,538 million for 2020. The increase was due primarily to higher cash operating revenues, partly offset by the cash settlements paid on derivatives not designated as hedges, higher cash operating expenses and income tax refunds received in the prior year.

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 $2,073 million for 2021 compared to $1,556 million for 2020. The increase was due primarily to higher cash paid for acquisitions and proceeds from the sale of assets in 2020.

The following table summarizes our capital expenditures.

	Years Ended December 31,
	2021		2020
	(Millions)
Reserve development	$	828	$	839
Land and lease (a)	144		121
Capitalized overhead	58		51
Capitalized interest	18		17
Other production infrastructure	47		40
Other corporate items	9		11
Total capital expenditures	1,104		1,079
Deduct: Non-cash items (b)	(49)		(37)
Total cash capital expenditures	$	1,055	$	1,042

(a)Capital expenditures attributable to noncontrolling interest were $9.6 million and $4.9 million for the years ended December 31, 2021 and 2020, respectively.

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

Financing Activities

Net cash provided by financing activities was $506 million for 2021 compared to $32 million for 2020. For 2021, the primary source of financing cash flows was proceeds from the issuance of debt, and the primary uses of financing cash flows were net credit facility borrowings and repayment and retirement of debt. For 2020, the primary source of financing cash flows was proceeds from the issuance of debt and equity, and the primary use of financing cash flows was repayment and retirement of debt. See Note 10 to the Consolidated Financial Statements for further discussion of our debt.

On February 3, 2022, our Board of Directors declared a quarterly cash dividend of $0.125 per share, payable on March 1, 2022, to shareholders of record at the close of business on February 14, 2022.

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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, 2020, which is incorporated herein by reference, for discussion and analysis of operating, investing and financing activities for the year ended December 31, 2019.

Security Ratings and Financing Triggers

The table below reflects the credit ratings and rating outlooks assigned to our debt instruments at February 4, 2022. 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 a description of what is deemed investment grade.

Rating agency	Senior notes	Outlook
Moody's Investors Service (Moody's)	Ba1	Stable
Standard & Poor's Ratings Service (S&P)	BB+	Positive
Fitch Ratings Service (Fitch)	BB+	Stable

Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our lines of credit, the interest rate on our senior notes with adjustable rates, the rates available on new long-term debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts. 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 our hedging counterparties.

As of February 4, 2022, 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 4, 2022, such assurances could be up to approximately $1.1 billion, inclusive of letters of credit, OTC derivative instrument margin deposits and other collateral posted of approximately $0.8 billion in the aggregate.

During the third quarter of 2021, we amended agreements with six of our largest OTC hedge counterparties to permanently or temporarily reduce or eliminate our margin posting obligations associated with our OTC derivative instruments with such OTC hedge counterparties. The purpose of such amendments was to mitigate the amount of cash collateral that we would otherwise have been required to post based on current NYMEX strip pricing. As of February 4, 2022, our margin balance on our existing hedge portfolio, including both OTC and broker margin balances, was approximately $0.3 billion, compared to approximately $0.1 billion as of December 31, 2020, despite a significant increase in natural gas prices. 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 loss. As of December 31, 2021, we were in compliance with all debt provisions and covenants under our debt agreements.

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

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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 following table summarizes the approximate volume and prices of our NYMEX hedge positions through 2024 as of February 4, 2022.

	Q1 2022 (a)		Q2 2022		Q3 2022		Q4 2022		2023		2024
Hedged Volume (MMDth)	355		329		287		287		858		16
Hedged Volume (MMDth/d)	3.9		3.6		3.1		3.1		2.4		—
Swaps (includes Futures)
Volume (MMDth)	289		296		254		232		166		2
Avg. Price ($/Dth)	$	2.78	$	2.63	$	2.41	$	2.36	$	2.53	$	2.67
Calls - Net Short
Volume (MMDth)	57		101		102		102		606		15
Avg. Short Strike ($/Dth)	$	3.26	$	3.00	$	3.00	$	3.00	$	4.38	$	3.11
Puts - Net Long
Volume (MMDth)	65		32		32		54		689		15
Avg. Long Strike ($/Dth)	$	2.68	$	2.68	$	2.68	$	2.68	$	2.90	$	2.45
Fixed Price Sales (b)
Volume (MMDth)	1		1		1		1		3		—
Avg. Price ($/Dth)	$	2.38	$	2.38	$	2.38	$	2.38	$	2.38	$	—

(a)January 1 through March 31.

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

For 2022, 2023 and 2024, we have natural gas sales agreements for approximately 18 MMDth, 88 MMDth and 11 MMDth, respectively, that include average NYMEX ceiling prices of $3.17, $2.84 and $3.21, respectively.

During the third and fourth quarters of 2021, we purchased $67 million of net winter calls to reposition our 2021 and 2022 hedge portfolio to enable incremental upside participation in rising natural gas prices and to further mitigate potential incremental margin posting requirements. As of December 31, 2021, the remaining positions cover approximately 45 net MMDth in the first quarter of 2022 and have been excluded from the table above.

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.

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.

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