EQT (EQT) 10-K risk factor changes: FY2021 vs FY2020

If any of the events or circumstances described below actually [removed: occurs,] [added: occur,] our business, financial condition or results of operations could suffer and the trading price of our common stock could decline.

Our future financial position, cash flows and results of operations [removed: will] depend on the success of our development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable natural gas production or that we will not recover all or any portion of our investment in drilled wells.

- delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from permitting, wastewater disposal, discharge of [removed: greenhouse gases,] [added: GHGs,] and limitations on hydraulic fracturing;

- shortages of or delays in obtaining equipment, rigs, [removed: materials and] [added: materials,] qualified personnel or [removed: in obtaining] water [removed: for] [added: (for] hydraulic fracturing [removed: activities;][added: activities);]

- lack of available gathering and water facilities or delays in [added: the] construction of gathering and water facilities;

- adverse weather conditions, such as flooding, droughts, freeze-offs, [removed: slips,] [added: landslides,] blizzards and ice storms;

- title, surface access, coal mining and right of way [removed: problems;] [added: issues;] and

In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, [removed: the] [added: our] leases for such acreage will expire.

[added: If] we cannot preserve a lease, the lease terminates.

Approximately [removed: 16%] [added: 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 [removed: plans,] [added: 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, [removed: trade,] [added: trade] or sell our leases prior to their [removed: expiration] [added: expiration,] resulting in the termination [removed: and] [added: or] impairment of leases for properties that we have not developed.

Indicators of potential impairment include changes brought about by economic factors, potential shifts in [added: our] business strategy [removed: employed by management] and historical experience.

For the years ended December 31, [removed: 2020, 2019] [added: 2021, 2020] and [removed: 2018,] [added: 2019,] we recorded [removed: lease impairments] [added: impairment] and [removed: expirations] [added: expiration] of [removed: $306.7] [added: leases of $311.8] million, [removed: $556.4] [added: $306.7] million and [removed: $279.7] [added: $556.4] million, respectively.

Additionally, a failure to effectively and efficiently operate existing wells may cause production [removed: volumes] [added: 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, [removed: government] [added: 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 [added: that] do not produce sufficient revenues to return a profit.

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 [removed: the] future net cash flows.

Although we believe our estimates are reasonable, actual production, revenues and costs to develop reserves will likely vary from [added: our] estimates and these variances could be material.

[removed: Our] [added: Consequently, our] revenue, profitability, future rate of growth, liquidity and financial position depend upon the [added: market] prices for natural gas and, to a lesser extent, NGLs and oil.

- the price, availability and [removed: acceptance of] [added: consumer demand for] alternative fuels;

The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of [removed: $3.14] [added: $23.86] per MMBtu to a low of [removed: $1.33] [added: $2.43] per MMBtu from January 1, [removed: 2020] [added: 2021] through December 31, [removed: 2020,] [added: 2021,] and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of [removed: $63.27] [added: $85.64] per barrel to a low of [removed: $(36.98)] [added: $47.47] per barrel during the same period.

In addition, the market price for natural gas in the Appalachian Basin [removed: continues to be] [added: is typically] lower relative to NYMEX Henry Hub as a result of [removed: significant increases in] the [added: increased production and] supply of natural gas in the Northeast United States.

Because our production and reserves predominantly consist of natural gas (approximately [removed: 93%] [added: 94%] of [added: our] equivalent proved developed reserves), changes in natural gas prices have significantly greater impact on our financial results than oil prices.

Reductions in cash flows from lower commodity prices may require us to incur additional [removed: borrowings] [added: debt] or [removed: to] reduce our capital spending, which could reduce our production and our reserves, negatively affecting our future rate of growth.

[removed: See "Impairment of Oil and Gas Properties" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations."] 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.

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 [added: or letters of credit] with our hedge [removed: counterparties.][added: counterparties and would negatively impact our liquidity.]

If we are not able to successfully execute our [removed: Deleveraging] [added: Debt Reduction] Plan or otherwise reduce our [removed: absolute] [added: 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 [added: shareholder returns strategy or other] strategic plans.

The issuance of additional indebtedness would require that a portion of our cash [removed: flow] [added: flows] from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash [removed: flow] [added: flows] from operations to fund working capital, capital expenditures and acquisitions.

Our cash [removed: flow] [added: flows] from operations and access to capital are subject to a number of variables, including:

As of December 31, [removed: 2020,] [added: 2021,] our senior notes were rated [removed: "Ba3"] [added: "Ba1"] with a [removed: "positive"] [added: "stable"] outlook by Moody's Investors Services (Moody's), [removed: "BB"] [added: "BB+"] with a [removed: "stable"] [added: "positive"] outlook by Standard & Poor's Ratings Service (S&P) and [removed: "BB"] [added: "BB+"] with a [removed: "positive"] [added: "stable"] outlook by Fitch Ratings Service (Fitch).

Low prices for natural gas, NGLs and oil, an increase in the level of our indebtedness or [removed: a failure to significantly execute our Deleveraging Plan] [added: other factors] may result in Moody's, S&P or Fitch downgrading its rating of our senior notes.

As of December 31, [removed: 2020,] [added: 2021,] we had approximately [removed: $4,925 million] [added: $5.5 billion] of debt outstanding, and we may incur additional indebtedness in the future.

These transactions limit our potential gains if natural gas, NGLs and oil prices rise above the price established by the [removed: hedge.][added: 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.]

In addition, derivative transactions may expose us to the risk of financial loss in certain circumstances, including instances in [removed: which:][added: 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.]

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 [removed: Condensed] 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.

We cannot be sure that we will be able to continue to demonstrate the ability or intent to settle [added: the Convertible Notes] in cash or that the accounting standards will continue to permit the use of the treasury stock method.

[added: 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 [added: and new venture] initiatives geared towards enhancing our strategy.

[added: 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, [added: in recent years,] federal and state regulatory agencies [removed: recently] have [removed: focused on a] [added: 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 [removed: volumes] [added: volume] or suspend operations.

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

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.

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.

See "Impairment of Oil and Gas Properties" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations."

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.

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.

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.

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 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.

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.

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.

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.

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.

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.

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.

Summary of Risk Factors

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

- Risks Associated with Natural Gas Drilling Operations. As a natural gas producer, there are risks inherent in our primary business operations.

These risks are not necessarily unique to us, but rather, these are risks that most operators in our industry have at least some exposure to.

- Financial and Market Risks. Given that our primary product and source of revenue is the sale of natural gas and NGLs, one of our most material risks is the commodity market and the price of natural gas and NGLs, which is often volatile.

Additionally, our operations are capital intensive.

Pressures on the market as a whole, or our specific financial

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

- Risks Associated with Our Human Capital, Technology and Other Resources and Service Providers. Our business, and the U.S. energy grid, is predominately operated on a digital system.

Our employees rely on our cloud-based digital work environment to communicate and access data that is necessary to conduct our day-to-day operations.

While these digital systems enable us to efficiently supply our natural gas and NGLs to the market, they are also susceptible to cyber security threats.

Likewise, as a digitally-focused organization, we seek employees with a high degree of both technical skill and digital literacy, and it can be difficult to attract and retain personnel who satisfy these criteria.

Further, we predominately operate in the Appalachia Basin, and a substantial majority of our midstream and water services are provided by one provider, EQM Midstream Partners, LP, making us vulnerable to risks associated with operating primarily in one major geographic area and obtaining a substantial amount of our services from a single provider within that operating area.

- Legal and Regulatory Risks. There are many environmental, energy, financial, real property and other regulations that we are required to comply with in the context of conducting our operations, otherwise, we may be exposed to fines, penalties, investigations, litigation or other legal proceedings.

Additionally, negative public perception of us or the natural gas industry, or increasing consumer demand for alternatives to natural gas, could adversely impact our earnings, cash flows and financial position.

- Risks Associated with Strategic Transactions. We have historically been involved in, and anticipate that we will continue to explore, opportunities to create value through strategic transactions, whether through mergers and acquisitions, divestitures, joint ventures or similar business transactions.

There are risks inherent in any strategic transaction, and such risks could negatively affect the benefits, outcomes and synergies anticipated to be obtained from executing such strategic transactions.

- Risks Related to the COVID-19 Pandemic. While we did not experience any material adverse effects from the COVID-19 pandemic in 2020, the severity, magnitude and duration of the COVID-19 pandemic is still uncertain, rapidly changing and difficult to predict.

We believe that our principal areas of operational risk resulting from a pandemic are availability of service providers and supply chain disruption.

Additionally, active development operations, including drilling and fracking operations, represent the greatest risk for transmission given the number of personnel and contractors on our drilling sites.

We believe that we are following best practices under COVID-19 guidance; however, the potential for transmission still exists, and in certain instances, it may be necessary or determined advisable for us to delay our development operations.

We describe these risks in greater detail below.

If

- the level of global inventories;

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.

In an effort to improve our leverage ratio, in the fourth quarter of 2019, we announced a plan to reduce our absolute debt using free cash flow and targeted proceeds from the monetization of select, non-strategic exploration and production assets, core mineral assets and our remaining retained equity interest in Equitrans Midstream (the Deleveraging Plan).

There can be no

assurance that we will be able to generate sufficient free cash flow or find attractive asset monetization opportunities or that any such transactions will be completed on our anticipated timeframe, if at all, which would delay or inhibit our ability to successfully execute our Deleveraging Plan.

Furthermore, our estimated value for the assets to be monetized under our Deleveraging Plan involves multiple assumptions and judgments about future events that are inherently uncertain; accordingly, there can be no assurance that the resulting net cash proceeds from asset monetization transactions will be as anticipated, even if such transactions are consummated.

Some of the factors that could affect our ability to successfully execute our Deleveraging Plan include changes in the financial condition or prospects of prospective purchasers and the availability of financing to potential purchasers on reasonable terms, the number of prospective purchasers, the number of competing assets on the market, unfavorable economic conditions, industry trends and changes in laws and regulations.

Uncertainty related to the LIBOR calculation process and potential phasing out of LIBOR after 2021 may adversely affect the market value of our current or future debt obligations.

Loans to us under our credit facility may be base rate loans or LIBOR loans.

LIBOR is calculated by reference to a market for interbank lending, and it is based on increasingly fewer actual transactions.

This increases the subjectivity of the LIBOR calculation process and increases the risk of manipulation.

Actions by the regulators or law enforcement agencies, as well as ICE Benchmark Administration (the current administrator of LIBOR), may result in changes to the manner that LIBOR is determined or the establishment of alternative reference rates.

For example, on July 27, 2017, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after 2021.

U.S. Dollar LIBOR will likely be replaced by the Secured Overnight Financing Rate (SOFR) published by the Federal Reserve Bank of New York; however, the timing of this shift is currently unknown.

SOFR is an overnight rate instead of a term rate, making SOFR an inexact replacement for LIBOR, and there is not an established process to create robust, forward-looking, SOFR term rates.

Changing the benchmark rate for LIBOR loans from LIBOR to SOFR requires calculations of a spread.

Net loss [added: attributable to EQT Corporation] for [removed: 2020] [added: 2021] was [removed: $967] [added: $1,156] million, [removed: $3.71] [added: $3.58] per diluted share, [removed: an improvement of $255 million] compared to net loss [added: attributable to EQT Corporation] for [removed: 2019] [added: 2020] of [removed: $1,222] [added: $967] million, [removed: $4.79] [added: $3.71] per diluted share.

See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on [Form [removed: 10-K](http://www.sec.gov/ix?doc=/Archives/edgar/data/33213/000003321320000008/a1231201910k.htm)] [added: 10-K](http://www.sec.gov/ix?doc=/Archives/edgar/data/33213/000003321321000006/eqt-20201231.htm#i43f68b92b00b4f60b7eb2031407a74f6_58)] for the year ended December 31, [removed: 2019,] [added: 2020,] which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year ended December 31, [removed: 2018.][added: 2019.]

See "Sales [removed: Volumes] [added: 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.

| Sales volume (MMcf) | | | [removed: 1,418,774] [added: 1,746,317] | | | | | | [removed: 1,435,134] [added: 1,418,774] | | |

| NYMEX price ($/MMBtu) [removed: (a)] | | | $ | [removed: 2.09] [added: 3.97] | | | | | $ | [removed: 2.63] [added: 2.09] | |

| Btu uplift | | | [removed: 0.11] [added: 0.20] | | | | | | [removed: 0.13] [added: 0.11] | | |

| Natural gas price ($/Mcf) | | | $ | [removed: 2.20] [added: 4.17] | | | | | $ | [removed: 2.76] [added: 2.20] | |

| Basis ($/Mcf) [removed: (b)] [added: (a)] | | | $ | [removed: (0.47)] [added: (0.63)] | | | | | $ | [removed: (0.28)] [added: (0.47)] | |

| Cash settled basis swaps [removed: (not] [added: not] designated as [removed: hedges)] [added: hedges] ($/Mcf) | | | [removed: 0.05] [added: (0.07)] | | | | | | [removed: (0.04)] [added: 0.05] | | |

| Average differential, including cash settled basis swaps ($/Mcf) | | | $ | [removed: (0.42)] [added: (0.70)] | | | | | $ | [removed: (0.32)] [added: (0.42)] | |

| Average adjusted price ($/Mcf) | | | $ | [removed: 1.78] [added: 3.47] | | | | | $ | [removed: 2.44] [added: 1.78] | |

| Cash settled derivatives [removed: (not] [added: not] designated as [removed: hedges)] [added: hedges] ($/Mcf) | | | [removed: 0.59] [added: (1.09)] | | | | | | [removed: 0.21] [added: 0.59] | | |

| Average natural gas price, including cash settled derivatives ($/Mcf) | | | $ | [removed: 2.37] [added: 2.38] | | | | | $ | [removed: 2.65] [added: 2.37] | |

| Natural gas sales, including cash settled derivatives | | | $ | [removed: 3,359,583] [added: 4,153,221] | | | | | $ | [removed: 3,805,977] [added: 3,359,583] | |

| [removed: Natural gas liquids (NGLs),] [added: NGLs,] excluding ethane: | | | | | | | | | | | |

| Sales volume (MMcfe) [removed: (c)] [added: (b)] | | | [removed: 44,702] [added: 64,202] | | | | | | [removed: 44,082] [added: 44,702] | | |

| Sales volume (Mbbl) | | | [removed: 7,451] [added: 10,700] | | | | | | [removed: 7,348] [added: 7,451] | | |

| Price ($/Bbl) | | | $ | [removed: 20.51] [added: 44.50] | | | | | $ | [removed: 23.63] [added: 20.51] | |

| Cash settled derivatives [removed: (not] [added: not] designated as [removed: hedges)] [added: hedges] ($/Bbl) | | | [removed: (0.12)] [added: (12.32)] | | | | | | [removed: 2.19] [added: (0.12)] | | |

| Average [removed: NGLs] price, including cash settled derivatives ($/Bbl) | | | $ | [removed: 20.39] [added: 32.18] | | | | | $ | [removed: 25.82] [added: 20.39] | |

| NGLs sales | | | $ | [removed: 151,877] [added: 344,260] | | | | | $ | [removed: 189,718] [added: 151,877] | |

| Sales volume (MMcfe) [removed: (c)] [added: (b)] | | | [removed: 29,489] [added: 37,548] | | | | | | [removed: 23,748] [added: 29,489] | | |

| Sales volume (Mbbl) | | | [removed: 4,914] [added: 6,258] | | | | | | [removed: 3,957] [added: 4,914] | | |

| Price ($/Bbl) | | | $ | [removed: 3.48] [added: 8.85] | | | | | $ | [removed: 6.16] [added: 3.48] | |

| Ethane sales | | | $ | [removed: 17,085] [added: 55,393] | | | | | $ | [removed: 28,414] [added: 17,085] | |

| Sales volume (MMcfe) [removed: (c)] [added: (b)] | | | [removed: 4,827] [added: 9,750] | | | | | | [removed: 4,932] [added: 4,827] | | |

| Sales volume (Mbbl) | | | [removed: 804] [added: 1,625] | | | | | | [removed: 822] [added: 804] | | |

| Price ($/Bbl) | | | $ | [removed: 25.57] [added: 56.82] | | | | | $ | [removed: 40.90] [added: 25.57] | |

| Oil sales | | | $ | [removed: 20,574] [added: 92,334] | | | | | $ | [removed: 33,620] [added: 20,574] | |

| Total liquids sales volume (MMcfe) [removed: (c)] [added: (b)] | | | [removed: 79,018] [added: 111,500] | | | | | | [removed: 72,762] [added: 79,018] | | |

| Total liquids sales volume (Mbbl) | | | [removed: 13,169] [added: 18,583] | | | | | | [removed: 12,127] [added: 13,169] | | |

| Total liquids sales | | | $ | [removed: 189,536] [added: 491,987] | | | | | $ | [removed: 251,752] [added: 189,536] | |

| Total natural gas and liquids sales, including cash settled derivatives [removed: (d)] [added: (c)] | | | $ | [removed: 3,549,119] [added: 4,645,208] | | | | | $ | [removed: 4,057,729] [added: 3,549,119] | |

| Total sales volume (MMcfe) | | | [removed: 1,497,792] [added: 1,857,817] | | | | | | [removed: 1,507,896] [added: 1,497,792] | | |

| Average realized price ($/Mcfe) | | | $ | [removed: 2.37] [added: 2.50] | | | | | $ | [removed: 2.69] [added: 2.37] | |

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

[removed: (d)Total] [added: (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.

Net marketing services and other [removed: primarily includes] [added: consists of] the costs of, and recoveries on, pipeline capacity [removed: releases.][added: releases, revenues for gathering services provided to third parties and other revenues.]

| Total operating revenues | | | $ | [removed: 3,058,843] [added: 3,064,663] | | | | | $ | [removed: 4,416,484] [added: 3,058,843] | |

| [removed: Gain] [added: Loss (gain)] on derivatives not designated as hedges | | | [removed: (400,214)] [added: 3,775,042] | | | | | | [removed: (616,634)] [added: (400,214)] | | |

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.

| | | | 2021 | | | | | | 2020 | | |

| | | | 2021 | | | | | | 2020 | | |

| | | | | | | | | | | | |

| Average realized price ($/Mcfe) | | | $ | 2.50 | | | | | $ | 2.37 | |

| | | | | | | | | | | | | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | 2021 | | | | | | 2020 | | | | | | Change | | | | | | % Change | | |

| | | | | | | | | | | | | | | | | | | | | | | | |

| 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 | | |

| | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | |

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.

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.

*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.

| | | | | | | | | | | | | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | Years Ended December 31, | | | | | | | | | | | | | | | | | | | | |

| | | | 2021 | | | | | | 2020 | | | | | | Change | | | | | | % Change | | |

| | | | | | | | | | | | | | | | | | | | | | | | |

| | | | (Thousands, unless otherwise noted) | | | | | | | | | | | | | | | | | | | | |

| 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 | | |

| Production taxes | | | 98,639 | | | | | | 46,376 | | | | | | 52,263 | | | | | | 112.7 | | |

| Exploration | | | 24,403 | | | | | | 5,484 | | | | | | 18,919 | | | | | | 345.0 | | |

| | | | | | | | | | | | | | | | | | | | | | | | |

| Production depletion | | | $ | 1,658,113 | | | | | $ | 1,375,542 | | | | | $ | 282,571 | | | | | 20.5 | | |

| | | | | | | | | | | | | | | | | | | | | | | | |

| Gathering | | | $ | 0.66 | | | | | $ | 0.71 | | | | | $ | (0.05) | | | | | (7.0) | | |

The variance was attributable primarily to decreased impairments, the gain on the Equitrans Share Exchange (defined and discussed in Note 5 to the Consolidated Financial Statements), decreased other operating expenses, decreased depreciation and depletion expense and decreased transportation and processing expense, partly offset by decreased operating revenues, increased interest expense and decreased dividend and other income.

[Table of](#i43f68b92b00b4f60b7eb2031407a74f6_7) [Contents](#i43f68b92b00b4f60b7eb2031407a74f6_7)

| | | | 2020 | | | | | | 2019 | | |

| Cash settled derivatives (not designated as hedges) ($/Bbl) | | | — | | | | | | 1.02 | | |

| Average Ethane price, including cash settled derivatives ($/Bbl) | | | $ | 3.48 | | | | | $ | 7.18 | |

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

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

| | | | | | | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | 2020 | | | | | | 2019 | | | | | | % | | |

| Marcellus (a) | | | 1,314,801 | | | | | | 1,270,352 | | | | | | 3.5 | | |

| Ohio Utica | | | 177,864 | | | | | | 231,545 | | | | | | (23.2) | | |

| Other | | | 5,127 | | | | | | 5,999 | | | | | | (14.5) | | |

| Total sales volumes (b) | | | 1,497,792 | | | | | | 1,507,896 | | | | | | (0.7) | | |

(a)Includes Upper Devonian wells.

Sales volumes for 2020 decreased compared

to 2019 due primarily to our strategic decisions to temporarily curtail production beginning in May 2020 and ending in November 2020 (the Strategic Production Curtailments) which resulted in a decrease to sales volumes of approximately 46 Bcfe.

Sales volumes for 2020 also decreased compared to 2019 by 16 Bcfe as a result of the 2020 Divestitures (defined in Note 7 to the Consolidated Financial Statements).

These decreases were partly offset by operational efficiencies realized throughout the year from increased production up-time and positively impacted sales volumes as well as an increase of approximately 12 Bcfe due to the Chevron Acquisition.

| Gathering | | | $ | 1,068,590 | | | | | $ | 1,038,646 | | | | | 2.9 | | |

| Transmission | | | 506,668 | | | | | | 588,302 | | | | | | (13.9) | | |

| Processing | | | 135,476 | | | | | | 125,804 | | | | | | 7.7 | | |

| Production taxes | | | 46,376 | | | | | | 69,284 | | | | | | (33.1) | | |

| Exploration | | | 5,484 | | | | | | 7,223 | | | | | | (24.1) | | |

| Production depletion | | | $ | 1,375,542 | | | | | $ | 1,524,112 | | | | | (9.7) | | |

| Gathering | | | $ | 0.71 | | | | | $ | 0.69 | | | | | 2.9 | | |

| Transmission | | | 0.34 | | | | | | 0.39 | | | | | | (12.8) | | |

| Processing | | | 0.09 | | | | | | 0.08 | | | | | | 12.5 | | |

| LOE, excluding production taxes | | | 0.07 | | | | | | 0.06 | | | | | | 16.7 | | |

| Exploration | | | — | | | | | | — | | | | | | — | | |

| Production depletion | | | 0.92 | | | | | | 1.01 | | | | | | (8.9) | | |

*Gathering.* Gathering expense increased on an absolute and per Mcfe basis for 2020 compared to 2019 due to a higher gathering rate structure as a result of the Consolidated GGA (defined in Note 5 to the Consolidated Financial Statements), partly offset by lower gathered volumes as a result of the Strategic Production Curtailments.

We expect to realize fee relief and a lower gathering rate structure from the Consolidated GGA beginning on the Mountain Valley Pipeline in-service date.

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

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

The decrease was due primarily to the impairment of intangible assets recognized in the third quarter of 2019 as described below, which decreased the amortization rate.

During the fourth quarter of 2019, we recorded impairment of long-lived assets of $1,124.4 million, of which $1,035.7 million was associated with our non-strategic assets located in the Ohio Utica and $88.7 million was associated with our Pennsylvania and West Virginia Utica assets.

The impairment was due primarily to depressed natural gas prices and changes in our development strategy.

During the third quarter of 2019, we recognized impairment of $15.4 million of intangible assets associated with non-compete agreements for former Rice Energy Inc. executives who are now our employees.

*Impairment and expiration of leases.* Impairment and expiration of leases for 2020 was $306.7 million compared to $556.4 million for 2019.

In addition, to the extent we have hedged our production at prices below the current market price, we will not benefit fully from an increase in the price of natural [removed: gas.][added: gas, and, depending on our then-current credit ratings and the terms of our hedging contracts, we may be required to post additional margin with our hedging counterparties.]

We also enter into derivative instruments to hedge [removed: basis and exposure to fluctuations in interest rates.][added: basis.]

Our use of derivative instruments is implemented under a set of policies approved by our [added: management-level] Hedge and Financial Risk Committee and [added: is] reviewed by our Board of Directors.

A hypothetical decrease of 10% in the [removed: market price of] [added: NYMEX] natural gas [added: price] on December 31, [removed: 2020] [added: 2021] and [removed: 2019] [added: 2020] would increase the fair value of our natural gas derivative commodity instruments by approximately [removed: $501] [added: $577] million and [removed: $389] [added: $501] million, respectively.

A hypothetical increase of 10% in the [removed: market price of] [added: NYMEX] natural gas [added: price] on December 31, [removed: 2020] [added: 2021] and [removed: 2019] [added: 2020] would decrease the fair value of our natural gas derivative commodity instruments by approximately [removed: $495] [added: $581] million and [removed: $395] [added: $495] million, respectively.

For purposes of this analysis, we applied the 10% change in the [removed: market price of] [added: NYMEX] natural gas [added: price] on December 31, [removed: 2020] [added: 2021] and [removed: 2019] [added: 2020] to our natural gas derivative commodity instruments as of December 31, [removed: 2020] [added: 2021] and [removed: 2019] [added: 2020] to calculate the hypothetical change in fair value.

*Interest Rate Risk.* Changes in market interest rates affect the amount of interest we earn on cash, cash equivalents and short-term investments and the interest [removed: rates] [added: rate] we pay on borrowings [removed: on] [added: under] our credit [removed: facility and, prior to its full redemption on June 30, 2020, our Term Loan Facility.][added: facility.]

A 1% increase in interest rates on [removed: our] [added: the] borrowings [removed: on] [added: under] our credit facility [removed: and term loan facility] during the year ended December 31, [removed: 2020] [added: 2021] would have increased [removed: 2020 annual] interest expense by approximately [removed: $5] [added: $6] million.

Interest rates on [removed: the Adjustable Rate Notes] [added: our other outstanding senior notes do not] fluctuate based on changes to the credit ratings assigned to our senior notes by Moody's, S&P and Fitch.

See Note 10 to the Consolidated Financial Statements for further discussion of our debt and Note 4 to the Consolidated Financial Statements for a discussion of fair value measurements, including the fair value [added: measurement] of our debt.

Approximately [removed: 75%,] [added: 17%,] or [removed: $718] [added: $477] million, of our OTC derivative contracts outstanding at December 31, [removed: 2019] [added: 2021] had a positive fair value.

As of December 31, [removed: 2020,] [added: 2021,] we were not in default under any derivative contracts and had no knowledge of default by any counterparty to our derivative contracts.

During the year ended December 31, [removed: 2020,] [added: 2021,] we made no adjustments to the fair value of our derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in our established fair value procedure.

Interest rates on our 6.125% senior notes due 2025 and 7.00% senior notes due 2030 fluctuate based on changes to the credit ratings assigned to our senior notes by Moody's, S&P and Fitch.

[Table of](#i43f68b92b00b4f60b7eb2031407a74f6_7) [Contents](#i43f68b92b00b4f60b7eb2031407a74f6_7)

A 1% increase in interest rates on our borrowings under our credit facility, term loan facility and floating rate notes during the year ended December 31, 2019 would have increased 2019 annual interest expense by approximately $14 million.

Based on average daily sales [removed: volumes,] [added: volume,] we are the largest producer of natural gas in the United States.

As of December 31, [removed: 2020,] [added: 2021,] we had [removed: 19.8] [added: 25.0] Tcfe of proved natural gas, NGLs and crude oil reserves across approximately [removed: 1.8] [added: 2.0] million gross acres, including approximately [removed: 1.5] [added: 1.7] million gross acres in the Marcellus play.

- Achieved [removed: 2020] [added: 2021] sales [removed: volumes] [added: volume] of [removed: 1,498 Bcfe or] [added: 1,858 Bcfe,] average daily sales [removed: volumes] [added: volume] of [removed: 4.1] [added: 5.1] Bcfe per day; received an average realized price of [removed: $2.37] [added: $2.50] per Mcfe.

- Increased [added: 2021] total proved reserves by [removed: 2.3 Tcfe] [added: 5.2 Tcfe,] or [removed: 13% in 2020] [added: 26%,] compared to [removed: 2019.][added: 2020.]

- Acquired strategic assets [removed: from Chevron U.S.A. Inc.] located in the Appalachian Basin [added: from Alta Resources Development, LLC] for [removed: an aggregate purchase price] [added: total consideration] of [removed: $735] [added: $2,925] million [removed: (Chevron] [added: (the Alta] Acquisition).

In [removed: 2021,] [added: 2022,] we expect to spend approximately [removed: $1.1] [added: $1.30] to [removed: $1.2] [added: $1.45] billion in total capital expenditures, excluding amounts attributable to noncontrolling [removed: interests.][added: interest.]

We expect to [removed: fund] [added: allocate the] planned capital expenditures [removed: with cash generated from operations, allocated] as follows: approximately [removed: $800] [added: $1.0] to [removed: $850 million] [added: $1.1 billion] to fund reserve development, approximately [removed: $125] [added: $110] to [removed: $140] [added: $130] million to fund land and lease acquisitions, approximately [removed: $130] [added: $120] to [removed: $155] [added: $160] million to fund other production infrastructure and approximately [removed: $45 to] $55 [added: to $75] million applied towards capitalized overhead.

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, [removed: NGL] [added: NGLs] and oil producing activities and our accounting policies and processes related to impairment reviews for proved and unproved property.

| Proved undeveloped reserves | | | [removed: 6,115] [added: 7,372] | | | | | | [removed: 8] [added: 62] | | | | | | [removed: 6,161] [added: 7,743] | | |

| Proved developed non-producing reserves | | | [removed: 538] [added: 375] | | | | | | [removed: 7] [added: 123] | | | | | | [removed: —] [added: 6] | | | | | | | | | | | | [removed: 545] [added: 504] | | |

| Gross proved undeveloped drilling locations | | | [removed: 201] [added: 279] | | | | | | [removed: 73] [added: 146] | | | | | | 5 | | | | | | | | | | | | [removed: 279] [added: 430] | | |

| Net proved undeveloped drilling locations | | | [removed: 169] [added: 195] | | | | | | [removed: 65] [added: 118] | | | | | | [removed: 5] [added: 1] | | | | | | | | | | | | [removed: 239] [added: 314] | | |

Our [removed: 2020] [added: 2021] total proved reserves increased by [removed: 2.3] [added: 5.2] Tcfe, or [removed: 13%,] [added: 26%,] compared to [removed: 2019] [added: 2020] due to [added: 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 [removed: 3,446 Bcfe and the acquisition of 1,381 Bcfe from the Chevron Acquisition,] [added: 3,104 Bcfe,] partly offset by production of [removed: 1,498 Bcfe,] [added: 1,858 Bcfe and] revisions to previous estimates of [removed: 739 Bcfe and divestitures of 257] [added: 274] Bcfe.

| Conversions into proved developed reserves | | | [removed: (2,102)] [added: (1,634)] | | |

| Acquisition of in-place reserves | | | [removed: 171] [added: 1,217] | | |

| Revision of previous estimates (a) | | | [removed: (355)] [added: (881)] | | |

| Extensions, discoveries and other additions (b) | | | [removed: 3,422] [added: 2,880] | | |

(a)Composed of (i) negative revisions of [removed: 510] [added: 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 [removed: which included 245 Bcfe from lower pricing that impacted well economics, shifting capital from the Ohio Utica,] to [removed: Pennsylvania and West Virginia Marcellus and 265 Bcfe as a result of] [added: support the] continued implementation of our combo-development strategy; and (ii) [removed: positive] [added: negative] revisions of [removed: 155] [added: 62] Bcfe due primarily to changes in working interests and net revenue [removed: interests as well as revisions to type curves.][added: interests.]

(b)Composed of (i) [removed: 2,096] [added: 2,828] Bcfe [removed: of] [added: from] proved undeveloped additions associated with acreage that was previously unproved but became proved [removed: using reliable technologies which] [added: due to 2021 reserve development that] expanded the number of our [removed: technically] proven [removed: locations;] [added: locations, implementation of, and alignment with, our combo-development strategy and additions to our five-year drilling plan; and] (ii) [removed: 1,295] [added: 52] Bcfe [removed: due to additions][added: from the extension of lateral lengths of proved undeveloped reserves.]

As of December 31, [removed: 2020,] [added: 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 [removed: our] [added: the] standardized measure of estimated future net cash flows from natural gas and crude oil reserves.

As of December 31, [removed: 2020,] [added: 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 [removed: (which is referred] [added: (referred] to as SEC pricing), was [removed: $3,366 million] [added: $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, [removed: 2020] [added: 2021] and held constant thereafter using (i) the NYMEX five-year strip adjusted for regional differentials using Texas Eastern Transmission Corp. M-2, [added: 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 [removed: with] [added: holding] all other assumptions [removed: held] constant, our total proved reserves would be [removed: 20,296] [added: 24,913] Bcfe, the standardized measure of our discounted net future cash flows after taxes of our proved reserves would be [removed: $8,952 million,] [added: $16,059 million] and the discounted future net cash flows before taxes would be [removed: $10,152] [added: $19,672] million.

The average realized product prices weighted by production over the remaining lives of the properties would be [removed: $27.18] [added: $46.84] per barrel of oil, [removed: $13.55] [added: $27.22] per barrel of [removed: NGL] [added: NGLs] and [removed: $2.075] [added: $2.448] per Mcf of gas [removed: (as compared] [added: (compared] to [removed: $20.94] [added: $51.57] per barrel of oil, [removed: $11.97] [added: $29.95] per barrel of [removed: NGL] [added: NGLs] and [removed: $1.38] [added: $2.694] per Mcf of gas using SEC pricing, as described in Note [removed: 18).][added: 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 [removed: “SEC pricing”] [added: SEC pricing] proved reserves and do not comply with SEC pricing assumptions.

We believe that the presentation of reserve [removed: volumes] [added: 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 [removed: market’s] [added: market's] forward-looking expectations of oil and gas prices as of a certain date.

We hedge [removed: substantial] [added: certain] amounts of future production based [removed: upon] [added: on] futures prices.

Based on our mix of proved undeveloped and probable reserves, we estimate that we have an undeveloped drilling inventory of approximately [removed: 1,660] [added: 2,400] net locations in [added: the] Pennsylvania and West Virginia [removed: Marcellus.][added: Marcellus Shale.]

At our current drilling pace, these net locations provide more than [removed: 15] [added: 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.

| [removed: | | |] Years [removed: Ended] [added: Ending] December 31, | | | | | | | | | | | | [removed: | | |]

| | | | [removed: 2020] [added: 2021] | | | | | | [removed: 2019] [added: 2020] | | | | | | [removed: 2018] [added: 2019] | | |

| Utica | | | [removed: 102] [added: 40] | | | | | | [removed: 193] [added: 102] | | | | | | [removed: 360] [added: 193] | | |

| Total | | | $ | [removed: 839] [added: 828] | | | | | $ | [removed: 1,377] [added: 839] | | | | | $ | [removed: 2,249] [added: 1,377] | |

[removed: Lease operating costs, excluding production taxes, for] [added: For] the years ended December 31, [removed: 2020, 2019] [added: 2021, 2020] and [removed: 2018 was] [added: 2019, lease operating costs, excluding production taxes were] $0.07, [removed: $0.06] [added: $0.07] and [removed: $0.07,] [added: $0.06,] respectively.

Approximately [removed: 24%] [added: 28%] of our total gross acres is developed.

| Average net revenue interest of proved developed reserves [added: (a)] | | | [removed: 72.9] [added: 59.8] | | % | | | | [removed: 83.0] [added: 82.0] | | % | | | | [removed: 48.8] [added: 48.9] | | % | | | | | | | | | | [removed: 72.7] [added: 62.5] | | % |

In the event that production is not established or we [removed: take no action to] [added: do not] extend or renew the terms of our [added: expiring] leases, [removed: 71,322, 69,813] [added: 57,361, 36,799] and [removed: 40,958] [added: 31,123] of our net undeveloped acreage as of December 31, [removed: 2020] [added: 2021] will expire in the years ending December 31, [removed: 2021, 2022] [added: 2022, 2023] and [removed: 2023,] [added: 2024,] respectively.

We had no productive or in-process oil wells as of December 31, [removed: 2020.][added: 2021.]

| Total gross | | | [removed: 3,203] [added: 4,527] | | | | | | | | |

| Total net | | | [removed: 2,852] [added: 3,510] | | | | | | | | |

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 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.

2021 Highlights

- 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.

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.

| | | | December 31, 2021 | | | | | | | | | | | | | | |

| Proved developed reserves | | | 16,152 | | | | | | 178 | | | | | | 17,219 | | |

| Total proved reserves | | | 23,524 | | | | | | 240 | | | | | | 24,962 | | |

| | | | December 31, 2021 | | | | | | | | | | | | | | | | | | | | | | | | | | |

| 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 | | |

| | | | December 31, 2021 | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Proved developed producing reserves | | | 12,642 | | | | | | 3,292 | | | | | | 781 | | | | | | | | | | | | 16,715 | | |

| Proved undeveloped reserves | | | 5,085 | | | | | | 2,648 | | | | | | 10 | | | | | | | | | | | | 7,743 | | |

| Total proved reserves | | | 18,102 | | | | | | 6,063 | | | | | | 797 | | | | | | | | | | | | 24,962 | | |

Our 2021 proved undeveloped reserves increased by 1,582 Bcfe, or 26%, compared to 2020.

| | | | | | |

| Balance at January 1, 2021 | | | 6,161 | | |

| Balance at December 31, 2021 | | | 7,743 | | |

| Marcellus | | | $ | 788 | | | | | $ | 737 | | | | | $ | 1,184 | |

| | | | December 31, 2021 | | | | | | | | | | | | | | | | | | | | | | | | | | |

| 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 | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

(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.

| | | | December 31, 2021 | | | | | | | | |

2020 Highlights

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

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

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

[Table of](#i43f68b92b00b4f60b7eb2031407a74f6_7) [Contents](#i43f68b92b00b4f60b7eb2031407a74f6_7)

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

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

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

Reserve development capital expenditures will be spent across our three primary operating areas, with approximately 65% spent in Pennsylvania Marcellus, approximately 30% spent in West Virginia Marcellus, and approximately 5% spent in Ohio Utica.

Our 2021 capital expenditure program is expected to deliver sales volumes of 1,620 Bcfe to 1,700 Bcfe, an increase of 120-200 Bcfe when compared to 2020 sales volumes primarily driven by increased production from the Chevron Acquisition.

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | December 31, 2020 | | | | | | | | | | | | | | |

| Proved developed reserves | | | 12,750 | | | | | | 148 | | | | | | 13,641 | | |

| Total proved reserves | | | 18,865 | | | | | | 156 | | | | | | 19,802 | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | December 31, 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Proved developed reserves | | | 11,943 | | | | | | 839 | | | | | | 757 | | | | | | 102 | | | | | | 13,641 | | |

| Proved undeveloped reserves | | | 6,061 | | | | | | — | | | | | | 100 | | | | | | — | | | | | | 6,161 | | |

| Total proved reserves | | | 18,004 | | | | | | 839 | | | | | | 857 | | | | | | 102 | | | | | | 19,802 | | |

| Proved developed producing reserves | | | 9,590 | | | | | | 2,749 | | | | | | 757 | | | | | | | | | | | | 13,096 | | |

| Proved undeveloped reserves | | | 4,465 | | | | | | 1,596 | | | | | | 100 | | | | | | | | | | | | 6,161 | | |

| Total proved reserves | | | 14,593 | | | | | | 4,352 | | | | | | 857 | | | | | | | | | | | | 19,802 | | |

We have an additional 13 Tcfe of reserves that meet the definition of proved reserves, except they are planned to be developed beyond five years and are therefore not included in the current estimate of proved reserves.

During 2020, we conducted a study of our reserves areas to determine the reliability of the technology used in calculating our reserves.

This study demonstrated that technologies used in the course of our reserves determination are reliable, provide reasonable certainty of future performance and economics of our wells, and conform to booking practices when using reliable technologies.

The technologies used in the estimation of our proved reserves include, but are not limited to, empirical evidence through drilling results and well performance, production data, decline curve analysis, well logs, geologic maps, core data, seismic data, demonstrated relationship between geologic parameters and performance, and the implementation and application of statistical analysis.

Proved undeveloped reserves increased by 1,136 Bcfe, or 23%, in 2020 from 2019.

| Balance at January 1, 2020 | | | 5,025 | | |

| Balance at December 31, 2020 | | | 6,161 | | |

associated with directly offsetting development; and (ii) 31 Bcfe from the extension of lateral lengths of proved undeveloped reserves.

| Marcellus (includes Upper Devonian) | | | $ | 737 | | | | | $ | 1,184 | | | | | $ | 1,889 | |

| Total gross productive acreage | | | 319,504 | | | | | | 84,374 | | | | | | 46,688 | | | | | | | | | | | | 450,566 | | |

| Total gross undeveloped acreage | | | 818,345 | | | | | | 448,401 | | | | | | 125,995 | | | | | | | | | | | | 1,392,741 | | |

| Total gross acreage | | | 1,137,849 | | | | | | 532,775 | | | | | | 172,683 | | | | | | | | | | | | 1,843,307 | | |

| Total net productive acreage | | | 289,820 | | | | | | 83,720 | | | | | | 33,906 | | | | | | | | | | | | 407,446 | | |

| Total net undeveloped acreage | | | 709,845 | | | | | | 352,402 | | | | | | 109,115 | | | | | | | | | | | | 1,171,362 | | |

| Total net acreage | | | 999,665 | | | | | | 436,122 | | | | | | 143,021 | | | | | | | | | | | | 1,578,808 | | |

| | | | December 31, 2020 | | | | | | | | |

| Total gross productive wells (a) | | | 2,252 | | | | | | 685 | | | | | | 266 | | | | | | | | | | | | 3,203 | | |

| Total net productive wells | | | 2,059 | | | | | | 659 | | | | | | 134 | | | | | | | | | | | | 2,852 | | |

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 [removed: matter currently] pending [removed: against] [added: matter involving] us will not materially [removed: impact] [added: affect] our financial position, results of operations or liquidity.

The plaintiffs sought more than $100 million in compensatory damages for the trespass claim under the Stout [removed: Lease,] [added: 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.

All [removed: recent] motions are pending.

*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.

*Produced Water Release, Marshall County, West Virginia.* On November 12, 2019, we received a Notice of Violation (NOV) from the West Virginia Department of Environmental Protection (WVDEP) relating to the Goshorn Pad in Marshall County, West Virginia.

The NOV alleged violations of Water Pollution Control Rules in connection with a release of produced water from secondary containment at a Goshorn Pad tank battery.

We cooperated fully with WVDEP to take appropriate actions to address the secondary containment issues and remediation of the release, and this matter was substantially resolved in March 2020.

We were not assessed any monetary penalty for this matter, and the resolution of this matter did not have a material impact on our financial position, results of operations or liquidity.

*Secondary Containment underneath Gas Processing Units (GPUs), Allegheny, Greene and Washington Counties, Pennsylvania.* On April 1, 2020, we received a draft Consent Order and Agreement from the Pennsylvania Department of Environmental Protection (PADEP) claiming that we failed to install secondary containment systems in accordance with 25 Pa.

Code § 78a.64a(b) underneath 228 GPUs located in southwest Pennsylvania between October 8, 2016 and February 4, 2019.

On February 4, 2019, we voluntarily disclosed a list of GPUs that did not meet the requirements of 25 Pa.

Code § 78a.64a(b).

On December 17, 2020, we entered into the Consent Order and Agreement with PADEP, pursuant to which we agreed to install

[Table of](#i43f68b92b00b4f60b7eb2031407a74f6_7) [Contents](#i43f68b92b00b4f60b7eb2031407a74f6_7)

secondary containment systems in compliance with 25 Pa.

Code § 78a.64a(b) on all new GPU installations going forward, among other things, and this matter was resolved.

*Hammerhead Gathering Agreement Dispute.* EQT Corporation and Equitrans Midstream, through certain of our and their subsidiaries, are parties to a gas gathering agreement (the Hammerhead Gathering Agreement) related to Equitrans Midstream's Hammerhead Gas Gathering System.

Pursuant to the terms of the Hammerhead Gathering Agreement, if the "In-Service Date" did not occur on or before October 1, 2020, we may terminate the Hammerhead Gathering Agreement and purchase the Hammerhead Gas Gathering System from Equitrans Midstream for an amount equal to 88% of expenses actually incurred and other obligations made or to be incurred by Equitrans Midstream.

The "In-Service Date" is defined in the Hammerhead Gathering Agreement as "the later of (i) the first Day of the Month immediately following the date on which Gatherer is first able to provide the Gathering Services to Shipper in accordance with the Hammerhead Gathering Agreement and (ii) the first Day of the Month immediately following the date on which the Interconnect Facilities connecting the Gathering System to the Mountain Valley Pipeline are first able to receive deliveries of the Contract MDQ." On September 24, 2020, we initiated arbitration proceedings against Equitrans Midstream, seeking a declaration that we are entitled to terminate the Hammerhead Gathering Agreement and purchase the Hammerhead Gas Gathering System.

The deadline for us to provide notice of our election to terminate the Hammerhead Gathering Agreement and purchase the Hammerhead Gas Gathering System has been tolled while the contract claim is pending in arbitration.

| | | | FOR THE FISCAL YEAR ENDED DECEMBER 31, [removed: 2020] [added: 2021] | | | | | |

The aggregate market value of common stock held by non-affiliates of the registrant as of June 30, [removed: 2020: $3.0] [added: 2021: $6.2] billion

As of February [removed: 12, 2021, 278,854,465] [added: 4, 2022, 376,023,250] shares of common stock, no par value, of the registrant were outstanding.

EQT Corporation's definitive proxy statement relating to its [removed: 2021] [added: 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, [removed: 2020] [added: 2021] and is incorporated by reference in Part III to the extent described therein.

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| [Item [removed: 13.](#i43f68b92b00b4f60b7eb2031407a74f6_199)] [added: 13.](#ib6b2fe1565e24737983a625bb9fea3f6_172)] | | | [Certain Relationships and Related Transactions, and Director [removed: Independence](#i43f68b92b00b4f60b7eb2031407a74f6_199)] [added: Independence](#ib6b2fe1565e24737983a625bb9fea3f6_172)] | | | [removed: [114](#i43f68b92b00b4f60b7eb2031407a74f6_199)] [added: [117](#ib6b2fe1565e24737983a625bb9fea3f6_172)] | | |

| [Item [removed: 14.](#i43f68b92b00b4f60b7eb2031407a74f6_202)] [added: 14.](#ib6b2fe1565e24737983a625bb9fea3f6_175)] | | | [Principal [removed: Accounting] [added: Accountant] Fees and [removed: Services](#i43f68b92b00b4f60b7eb2031407a74f6_202)] [added: Services](#ib6b2fe1565e24737983a625bb9fea3f6_175)] | | | [removed: [114](#i43f68b92b00b4f60b7eb2031407a74f6_202)] [added: [117](#ib6b2fe1565e24737983a625bb9fea3f6_175)] | | |

| [Item [removed: 15.](#i43f68b92b00b4f60b7eb2031407a74f6_208)] [added: 15.](#ib6b2fe1565e24737983a625bb9fea3f6_181)] | | | [Exhibits and Financial Statement [removed: Schedules](#i43f68b92b00b4f60b7eb2031407a74f6_208)] [added: Schedules](#ib6b2fe1565e24737983a625bb9fea3f6_181)] | | | [removed: [115](#i43f68b92b00b4f60b7eb2031407a74f6_208)] [added: [117](#ib6b2fe1565e24737983a625bb9fea3f6_181)] | | |

| [Item [removed: 16.](#i43f68b92b00b4f60b7eb2031407a74f6_217)] [added: 16.](#ib6b2fe1565e24737983a625bb9fea3f6_190)] | | | [Form 10-K [removed: Summary](#i43f68b92b00b4f60b7eb2031407a74f6_217)] [added: Summary](#ib6b2fe1565e24737983a625bb9fea3f6_190)] | | | [removed: [120](#i43f68b92b00b4f60b7eb2031407a74f6_217)] [added: [123](#ib6b2fe1565e24737983a625bb9fea3f6_190)] | | |

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

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 [removed: amended,] [added: amended (the Exchange Act),] and Section 27A of the Securities Act of 1933, as amended.

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 [removed: programs (including] [added: programs, including] availability of capital to complete [removed: such] [added: these] plans and [removed: programs); the projected scope and timing of our combo-development projects; estimated reserves, including potential future downward adjustments of reserves and reserve life;] [added: programs;] total resource potential and drilling inventory duration; projected production and sales [removed: volumes and growth rates (including liquids production and sales volumes] [added: volume] and growth [removed: rates);] [added: rates;] natural gas [removed: prices,] [added: prices;] changes in basis and the impact of commodity prices on our business; potential [removed: impacts to our business and operations resulting from COVID-19 or a similar pandemic; potential] future impairments of our assets; [removed: our ability to reduce our drilling and completions costs, other] [added: projected well] costs and [removed: expenses and] capital [removed: expenditures, and the timing of achieving any such reductions;] [added: 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 [removed: benefits] [added: results] of such initiatives; projected [removed: reductions of our] gathering and compression [removed: rates resulting from our consolidated gathering agreement with EQM Midstream Partners, LP, and the anticipated cost savings and other strategic benefits associated with the execution of such agreement;] [added: rates;] monetization transactions, including asset sales, joint ventures or other transactions involving our assets, and our planned use of the proceeds from [removed: any] such monetization transactions; potential [removed: acquisitions] [added: 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 [removed: Midstream Corporation's (Equitrans Midstream's)] [added: 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; [added: the] projected [removed: dividend amounts] [added: amount] and [removed: rates;] [added: timing of dividends;] projected cash flows and free cash [removed: flow; projected capital expenditures;] [added: 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 [removed: strategy;] [added: strategy and projected margin posting obligations;] the effects of litigation, government regulation and tax position; and the expected impact of changes to tax laws.

| [Summary of Risk Factors](#ib6b2fe1565e24737983a625bb9fea3f6_1720) | | | | | | [6](#ib6b2fe1565e24737983a625bb9fea3f6_1720) | | |

| [Item 6.](#ib6b2fe1565e24737983a625bb9fea3f6_46) | | | [\[Reserved\]](#ib6b2fe1565e24737983a625bb9fea3f6_46) | | | [46](#ib6b2fe1565e24737983a625bb9fea3f6_46) | | |

| [Item 9C.](#ib6b2fe1565e24737983a625bb9fea3f6_1772) | | | [Disclosure Regarding Foreign Jurisdictions that Prevent Inspections](#ib6b2fe1565e24737983a625bb9fea3f6_1772) | | | [115](#ib6b2fe1565e24737983a625bb9fea3f6_1772) | | |

| [Signatures](#ib6b2fe1565e24737983a625bb9fea3f6_193) | | | | | | [124](#ib6b2fe1565e24737983a625bb9fea3f6_193) | | |

has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated

or in an analogous formation.

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."

[Table of](#i43f68b92b00b4f60b7eb2031407a74f6_7) [Contents](#i43f68b92b00b4f60b7eb2031407a74f6_7)

| [Item 6.](#i43f68b92b00b4f60b7eb2031407a74f6_46) | | | [Selected Financial Data](#i43f68b92b00b4f60b7eb2031407a74f6_46) | | | [45](#i43f68b92b00b4f60b7eb2031407a74f6_46) | | |

| [Signatures](#i43f68b92b00b4f60b7eb2031407a74f6_220) | | | | | | [121](#i43f68b92b00b4f60b7eb2031407a74f6_220) | | |

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

We also own or lease office space in Pennsylvania, West [removed: Virginia, Ohio,] Virginia and Texas.

Information about our Executive Officers (as of February [removed: 17, 2021)][added: 10, 2022)]

| Tony Duran [removed: (42)] [added: (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 [removed: (43)] [added: (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 [removed: (38)] [added: (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 [removed: (40)] [added: (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 [removed: (57)] [added: (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 [removed: (39)] [added: (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 [removed: Plan (which] [added: Plan, which] includes confidentiality and non-compete [removed: provisions)] [added: provisions,] or executed non-compete agreements with EQT Corporation, and each of the executive officers serve at the pleasure of our Board of Directors.

[Table of](#i43f68b92b00b4f60b7eb2031407a74f6_7) [Contents](#i43f68b92b00b4f60b7eb2031407a74f6_7)

As of February [removed: 12, 2021,] [added: 4, 2022,] there were [removed: 1,985] [added: 1,927] shareholders of record of our common stock.

[removed: We did not repurchase any] [added: The following table sets forth our repurchases of] equity securities registered under Section 12 of the [removed: Securities] Exchange Act [removed: of 1934, as amended,] [added: that have occurred] during the three months ended December 31, [removed: 2020.][added: 2021.]

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 [removed: Standard & Poor’s (S&P)] [added: S&P] 500 Index, the S&P MidCap 400 Index and two customized peer groups, the [removed: 2019] [added: 2020] Self-Constructed Peer Group and [removed: 2020] [added: 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 [added: (defined] and [added: 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.

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, [removed: 2015] [added: 2016] and its relative performance is tracked through December 31, [removed: 2020.][added: 2021.]

[removed: ][added: ]

*$100 invested on [removed: 12/31/15] [added: 12/31/16] in stock, index, or peer group, including reinvestment of dividends.

Copyright© [removed: 2021] [added: 2022] Standard & [removed: Poor’s,] [added: Poor's,] a division of S&P Global.

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

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.

| | | | | | | | | | | | | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | 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.

| | | | 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 | | |

(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.

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

None.

Market Repurchases

[Table of](#i43f68b92b00b4f60b7eb2031407a74f6_7) [Contents](#i43f68b92b00b4f60b7eb2031407a74f6_7)

| | | | 12/15 | | | | | | 12/16 | | | | | | 12/17 | | | | | | 12/18 | | | | | | 12/19 | | | | | | 12/20 | | |

| EQT Corporation | | | $ | 100.00 | | | | | $ | 125.69 | | | | | $ | 109.60 | | | | | $ | 67.06 | | | | | $ | 39.01 | | | | | $ | 45.74 | |

| S&P 500 | | | 100.00 | | | | | | 111.96 | | | | | | 136.40 | | | | | | 130.42 | | | | | | 171.49 | | | | | | 203.04 | | |

| S&P MidCap 400 Index | | | 100.00 | | | | | | 120.74 | | | | | | 140.35 | | | | | | 124.80 | | | | | | 157.49 | | | | | | 179.00 | | |

| 2019 Self-Constructed Peer Group (a) | | | 100.00 | | | | | | 148.63 | | | | | | 129.24 | | | | | | 77.93 | | | | | | 60.57 | | | | | | 49.24 | | |

| 2020 Self-Constructed Peer Group (b) | | | 100.00 | | | | | | 132.65 | | | | | | 108.37 | | | | | | 72.36 | | | | | | 49.65 | | | | | | 50.87 | | |

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

Not Applicable.

| [Reports of Independent Registered Public Accounting [removed: Firm](#i43f68b92b00b4f60b7eb2031407a74f6_61)] [added: Firm](#ib6b2fe1565e24737983a625bb9fea3f6_61) [](#ib6b2fe1565e24737983a625bb9fea3f6_61)[(](#ib6b2fe1565e24737983a625bb9fea3f6_61)[PCAOB ID](#ib6b2fe1565e24737983a625bb9fea3f6_61)[:](#ib6b2fe1565e24737983a625bb9fea3f6_61) 42[)](#ib6b2fe1565e24737983a625bb9fea3f6_61)] | | | | | | [removed: [60](#i43f68b92b00b4f60b7eb2031407a74f6_61)] [added: [63](#ib6b2fe1565e24737983a625bb9fea3f6_61)] | | |

[removed: | [Notes to Consolidated Financial Statements](#i43f68b92b00b4f60b7eb2031407a74f6_91) | | | | | | [72](#i43f68b92b00b4f60b7eb2031407a74f6_91) | | |][added: NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS]

We have audited the accompanying consolidated balance sheets of EQT Corporation and subsidiaries (the Company) as of December 31, [removed: 2020] [added: 2021] and [removed: 2019,] [added: 2020,] the related statements of consolidated operations, comprehensive [removed: income,] [added: loss,] cash flows and equity for each of the three years in the period ended December 31, [removed: 2020,] [added: 2021,] and the related notes and the financial statement schedule listed in the Index at Item [removed: 15 (a)] [added: 15(a)] (collectively referred to as the "consolidated financial statements").

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company at December 31, [removed: 2020] [added: 2021] and [removed: 2019,] [added: 2020,] and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, [removed: 2020,] [added: 2021,] in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, [removed: 2020,] [added: 2021,] based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 [removed: framework)] [added: framework),] and our report dated February [removed: 17, 2021] [added: 10, 2022] expressed an unqualified opinion thereon.

| *Description of the Matter* | | | At December 31, [removed: 2020,] [added: 2021,] the net book value of the Company's proved oil and natural gas properties was [removed: $13,613] [added: $15,610] million, and depreciation, depletion and amortization (DD&A) expense was [removed: $1,393] [added: $1,677] million for the year then ended. As described in Note 1, under the successful efforts method of accounting, DD&A is recorded on a cost center basis using the units-of-production method. Proved developed reserves, as estimated by the [removed: Company’s] [added: Company's] internal engineers, are used to calculate depreciation of wells and related equipment and facilities and amortization of intangible drilling costs. Total proved reserves, also estimated by the [removed: Company’s] [added: Company's] engineers, are used to calculate depletion on property acquisitions. Proved natural gas, natural gas liquids (NGLs) and oil reserve estimates are based on geological and engineering evaluations of in-place hydrocarbon volumes. Significant judgment is required by the [removed: Company’s] [added: Company's] engineers in evaluating geological and engineering data when estimating proved natural gas, NGLs and oil reserves. Estimating reserves also requires the selection of inputs, including natural gas, NGLs and oil price assumptions, future operating and capital costs assumptions and tax rates by jurisdiction, among others. Because of the complexity involved in estimating natural gas, NGLs and oil reserves, management used independent engineers to audit the estimates prepared by the [removed: Company’s] [added: Company's] internal engineers as of December 31, [removed: 2020.] [added: 2021.] Auditing the [removed: Company’s] [added: Company's] DD&A calculation is especially complex because of the use of the work of the internal engineers and the independent engineers and the evaluation of [removed: management’s] [added: management's] determination of the inputs described above used by the specialists in estimating proved natural gas, NGLs and oil reserves. | | |

| *Description of the Matter* | | | As described in Note 6 to the consolidated financial statements, [added: on July 21, 2021,] the Company completed the acquisition of [removed: the Appalachian assets of Chevron U.S.A. during the year ended December 31, 2020.] [added: Alta Marcellus Development, LLC and ARD Operating, LLC and subsidiaries.] The [removed: Company’s] [added: Company's] accounting for the acquisition included determining the fair value of the acquired [removed: proved reserves.] [added: natural gas and oil properties.] The determination of fair value of the acquired [removed: proved reserves] [added: natural gas and oil properties] included significant judgment and assumptions by management, including future commodity prices, anticipated production volumes, future operating [added: and development] costs, and a weighted average cost of capital (WACC). Auditing the Company's valuation of acquired [removed: proved reserves] [added: natural gas and oil properties] involved a high degree of subjectivity as the determination of fair value was based on assumptions as described above about future market and economic conditions. In addition, [removed: the] certain of the assumptions developed by the Company’s [removed: engineering staff] [added: internal engineers] in conjunction with the reserve estimates described in the preceding critical audit [removed: matter,] [added: matter] are used as inputs in the cash flow model. | | |

| *How We Addressed the Matter in Our Audit* | | | We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company's process to estimate fair value for the acquired [removed: proved reserves.] [added: natural gas and oil properties.] For example, we tested controls over management's assessment of the appropriateness of the significant assumptions that are inputs to the fair value calculation and management’s review of the valuation model. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company engineer primarily responsible for overseeing the preparation of the reserve estimates by the internal engineering staff, the independent engineers used to audit the estimates, and the external valuation specialist used to assist with the determination of the fair value of certain acquired assets. Our testing of the Company’s estimate of fair value of the acquired [removed: proved reserves] [added: natural gas and oil properties] included, among other procedures, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data. The audit effort involved the use of our valuation specialists to assist in evaluating the appropriateness of the methodology used in the cash flow model, as well as testing the significant market-related assumptions described above used to develop the fair value estimate. We evaluated the reasonableness of management's assumptions by comparing the key market-related assumptions (including future natural gas prices and WACC rates) used in the cash flow model to external market and third-party data and anticipated production volumes to the reserve estimates audited by the independent engineers. | | |

We have audited EQT Corporation and subsidiaries' internal control over financial reporting as of December 31, [removed: 2020,] [added: 2021,] based on criteria established in Internal [removed: Control-Integrated] [added: Control – Integrated] Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria).

In our opinion, EQT Corporation and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, [removed: 2020,] [added: 2021,] based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, [removed: 2020 and 2019,] [added: 2021] and [added: 2020,] the related statements of consolidated operations, comprehensive [removed: income,] [added: loss,] cash flows and equity for each of the three years in the period ended December 31, [removed: 2020] [added: 2021] and the related notes and the financial statement schedule listed in the Index at Item [removed: 15 (a)] [added: 15(a)] of the [removed: Company] [added: Company,] and our report dated February [removed: 17, 2021] [added: 10, 2022] expressed an unqualified opinion thereon.

| | | | 2020 | | | | | | [removed: 2019 | | | | | | 2018] [added: 2019 (a)] | | |

| Sales of natural gas, natural gas liquids and oil | | | $ | [removed: 2,650,299] [added: 6,804,020] | | | | | $ | [removed: 3,791,414] [added: 2,650,299] | | | | | $ | [removed: 4,695,519] [added: 3,791,414] | |

| [removed: Gain (loss)] [added: (Loss) gain] on derivatives not designated as hedges | | | [removed: 400,214] [added: (3,775,042)] | | | | | | [removed: 616,634] [added: 400,214] | | | | | | [removed: (178,591)] [added: 616,634] | | |

| Net marketing services and other | | | [removed: 8,330] [added: 35,685] | | | | | | [removed: 8,436] [added: 8,330] | | | | | | [removed: 40,940] [added: 8,436] | | |

| Total operating revenues | | | [removed: 3,058,843] [added: 3,064,663] | | | | | | [removed: 4,416,484] [added: 3,058,843] | | | | | | [removed: 4,557,868] [added: 4,416,484] | | |

| Transportation and processing | | | [removed: 1,710,734] [added: 1,942,165] | | | | | | [removed: 1,752,752] [added: 1,710,734] | | | | | | [removed: 1,697,001] [added: 1,752,752] | | |

| Production | | | [removed: 155,403] [added: 225,279] | | | | | | [removed: 153,785] [added: 155,403] | | | | | | [removed: 195,775] [added: 153,785] | | |

| Exploration | | | [removed: 5,484] [added: 24,403] | | | | | | [removed: 7,223] [added: 5,484] | | | | | | [removed: 6,765] [added: 7,223] | | |

| Selling, general and administrative | | | [removed: 174,769] [added: 196,315] | | | | | | [removed: 170,611] [added: 174,769] | | | | | | [removed: 232,543] [added: 170,611] | | |

| Depreciation and depletion | | | [removed: 1,393,465] [added: 1,676,702] | | | | | | [removed: 1,538,745] [added: 1,393,465] | | | | | | [removed: 1,569,038] [added: 1,538,745] | | |

| Amortization of intangible assets | | | [removed: 26,006] [added: —] | | | | | | [removed: 35,916] [added: 26,006] | | | | | | [removed: 41,367] [added: 35,916] | | |

| [removed: Impairment/loss] [added: (Gain) loss/impairment] on sale/exchange of long-lived assets | | | [removed: 100,729] [added: (21,124)] | | | | | | [removed: 1,138,287] [added: 100,729] | | | | | | [removed: 2,709,976] [added: 1,138,287] | | |

| Impairment of intangible and other assets | | | [removed: 34,694] [added: —] | | | | | | [removed: 15,411] [added: 34,694] | | | | | | [removed: —] [added: 15,411] | | |

| Impairment and expiration of leases | | | [removed: 306,688] [added: 311,835] | | | | | | [removed: 556,424] [added: 306,688] | | | | | | [removed: 279,708] [added: 556,424] | | |

| Other operating expenses | | | [removed: 28,537] [added: 70,063] | | | | | | [removed: 199,440] [added: 28,537] | | | | | | [removed: 78,008] [added: 199,440] | | |

| Total operating expenses | | | [removed: 3,936,509] [added: 4,425,638] | | | | | | [removed: 5,568,594] [added: 3,936,509] | | | | | | [removed: 7,340,992] [added: 5,568,594] | | |

| Operating loss | | | [removed: (877,666)] [added: (1,360,975)] | | | | | | [removed: (1,152,110)] [added: (877,666)] | | | | | | [removed: (2,783,124)] [added: (1,152,110)] | | |

| Gain on Equitrans Share Exchange (see Note 5) | | | [removed: (187,223)] [added: —] | | | | | | [removed: —] [added: (187,223)] | | | | | | — | | |

| Dividend and other income | | | [removed: (35,512)] [added: (19,105)] | | | | | | [removed: (91,483)] [added: (35,512)] | | | | | | [removed: (7,017)] [added: (91,483)] | | |

| Loss on debt extinguishment | | | [removed: 25,435] [added: 9,756] | | | | | | [removed: —] [added: 25,435] | | | | | | — | | |

| Interest expense | | | [removed: 271,200] [added: 308,903] | | | | | | [removed: 199,851] [added: 271,200] | | | | | | [removed: 228,958] [added: 199,851] | | |

| Loss [removed: from continuing operations] before income taxes | | | [removed: (1,266,034)] [added: (1,588,688)] | | | | | | [removed: (1,597,471)] [added: (1,266,034)] | | | | | | [removed: (3,077,431)] [added: (1,597,471)] | | |

| Income tax benefit | | | [removed: (298,858)] [added: (434,175)] | | | | | | [removed: (375,776)] [added: (298,858)] | | | | | | [removed: (696,511)] [added: (375,776)] | | |

| Net loss | | | [removed: (967,176)] [added: (1,154,513)] | | | | | | [removed: (1,221,695)] [added: (967,176)] | | | | | | [removed: (2,007,158)] [added: (1,221,695)] | | |

| Less: Net [removed: loss] [added: income (loss)] attributable to noncontrolling interest | | | [removed: (10) | | | | | |] — | | | | | | — | | |

| Net loss attributable to EQT Corporation | | | $ | [removed: (967,166)] [added: (1,155,759)] | | | | | $ | [removed: (1,221,695)] [added: (967,166)] | | | | | $ | [removed: (2,244,568)] [added: (1,221,695)] | |

| Net loss | | | $ | [removed: (967,166)] [added: (1,154,513)] | | | | | $ | [removed: (1,221,695)] [added: (967,176)] | | | | | $ | [removed: (2,244,568)] [added: (1,221,695)] | |

| Weighted average common stock outstanding | | | [removed: 260,613] [added: 323,196] | | | | | | [removed: 255,141] [added: 260,613] | | | | | | [removed: 260,932] [added: 255,141] | | |

| Net loss [added: attributable to EQT Corporation] | | | $ | [removed: (3.71)] [added: (3.58)] | | | | | $ | [removed: (4.79)] [added: (3.71)] | | | | | $ | [removed: (8.60)] [added: (4.79)] | |

| [Statements of Consolidated Operations](#ib6b2fe1565e24737983a625bb9fea3f6_64) | | | | | | [67](#ib6b2fe1565e24737983a625bb9fea3f6_64) | | |

| [Statements of Consolidated Comprehensive](#ib6b2fe1565e24737983a625bb9fea3f6_70) [Loss](#ib6b2fe1565e24737983a625bb9fea3f6_70) | | | | | | [68](#ib6b2fe1565e24737983a625bb9fea3f6_70) | | |

| [Consolidated Balance Sheets](#ib6b2fe1565e24737983a625bb9fea3f6_73) | | | | | | [69](#ib6b2fe1565e24737983a625bb9fea3f6_73) | | |

| [Statements of Consolidated Cash Flows](#ib6b2fe1565e24737983a625bb9fea3f6_76) | | | | | | [70](#ib6b2fe1565e24737983a625bb9fea3f6_76) | | |

| [Statements of Consolidated Equity](#ib6b2fe1565e24737983a625bb9fea3f6_79) | | | | | | [71](#ib6b2fe1565e24737983a625bb9fea3f6_79) | | |

Valuation of Acquired Natural Gas and Oil Properties

February 10, 2022

February 10, 2022

| (Income) loss from investments | | | (71,841) | | | | | | 314,468 | | | | | | 336,993 | | |

| Less: Net income (loss) attributable to noncontrolling interest | | | 1,246 | | | | | | (10) | | | | | | — | | |

| | | | 2021 | | | | | | 2020 | | |

| Cash and cash equivalents | | | $ | 113,963 | | | | | $ | 18,210 | |

| Other assets | | | 491,702 | | | | | | 433,754 | | |

| (Income) loss from investments | | | (71,841) | | | | | | 314,468 | | | | | | 336,993 | | |

| Loss on debt extinguishment | | | 9,756 | | | | | | 25,435 | | | | | | — | | |

| Proceeds from sale/exchange of investment shares | | | 24,369 | | | | | | 52,323 | | | | | | — | | |

| Other financing activities | | | (1,038) | | | | | | — | | | | | | — | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Net (loss) income | | | | | | | | | | | | | | | | | | | | | (1,155,759) | | | | | | | | | | | | 1,246 | | | | | | (1,154,513) | | |

| Alta Acquisition (see Note 6) | | | 98,789 | | | | | | 1,925,405 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,925,405 | | |

| Contributions from noncontrolling interest | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 7,500 | | | | | | 7,500 | | |

| Balance at December 31, 2021 | | | 376,399 | | | | | | $ | 10,167,963 | | | | | $ | (18,046) | | | | | $ | (115,779) | | | | | $ | (4,611) | | | | | $ | 16,236 | | | | | $ | 10,045,763 | |

DECEMBER 31, 2021

1.

Management evaluates whether an entity or interest is a variable interest entity and whether the Company is the primary beneficiary; consolidation is required if both criteria are met.

Certain of the Company's midstream gathering systems are not wholly-owned but are operated by the Company pursuant to a construction, ownership and operation agreement.

The Company records the pro rata share of revenues, expenses, assets and liabilities it is entitled under the agreement.

| | | | 2021 | | | | | | 2020 | | |

| | | | 2021 | | | | | | 2020 | | |

There were no additional indicators of impairment identified in 2021.

*Equity Method Investments.* The Company applies the equity method of accounting to its investments over which it does not have the power to direct the activities that most significantly impact the investment's economic performance.

The carrying value of the Company's equity method investments is recorded in other assets in the Consolidated Balance Sheets.

The Company's pro-rata share of earnings in equity method investments is recorded in (income) loss from investments in the Statements of Consolidated Operations.

| | | | 2021 | | | | | | 2020 | | |

| Accrued severance | | | 3,815 | | | | | | 2,536 | | |

When evaluating whether or not a valuation allowance should be established, the Company exercises judgment on whether it is more likely than not (a likelihood of more than 50%) that a portion or all of the deferred tax assets will not be realized.

To determine whether a valuation allowance is needed, the Company considers all available evidence, both positive and negative, including carrybacks, tax planning strategies, reversals of deferred tax assets and liabilities and forecasted future taxable income.

To determine the amount of financial statement benefit recorded for uncertain tax positions, the Company considers the amounts and probabilities of outcomes that could be realized upon ultimate settlement of an uncertain tax position using facts, circumstances and information available at the reporting date.

| | | | 2021 | | | | | | 2020 | | |

| | | | | | | | | | | | |

| [Statements of Consolidated Operations for each of the three years in the period ended December 31, 2020](#i43f68b92b00b4f60b7eb2031407a74f6_64) | | | | | | [67](#i43f68b92b00b4f60b7eb2031407a74f6_64) | | |

| [Statements of Consolidated Comprehensive Income for each of the three years in the period ended December 31, 2020](#i43f68b92b00b4f60b7eb2031407a74f6_67) | | | | | | [68](#i43f68b92b00b4f60b7eb2031407a74f6_67) | | |

| [Consolidated Balance Sheets as of December 31, 2020 and 2019](#i43f68b92b00b4f60b7eb2031407a74f6_79) | | | | | | [69](#i43f68b92b00b4f60b7eb2031407a74f6_79) | | |

| [Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 2020](#i43f68b92b00b4f60b7eb2031407a74f6_73) | | | | | | [70](#i43f68b92b00b4f60b7eb2031407a74f6_73) | | |

| [Statements of Consolidated Equity for each of the three years in the period ended December 31, 2020](#i43f68b92b00b4f60b7eb2031407a74f6_85) | | | | | | [71](#i43f68b92b00b4f60b7eb2031407a74f6_85) | | |

[Table of](#i43f68b92b00b4f60b7eb2031407a74f6_7) [Contents](#i43f68b92b00b4f60b7eb2031407a74f6_7)

| | | | | | |

| --- | --- | --- | --- | --- | --- |

Accounting for the Equitrans gas gathering agreement

| *Description of the Matter* | | | As more fully described in Note 5 to the consolidated financial statements, on February 26, 2020, the Company entered into the Share Purchase Agreements and the Consolidated Gas Gathering Agreement (the Consolidated GGA) pursuant to which, among other things, the Company sold to Equitrans Midstream 50% of its ownership of Equitrans Midstream's common stock in exchange for approximately $52 million in cash and rate relief under certain of the Company's gathering contracts with EQM, an affiliate of Equitrans Midstream. The Consolidated GGA provides for additional cash bonus payments (the Henry Hub Cash Bonus) payable by the Company to EQM conditioned upon the quarterly average of the NYMEX Henry Hub natural gas settlement price exceeding certain price thresholds during a specified period. The Company’s initial entry to record this transaction included recognition of a contract asset representing the estimated fair value of the rate relief provided by the Consolidated GGA of $410 million and a derivative liability related to the Henry Hub Cash Bonus of approximately $117 million. The determination of fair value of these components included significant judgment and assumptions by management, including an estimated production volume forecast, future commodity prices and price volatility, and a market-based discount rate. Auditing the Company's initial accounting for the Consolidated GGA contract asset and Henry Hub Cash Bonus derivative liability involved a high degree of subjectivity as the determination of fair values was based on assumptions as described above about future market and economic conditions. Additionally, a detailed analysis of the terms of the relevant agreements was required to determine the existence of any derivatives that may require separate accounting under applicable accounting guidance. | | |

| *How We Addressed the Matter in Our Audit* | | | We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s accounting for the Consolidated GGA. For example, we tested controls over management's assessment of the appropriateness of the significant assumptions outlined above that are inputs to the fair value calculations. We also tested management’s evaluation of the Consolidated GGA and the identification and evaluation of specific features and the related accounting. To test the initial accounting for the Consolidated GGA, our audit procedures included, among others, inspection of the underlying agreement and testing management’s application of the relevant accounting guidance, including the determination of the balance sheet classification of each transaction component and the identification of any derivatives included in the arrangements. We involved professionals with specialized skill and knowledge to assist in evaluating the appropriateness of the accounting for the Consolidated GGA, including conclusions reached with respect to identification and bifurcation of embedded features. Our testing of the Company’s estimate of fair value of the contract asset and derivative liability related to the Henry Hub option included, among other procedures, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data. The audit effort involved the use of our valuation specialists to assist in evaluating the appropriateness of the methodology used in the cash flow models, as well as testing the significant market-related assumptions, such as future commodity prices and the market-based discount rate, used to develop the fair value estimates. | | |

Convertible Notes Issuance

| *Description of the Matter* | | | As described in Note 10 to the consolidated financial statements, in April 2020, the Company issued $500 million of aggregate principal of 1.75% convertible senior notes due May 2026 in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended. Additionally, the Company entered into separate capped call transactions to reduce potential dilution to the Company’s common stock upon any conversion of the Convertible Notes. These transactions are collectively referred to as the Convertible Notes Transactions. To account for the Convertible Notes, the Company was required to separate the Convertible Notes into liability and equity components. The carrying amount of the liability component was calculated by measuring the fair value of similar debt instruments that do not have an associated conversion feature. The carrying amount of the equity component was determined by deducting the fair value of the liability component from the principal value of the Convertible Notes. Auditing the Company’s accounting for the Convertible Notes Transactions was complex due to the judgment that was required in determining the balance sheet classification of the elements of the Convertible Notes. Additionally, a detailed analysis of the terms of the Convertible Notes Transactions was required to determine the existence of any derivatives that may require separate accounting under applicable accounting guidance. | | |

| *How We Addressed the Matter in Our Audit* | | | We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Convertible Notes Transactions. For example, we tested the Company's controls over the initial recognition and measurement of the Convertible Notes Transactions, including the recording of the associated liability and equity components. We also tested the evaluation of the Convertible Notes and the identification and evaluation of specific features and the related accounting. To test the initial accounting for the Convertible Notes Transactions, our audit procedures included, among others, inspection of the agreements underlying the Convertible Notes Transactions and testing management’s application of the relevant accounting guidance, including the determination of the balance sheet classification of each transaction and the identification of any derivatives included in the arrangements. We involved professionals with specialized skill and knowledge to assist in evaluating the appropriateness of the accounting for the convertible notes, including conclusions reached with respect to identification and bifurcation of embedded features. | | |

Valuation of Acquired Proved Reserves

February 17, 2021

As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the assets acquired in the Chevron Acquisition, which are included in the 2020 consolidated financial statements of the Company and constituted 5% of total assets, as of December 31, 2020, and less than 1% of consolidated total operating revenues, for the year ended December 31, 2020.

Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of assets acquired in the Chevron Acquisition.

| Impairment of goodwill | | | — | | | | | | — | | | | | | 530,811 | | |

| Loss on investment in Equitrans Midstream Corporation | | | 314,468 | | | | | | 336,993 | | | | | | 72,366 | | |

| Loss from continuing operations | | | (967,176) | | | | | | (1,221,695) | | | | | | (2,380,920) | | |

| Income from discontinued operations, net of tax | | | — | | | | | | — | | | | | | 373,762 | | |

| Less: Net income from discontinued operations attributable to noncontrolling interests | | | — | | | | | | — | | | | | | 237,410 | | |

| Amounts attributable to EQT Corporation: | | | | | | | | | | | | | | | | | |

| Loss from continuing operations | | | $ | (967,166) | | | | | $ | (1,221,695) | | | | | $ | (2,380,920) | |

| Income from discontinued operations, net of tax | | | — | | | | | | — | | | | | | 136,352 | | |

| Loss from continuing operations | | | $ | (3.71) | | | | | $ | (4.79) | | | | | $ | (9.12) | |

| Income from discontinued operations | | | — | | | | | | — | | | | | | 0.52 | | |

| Natural gas, net of tax expense: $2,584 in 2018 | | | — | | | | | | — | | | | | | (4,625) | | |

| Interest rate, net of tax expense: $210 in 2019 and $80 in 2018 | | | — | | | | | | 387 | | | | | | 168 | | |

| Less: Comprehensive income from discontinued operations attributable to noncontrolling interests | | | — | | | | | | — | | | | | | 237,410 | | |

| Income tax receivable | | | — | | | | | | 298,854 | | |

| Investment in Equitrans Midstream Corporation | | | 203,380 | | | | | | 676,009 | | |

| Other assets | | | 230,374 | | | | | | 222,873 | | |

| Term Loan Facility borrowings | | | — | | | | | | 999,353 | | |

| Impairment of goodwill | | | — | | | | | | — | | | | | | 798,689 | | |

| Capital expenditures for discontinued operations | | | — | | | | | | — | | | | | | (732,727) | | |

| Capital contributions to Mountain Valley Pipeline, LLC | | | — | | | | | | — | | | | | | (820,943) | | |

| Proceeds and excess tax benefits from awards under employee compensation plans | | | — | | | | | | — | | | | | | 1,946 | | |

| Acquisition of 25% of Strike Force Midstream LLC | | | — | | | | | | — | | | | | | (175,000) | | |

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

Based on that evaluation, the Principal Executive Officer and Principal Financial Officer concluded that [removed: the Company's] [added: our] disclosure controls and procedures were effective as of the end of the period covered by this report.

[removed: The Company's management] [added: Management] is responsible for establishing and maintaining adequate internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act).

[removed: The Company's] [added: Our] internal control system is designed to provide reasonable assurance to [removed: the Company's] management and [added: our] Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

[removed: The Company's management] [added: Management] assessed the effectiveness of [removed: the Company's] [added: our] internal control over financial reporting as of December 31, [removed: 2020.][added: 2021.]

Based on this assessment, management concluded that [removed: the Company] [added: we] maintained effective internal control over financial reporting as of December 31, [removed: 2020.][added: 2021.]

Ernst & Young LLP (Ernst & Young), the independent registered public accounting firm that audited [removed: the Company's] [added: our] Consolidated Financial Statements, has issued an attestation report on [removed: the Company's] [added: our] internal control over financial [added: reporting.]

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

There were no changes in internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of [removed: 2020] [added: 2021] that have materially affected, or are reasonably likely to materially affect, [removed: the Company's] [added: our] internal control over financial reporting.

Management’s assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the assets acquired in the Chevron Acquisition on November 30, 2020.

Total assets acquired and total operating revenues represented approximately 5% of the Company’s consolidated total assets at December 31, 2020 and less than 1% of the Company’s consolidated total operating revenues for the year ended December 31, 2020.

[Table of](#i43f68b92b00b4f60b7eb2031407a74f6_7) [Contents](#i43f68b92b00b4f60b7eb2031407a74f6_7)

reporting.

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

PART III

Not Applicable.

PART III

The following information is incorporated herein by reference from [removed: the Company's] [added: our] definitive proxy statement relating to the [removed: 2021] [added: 2022] annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the close of [removed: the Company's] [added: our] fiscal year ended December 31, [removed: 2020:][added: 2021:]

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

Information required by Item 401 of Regulation S-K with respect to executive officers is included after Item 4 at the end of Part I of this Annual Report on Form 10-K under the caption "Information about our Executive Officers (as of February [removed: 17, 2021)," and is incorporated herein by reference.][added: 10, 2022)."]

[removed: The Company has] [added: We have] adopted a code of business conduct and ethics applicable to all directors and employees, including the principal executive officer, principal financial officer and principal accounting officer.

[removed: The] [added: Our] code of business conduct and ethics is posted on [removed: the Company's] [added: our] website http://www.eqt.com (accessible by clicking on the "About" link on the main page, followed by the "Governance" heading, then the "Charters and Governance Documents" link), and a printed copy will be delivered free of charge on request by writing to the corporate secretary at EQT Corporation, c/o Corporate Secretary, 625 Liberty Avenue, Suite 1700, Pittsburgh, Pennsylvania 15222.

[removed: The Company intends] [added: We intend] to satisfy the disclosure requirement regarding certain amendments to, or waivers from, provisions of [removed: its] [added: our] code of business conduct and ethics by posting such information on [removed: the Company's] [added: our] website.

- Information required by Item 401 of Regulation S-K with respect to directors;

- Information required by Item 405 of Regulation S-K with respect to our compliance with Section 16(a) of the Exchange Act, if any;

- Information required by Item 407(d)(5) of Regulation S-K with respect to disclosure of our audit committee financial expert.

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

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

The following information is incorporated herein by reference from [removed: the Company's] [added: our] definitive proxy statement relating to the [removed: 2021] [added: 2022] annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the close of [removed: the Company's] [added: our] fiscal year ended December 31, [removed: 2020:][added: 2021:]