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Item 1A. Risk Factors

2022-02-10 compared with 2021-02-17 · 126 added, 207 removed, 360 unchanged (48% of the section changed)

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Note that additional risks not presently known to us or that are currently considered immaterial may also have a negative impact on our business and operations.

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

Summary of Risk Factors

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

• Risks Associated with Natural Gas Drilling Operations.

As a natural gas producer, there are risks inherent in our primary business operations.

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

• Financial and Market Risks.

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

Additionally, our operations are capital intensive.

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

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 any of the events or circumstances described below actually occur, our business, financial condition or results of operations could suffer and the trading price of our common stock could decline.

Risks Associated with Natural Gas Drilling Operations

Drilling for and producing natural gas is a high-risk and costly activity with many uncertainties.

Our future financial position, cash flows and results of operations 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.

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

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

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

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

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

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

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

• equipment failures, accidents or other unexpected operational events;

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

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

• lack of available capacity on interconnecting transportation pipelines;

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

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

• issues related to compliance with environmental regulations;

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• public opposition to our operations;

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

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

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

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Because of these uncertain factors, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce natural gas, NGLs or oil from these or any other drilling locations.

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

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

Further, certain of the horizontal wells we intend to drill in the future may require pooling or unitization with adjacent leaseholds controlled by third parties.

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Such leases expire after an initial term, typically five years, unless certain actions are taken to preserve the lease.

we cannot preserve a lease, the lease terminates.

If we cannot preserve a lease, the lease terminates.

Approximately 10% of our net undeveloped acres are subject to leases that could expire over the next three years.

Lack of access to capital, changes in government regulations, changes in future development plans, reduced drilling activity, or the reduction in the fair value of undeveloped properties in the areas in which we operate could impact our ability to preserve, trade, or sell our leases prior to their expiration resulting in the termination and impairment of leases for properties that we have not developed.

Lack of access to capital, changes in government regulations, changes in future development plans or commodity prices, reduced drilling activity, or the reduction in the fair value of undeveloped properties in the areas in which we operate could impact our ability to preserve, trade or sell our leases prior to their expiration, resulting in the termination or impairment of leases for properties that we have not developed.

We evaluate capitalized costs of unproved oil and gas properties at least annually to determine recoverability on a prospective basis.

Indicators of potential impairment include changes brought about by economic factors, potential shifts in business strategy employed by management and historical experience.

Indicators of potential impairment include changes brought about by economic factors, potential shifts in our business strategy and historical experience.

The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches and drilling activity has not commenced.

For the years ended December 31, 2020, 2019 and 2018, we recorded lease impairments and expirations of $306.7 million, $556.4 million and $279.7 million, respectively.

For the years ended December 31, 2021, 2020 and 2019, we recorded impairment and expiration of leases of $311.8 million, $306.7 million and $556.4 million, respectively.

Refer to Note 1 to the Consolidated Financial Statements.

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Because the rate of production from natural gas and oil wells, and associated NGLs, generally declines as reserves are depleted, our future success depends upon our ability to develop additional reserves that are economically recoverable and to optimize existing well production, and our failure to do so may reduce our earnings.

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

Additionally, a failure to effectively and efficiently operate existing wells may cause production volume to fall short of our projections.

Our drilling and subsequent maintenance of wells can involve significant risks, including those related to timing, cost overruns and operational efficiency, and these risks can be affected by the availability of capital, leases, rigs, equipment, a qualified work force, and adequate capacity for the treatment and recycling or disposal of waste water generated in our operations, as well as weather conditions, natural gas, NGLs and oil price volatility, regulatory approvals, title and property access problems, geology, equipment failure or accidents and other factors.

Drilling for natural gas and oil can be unprofitable, not only from dry wells, but from productive wells that perform below expectations or that do not produce sufficient revenues to return a profit.

Low natural gas, NGLs and oil prices may further limit the types of reserves that we can develop and produce economically.

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As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate.

Any significant variance from our assumptions could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas, NGLs and oil, the classifications of reserves based on risk of recovery and estimates of the future net cash flows.

To the extent we experience a sustained period of reduced commodity prices, there is a risk that a portion of our proved reserves could be deemed uneconomic and no longer be classified as proved.

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

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

Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas, NGLs and oil we ultimately recover being different from our reserve estimates.

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Financial and Market Risks Applicable to Our Business

Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position.

Our revenue, profitability, future rate of growth, liquidity and financial position depend upon the prices for natural gas and, to a lesser extent, NGLs and oil.

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

Our primary business involves the exploration, production and sale of hydrocarbons, and in particular, natural gas.

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

The prices for natural gas, NGLs and oil have historically been volatile, and we expect this volatility to continue in the future.

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• the effect of energy conservation efforts;

• the price, availability and acceptance of alternative fuels;

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

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

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

• the level of global inventories;

• risks associated with drilling, completion and production operations;

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The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $23.86 per MMBtu to a low of $2.43 per MMBtu from January 1, 2021 through December 31, 2021, and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of $85.64 per barrel to a low of $47.47 per barrel during the same period.

In addition, the market price for natural gas in the Appalachian Basin continues to be lower relative to NYMEX Henry Hub as a result of significant increases in the supply of natural gas in the Northeast United States.

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

In addition, the market price for natural gas in the Appalachian Basin is typically lower relative to NYMEX Henry Hub as a result of the increased production and supply of natural gas in the Northeast United States.

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

NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, which adds further volatility to the pricing of NGLs.

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.

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.

Prolonged low, and/or significant or extended declines in, natural gas, NGLs and oil prices may adversely affect our revenues, operating income, cash flows and financial position, particularly if we are unable to control our development costs during periods of lower natural gas, NGLs and oil prices.

Declines in prices could also adversely affect our drilling activities and the amount of natural gas, NGLs and oil that we can produce economically, which may result in our having to make significant downward adjustments to the value of our assets and could cause us to incur non-cash impairment charges to earnings.

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

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

Lower prices for natural gas, NGLs and oil may also adversely affect our credit ratings and result in a reduction in our borrowing capacity and access to other capital.

See "Impairment of Oil and Gas Properties" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations." We are also exposed to the risk of non-performance by our hedge counterparties in the event that changes, positive or negative, in natural gas prices result in our derivative contracts having a positive fair value in our favor.

Further, adverse economic and market conditions could negatively affect the collectability of our trade receivables and cause our hedge counterparties to be unable to perform their obligations or to seek bankruptcy protection.

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

Increases in natural gas, NGLs and oil prices may be accompanied by or result in increased well drilling costs, increased production taxes, increased lease operating expenses, increased volatility in seasonal gas price spreads for our storage assets and increased end-user conservation or conversion to alternative fuels.

Significant natural gas price increases may subject us to margin calls on our commodity price derivative contracts (hedging arrangements, including swap, collar and option agreements and exchange-traded instruments), which would potentially require us to post significant amounts of cash collateral with our hedge counterparties.

The cash collateral provided to our hedge counterparties, which is interest-bearing, is returned to us in whole or in part upon a reduction in forward market prices, depending on the amount of such reduction, or in whole upon settlement of the related derivative contract.

In addition, to the extent we have hedged our current production at prices below the current market price, we will not benefit fully from an increase in the price of natural gas.

We are also exposed to the risk of non-performance by our hedge counterparties in the event that changes, positive or negative, in natural gas prices result in our derivative contracts having a positive fair value in our favor.

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

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.

If we are not able to successfully execute our Deleveraging Plan or otherwise reduce our absolute 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 strategic plans.

In December 2021, we reaffirmed our commitment to attaining investment grade credit metrics and outlined a leverage and debt reduction strategy with the goal of reducing our total debt by $1.5 billion by the end of 2023 (our Debt Reduction Plan).

We intend to fund our Debt Reduction Plan through free cash flow, and have aligned our hedge strategy in a manner that we believe will mitigate the risk of volatility of future natural gas and NGLs prices, which we anticipate will enable us to execute on our Debt Reduction Plan and other capital allocation strategies;

however, there can be no assurance that we will be able to generate sufficient free cash flow to execute our Debt Reduction Plan on our anticipated timeframe, if at all.

If we are not able to successfully execute our Debt Reduction Plan or otherwise reduce our total debt to a level we believe appropriate, our credit ratings may be lowered, we may reduce or delay our planned capital expenditures or investments, and we may revise or delay our shareholder returns strategy or other strategic plans.

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

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If we do not have sufficient borrowing availability under our credit facility, we may seek alternate debt or equity financing, sell assets or reduce our capital expenditures.

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

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

The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.

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

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

• our level of proved reserves and production;

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

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

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

Although we are not aware of any current plans of Moody's, S&P or Fitch to downgrade its rating of our senior notes, we cannot be assured that one or more of these rating agencies will not downgrade or withdraw entirely its rating of our senior notes.

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

Low prices for natural gas, NGLs and oil, an increase in the level of our indebtedness or other factors may result in Moody's, S&P or Fitch downgrading its rating of our senior notes.

Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our lines of credit, the interest rate on the Adjustable Rate Notes (defined in Note 10 to the Consolidated Financial Statements), the rates available on new long-term debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts.

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

As of December 31, 2020, we had approximately $4,925 million of debt outstanding, and we may incur additional indebtedness in the future.

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

Increases in our level of indebtedness may:

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In addition, we are exposed to credit risk related to our credit facility to the extent that one or more of our lenders may be unable to provide necessary funding to us under our existing line of credit if it experiences liquidity problems.

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.

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.

Industry organizations are attempting to structure the spread calculation in a manner that minimizes the possibility of value transfer between counterparties, borrowers, and lenders by the transition, but there is no assurance that the calculated spread will be fair and accurate.

At this time, it is not possible to predict the effect of any such changes, any establishment of alternative reference rates or any other reforms to LIBOR that may be implemented.

If LIBOR ceases to exist, we may need to renegotiate our credit facility to determine the interest rate to replace LIBOR with the new standard that is established.

As such, the potential effect of any such event on our interest expense cannot yet be determined.

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

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Such hedges are designed to lock in prices in order to limit volatility and increase the predictability of cash flow.

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

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

• our production is less than expected;

• the counterparties to our derivative contracts fail to perform on their contract obligations;

• 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.

These transactions limit our potential gains if natural gas, NGLs and oil prices rise above the price established by the hedge, and we may be required to post cash collateral or letters of credit with our hedge counterparties to the extent our liability under the derivative contract exceeds specified thresholds, which would negatively impact our liquidity.

We have previously sustained losses as a result of certain of our derivative arrangements (including a $3.8 billion loss in 2021), and we cannot assure you that we will not do so in the future.

In addition, derivative transactions may expose us to the risk of financial loss in certain circumstances, including instances in which our production is less than expected or an event materially impacts natural gas, NGLs or oil prices or the relationship between the hedged price index and the natural gas, NGLs or oil sales price.

We cannot be certain that any derivative transaction we may enter into will adequately protect us from declines in the prices of natural gas, NGLs or oil.

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In accordance with GAAP, an issuer must separately account for the liability and equity components of certain convertible debt instruments that may be settled entirely or partially in cash upon conversion in a manner that reflects the issuer's economic interest cost.

The effect on the accounting for the Convertible Notes is that the equity component is required to be included in additional paid-in capital of shareholders' equity on our 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.

The effect on the accounting for the Convertible Notes is that the equity component is required to be included in additional paid-in capital of shareholders' equity on our Consolidated Balance Sheet, and the value of the equity component is treated as a debt discount for purposes of accounting for the debt component of the Convertible Notes.

Accordingly, we will be required to record a greater amount of non-cash interest expense in current and future periods as a result of the amortization of the discounted carrying value of the Convertible Notes to their face amount over the term of the Convertible Notes.

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Further, under the treasury stock method, the transaction is accounted for as if the number of shares of common stock that would be necessary to settle such excess are issued.

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

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

If we are unable to use the treasury stock method in accounting for the shares issuable upon conversion of the Convertible Notes, our diluted earnings per share could be adversely affected.

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

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

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Our operational strategy focuses on developing several multi-well pads in tandem through a process known as combo-development.

We have allocated a

substantial portion of our financial, human capital and other resources to pursuing this strategy, including investing in new technologies and equipment, restructuring our workforce, and pursuing various ESG initiatives geared towards enhancing our strategy.

We have allocated a substantial portion of our financial, human capital and other resources to pursuing this strategy, including investing in new technologies and equipment, restructuring our workforce, and pursuing various ESG and new venture initiatives geared towards enhancing our strategy.

We may not realize some or any of the anticipated strategic, financial, operational, environmental and other anticipated benefits from our operational strategy and the corresponding investments we have made in pursuing our strategy.

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Historically, there have been shortages of personnel and equipment as demand for personnel and equipment has increased along with the number of wells being drilled.

Additionally, our operations may be disrupted or impaired if a significant portion of our or our service providers' employees or contractors are unable to work due to illness or if our field operations are suspended or temporarily shut-down or restricted due to control measures designed to contain the COVID-19 pandemic.

We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be.

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Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, or to timely obtain water sourcing permits or other rights, could adversely affect our operations.

Additionally, the imposition of new

environmental initiatives and regulations could include restrictions on our ability to obtain water or dispose of waste, which would adversely affect our business and results of operations, which could result in decreased cash flows.

In addition, federal and state regulatory agencies recently have focused on a 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 volumes or suspend operations.

Increased regulation and attention given to induced seismicity in the states where we operate could lead to restrictions on our disposal well injection volumes and increased scrutiny of and delay in obtaining new disposal well permits, which could result in increased operating costs, which could be material, or a curtailment of our operations.

Additionally, the imposition of new environmental initiatives and regulations could include restrictions on our ability to obtain water or dispose of waste, which would adversely affect our business and results of operations, which could result in decreased cash flows.

In addition, in recent years, federal and state regulatory agencies have investigated the possible connection between the operation of injection wells used for natural gas and oil waste disposal and increased seismic activity in certain areas.

In some cases, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volume or suspend operations.

Increased regulation and attention given to induced seismicity in the states where we operate could lead to restrictions on our disposal well injection volume and increased scrutiny of and delay in obtaining new disposal well permits, which could result in increased operating costs, which could be material, or a curtailment of our operations.

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

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The substantial majority of our midstream and water services are provided by one provider, EQM Midstream Partners LP (EQM), a wholly-owned subsidiary of Equitrans Midstream.

Therefore, any regulatory, infrastructure, or other events that materially adversely affect EQM's business operations will have a disproportionately adverse effect on our business and operating results as compared to similar events experienced by our other third-party service providers.

Therefore, any regulatory, infrastructure or other events that materially adversely affect Equitrans Midstream's business operations will have a disproportionately adverse effect on our business and operating results as compared to similar events experienced by our other third-party service providers.

Additionally, our midstream services contracts with EQM involve significant long-term financial and other commitments on our part, which hinders our ability to diversify our slate of midstream service providers and seek better economic and other terms for the midstream services that are provided to us.

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Historically, we have received the substantial majority of our natural gas gathering, transmission and storage and water services from EQM.

Additionally, on February 26, 2020, we executed a new gas gathering agreement with EQM (the Consolidated

GGA), which, among other things, consolidated the majority of our prior gathering agreements with EQM into a single agreement, established a new fee structure for gathering and compression fees charged by EQM, increased our minimum volume commitments with EQM, committed certain of our remaining undedicated acreage to EQM and extended our and EQM's contractual obligations with each other to 2035.

Additionally, on February 26, 2020, we executed a new gas gathering agreement with EQM (the Consolidated GGA), which, among other things, consolidated the majority of our prior gathering agreements with EQM into a single agreement, established a new fee structure for gathering and compression fees charged by EQM, increased our minimum volume commitments with EQM, committed certain of our remaining undedicated acreage to EQM and extended our and EQM's contractual obligations with each other to 2035.

Because we have significant long-term contractual commitments with EQM, we expect to receive the majority of our midstream and water services from EQM for the foreseeable future.

Therefore, any event, whether in our areas of operation or otherwise, that adversely affects EQM's operations, water assets, pipelines, other transportation facilities, gathering and processing facilities, financial condition, leverage, results of operations or cash flows will have a disproportionately adverse effect on our business and operating results as compared to similar events experienced by our other third-party service providers.

Accordingly, we are subject to the business risks of EQM, including the following:

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

Therefore, any event, whether in our areas of operation or otherwise, that adversely affects Equitrans Midstream's operations, water assets, pipelines, other transportation facilities, gathering and processing facilities, financial condition, leverage, results of operations or cash flows will have a disproportionately adverse effect on our business and operating results as compared to similar events experienced by our other third-party service providers.

Accordingly, we are subject to the business risks of Equitrans Midstream, including the following:

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

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

• acts of cybersecurity, sabotage or terrorism that could cause significant damage or injury to EQM's personnel, assets or infrastructure or lead to extended interruptions of EQM's operations;

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

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

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

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

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

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

Because these obligations involve significant long-term financial and other commitments on our part, they could reduce our cash flow during periods of low prices for natural gas, NGLs and oil when we may have lower volumes of natural gas and NGLs and therefore less of a need for capacity and storage, or the market prices for such pipeline and storage capacity services may be lower than what we are contractually obligated to pay to EQM.

Because these obligations involve significant long-term financial and other commitments on our part, they could reduce our cash flow during periods of low prices for natural gas, NGLs and oil when we may have lower volume of natural gas and NGLs and therefore less of a need for capacity and storage, or the market prices for such pipeline and storage capacity services may be lower than what we are contractually obligated to pay to EQM.

Further, the Consolidated GGA provides for a reduced fee structure for the gathering and compression fees charged by EQM;

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We review the contract asset for indications of impairment when events or circumstances indicate the carrying value may not be recoverable.

Although the Consolidated GGA provides a cash payment option that grants us the right to receive payments from EQM in the event that the Mountain Valley Pipeline in-service date has not occurred prior to January 1, 2022, future delays in the Mountain Valley Pipeline’s in-service date may nonetheless affect our ability to fully realize the value we recorded as a contract asset for the rate relief associated with the Consolidated GGA, which could adversely affect our results of operations in future periods.

Future delays in the Mountain Valley Pipeline's in-service date may affect our ability to fully realize the value we recorded as a contract asset for the rate relief associated with the Consolidated GGA, which could adversely affect our results of operations in future periods.

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

Substantially all of our producing properties are geographically concentrated in the Appalachian Basin.

As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by, and costs associated with, governmental regulation, state and local political activities, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other weather-related conditions, interruption of the processing or transportation of natural gas,

NGLs or oil and changes in state and local laws, judicial precedents, political regimes and regulations.

Such conditions could materially adversely affect our results of operations and financial position.

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If activism against oil and natural gas exploration and development persists or increases, there could be a material adverse effect on our business, financial condition and results of operations.

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

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

In February 2021, the U.S.

formally rejoined the Paris Agreement, an international treaty signed by nearly 200 counties which calls for countries to set their own GHG emissions targets and to be transparent about the measures they will implement to achieve their GHG emissions targets.

In furtherance of the objectives of the Paris Agreement, in April 2021, the Biden Administration announced goals aimed at reducing the U.S.’s GHG emissions by 50-52% (compared to 2005 levels) by 2030.

The federal government has correspondingly instituted several regulations and initiatives in alignment with the goal of reducing the U.S.’s GHG emissions.

In June 2021, President Biden signed legislation reinstituting regulations which were previously repealed by the Trump Administration establishing NSPS for methane and VOC from new and modified oil and natural gas production and natural gas processing and transmission facilities.

Additionally, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions.

Facilities required to obtain PSD permits for their GHG emissions also will be required to meet "best available control technology" standards that will be established by the states or, in some cases, by the EPA on a case‑by‑case basis.

Furthermore, in November 2021, the EPA announced proposed rules expanding upon the NSPS rule which, if instituted, would establish standards for existing wells, impose more frequent and stringent leak monitoring, and mandate that all pneumatic controllers have zero emissions.

Separately, there have also been several instances of proposed legislation at the federal level which seek to impose a fee on methane emissions.

Most recently, in November 2021, the U.S.

House of Representatives passed a budget reconciliation bill known as the Build Back Better Act.

The version of the bill approved by the House includes a provision that would impose charges on oil and gas facilities for their methane emissions.

Under the bill, the EPA would levy "methane fees" starting at $900 per ton in 2023, increasing to $1,200 in 2024 and then $1,500 in 2025 and each year thereafter.

The fee would apply to each ton of methane emissions in excess of 0.20% of the gas sold by the facility.

The bill is currently under review by the U.S.

Senate, and it is unclear at this time as to what the final terms of any proposed methane fee may be.

These federal rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits.

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

At the state level, several states including Pennsylvania have proceeded with a number of state and regional efforts aimed at tracking and/or reducing GHG emissions by means of cap-and-trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs.

In October 2019, Pennsylvania Governor Tom Wolf signed an Executive Order directing the PADEP to draft regulations establishing a cap-and-trade program under its existing authority to regulate air emissions, with the intent of enabling Pennsylvania to join RGGI, a multi-state regional cap-and-trade program comprised of several Eastern U.S.

In September 2020, the EQB approved promulgation of the RGGI regulation, and a public comment period and hearings regarding the regulation commenced at the end of 2020.

In September 2021, Pennsylvania’s Independent Regulatory Review Commission adopted a regulation approving Pennsylvania’s participation in RGGI;

however, in October 2021 the Pennsylvania Senate approved a resolution to block the state's participation in RGGI, and such resolution was subsequently approved by the Pennsylvania House in December 2021.

On January 10, 2022, Governor Wolf vetoed the Senate's resolution, and as a result, it is likely that Pennsylvania will join RGGI in 2022 unless the Pennsylvania legislature overrides the Governor's veto by the vote of two-thirds of the members of each of the Pennsylvania House and Senate.

In the event that Pennsylvania ultimately becomes a member of RGGI, it will result in increased operating costs if we are required to purchase emission allowances in connection with our operations.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations.

Substantial limitations on GHG emissions could also adversely affect demand for the natural gas, NGLs and oil we produce and lower the value of our reserves.

Further, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector.

Moreover, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities.

While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult to engage in exploration and production activities.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events;

if any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water and thus could have an adverse effect on our exploration and production operations.

See "Business-Regulation-Environmental, Health and Safety Regulation" for more information.

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

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and the unitization or pooling of properties.

Some states allow the statutory pooling and unitization of tracts to facilitate development and exploration, as well as joint

development of existing contiguous leases.

Some states allow the statutory pooling and unitization of tracts to facilitate development and exploration, as well as joint development of existing contiguous leases.

In addition, state conservation and natural gas and oil laws generally limit the venting or flaring of natural gas and may set production allowances on the amount of annual production permitted from a well.

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

Effective January 1, 2018, changes to certain U.S.

federal income tax laws were signed into law that impact us, including but not limited to:

changes to the regular income tax rate;

the elimination of the alternative minimum tax (AMT);

full expensing of capital equipment;

limited deductibility of interest expense;

and increased limitations on deductible executive compensation.

On March 27, 2020, the U.S.

Congress enacted the Coronavirus Aid, Relief, and Economic Security Act (CARES Act), which, among other things, includes provisions relating to net operating loss (NOL) carryback periods, AMT credit refunds and modifications to the net interest deduction limitations.

In particular, under the CARES Act, (i) for taxable years beginning before 2021, NOL carryforwards and carrybacks may offset 100% of taxable income, (ii) NOLs arising in 2018, 2019, and 2020 taxable years may be carried back to each of the preceding five years to generate a refund, and (iii) for taxable years beginning in 2019 and 2020, the base for interest deductibility is increased from 30% to 50% of EBITDA.

Members of Congress periodically introduce legislation to revise U.S.

federal income tax laws which could have a material impact on us.

The most significant potential tax law changes that could impact us include increases in the regular income tax rate, a new minimum tax based on net income, the expensing of intangible drilling costs or percentage depletion, the repeal of like-kind exchange tax deferral rules on real property and further limited deductibility of interest expense, any of which could adversely impact our current and deferred federal and state income tax liabilities.

The most significant potential tax law changes that could impact us include increases in the regular income tax rate, a new minimum tax based on net income, a new excise tax on stock repurchases, the repeal of expensing intangible drilling costs or percentage depletion, the repeal of like-kind exchange tax deferral rules on real property and further limited deductibility of interest expense, any of which could adversely impact our current and deferred federal and state income tax liabilities.

Most recently, in November 2021, the U.S.

House passed the Build Back Better Act, which includes some, but not all, of these proposals.

The bill is currently under review by the U.S.

Senate, and, it is unclear at this time, what, if any, changes to the tax laws applicable to us will be enacted.

State and local taxing authorities in jurisdictions in which we operate or own assets may enact new taxes, such as the imposition of a severance tax on the extraction of natural resources in states in which we produce natural gas, NGLs and oil, or change the rates of existing taxes, which could adversely impact our earnings, cash flows and financial position.

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therefore, our uncleared swaps are not subject to regulatory margin requirements.

Finally, although the Position Limits Rule does not go into effect with respect to energy products until January 1, 2022, we believe that the majority, if not all, of our hedging activities constitute bona fide hedging under the Position Limits Rule and will not be subject to the limitations under such rule.

Finally, we believe that the majority, if not all, of our hedging activities constitute bona fide hedging under the Position Limits Rule and are not materially impacted by the limitations under such rule.

However, many of our hedge counterparties and other market participants are not eligible for the End-User Exception, are subject to mandatory clearing and the Margin Rule for swaps with some or all of their other swap counterparties, and may be subject to the Position Limits Rule, which may affect the pricing and/or availability of derivatives for us.

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We use hydraulic fracturing in the completion of our wells.

Hydraulic fracturing typically is regulated by state natural gas and oil commissions, but the EPA has asserted federal regulatory authority.

For example, the EPA finalized rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants, and after a legal challenge by environmental groups, in July 2019, the EPA declined to revise the rules.

Hydraulic fracturing typically is regulated by state natural gas and oil commissions, but the EPA prohibits the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

Certain governmental reviews have been conducted or are underway that focus on the environmental aspects of hydraulic fracturing practices.

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These delays, costs and liabilities could arise under a wide range of federal, state and local laws and regulations relating to protection of the environment and occupational health and workplace safety, including regulations and enforcement policies that have tended to become increasingly strict over time, resulting in longer waiting periods to receive permits and other regulatory approvals.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.

Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those

actions were taken.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of clean-up and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.

In addition, claims for damages to persons or property, including natural resources, may result from the environmental and occupational health and workplace safety impacts of our operations.

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

For example, in June 2015, the EPA and the Corps issued a final rule under the CWA defining the scope of the EPA's and the Corps' jurisdiction over WOTUS, which was stayed nationwide in October 2015 pending resolution of several legal challenges.

The EPA and the Corps proposed a rule in July 2017 to repeal the WOTUS rule and announced their intent to issue a new rule defining the CWA's jurisdiction.

In January 2018, the U.S.

Supreme Court issued a decision finding that jurisdiction to hear challenges to the WOTUS rule resides with the federal district courts, which lifted the stay and resulted in a patchwork application of the rule in some states, but not in others.

In October 2019, the EPA issued a final rule repealing the WOTUS rule and the repeal rule became effective in December 2019.

In April 2020, the EPA and the Corps published the NWPR, which narrows the definition of WOTUS to four categories of jurisdictional waters and includes twelve categories of exclusions, including groundwater.

A coalition of states and cities, environmental groups, and agricultural groups have challenged the NWPR and a federal district court in Colorado stayed implementation of the rule.

The stay is limited to application of the rule in Colorado;

the rule has taken effect in all other states.

In addition, in an April 2020 decision defining the scope of the CWA that was handed down just days after the NWPR was published, the U.S.

For example, in June 2015, the EPA and the Corps issued a rule under the CWA defining the scope of the EPA's and the Corps' jurisdiction over WOTUS, which never took effect before being replaced by the NWPR in December 2019.

A coalition of states and cities, environmental groups, and agricultural groups challenged the NWPR, which was vacated by a federal district court in August 2021.

In addition, in an April 2020 decision further defining the scope of the CWA, the U.S.

Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit.

The Court rejected the EPA and Corps’ assertion that groundwater should be totally excluded from the CWA.

The Court’s decision is expected to bolster challenges to the NWPR.

On January 20, 2021, the Biden Administration announced it will review the NWPR in accordance with the January 20, 2021 Executive Order that revokes President Trump’s Executive Order 13778, which required review and reversal of the WOTUS rule.

The EPA and the Corps have requested to stay the litigation over the NWPR during the agencies’ review of the rule.

To the extent a rule expands the scope of the CWA's jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

The EPA is undergoing a rulemaking process to redefine the definition of waters of the United States;

in the interim, the EPA is using the pre-2015 definition.

To the extent a new rule or further litigation expands the scope of the CWA's jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

Such potential regulations or litigation could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which in turn could materially adversely affect our results of operations and financial position.

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

Our operations can be adversely affected by regulations designed to protect various wildlife.

The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in constraints on our exploration and production activities.

Our operations can be adversely affected by regulations designed to protect various wildlife, including threatened and endangered species and their critical habitat.

The implementation of measures to protect wildlife or the designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in constraints on our exploration and production activities.

This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages.

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The impact of the changing demand for natural gas and oil could adversely impact our earnings, cash flows and financial position.

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions.

These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.

In addition, the EPA has adopted rules requiring the monitoring

and reporting of GHG emissions from specified onshore and offshore natural gas and oil production sources in the United States on an annual basis, which include certain of our operations.

At the state level, several states including Pennsylvania have proceeded with regulation targeting GHG emissions.

Such state regulations could impose increased compliance costs on our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of federal legislation in recent years.

In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap-and-trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs.

In October 2019, Pennsylvania Governor Tom Wolf signed an Executive Order directing the PADEP to draft regulations establishing a cap-and-trade program under its existing authority to regulate air emissions, with the intent of enabling Pennsylvania to join the RGGI, a multi-state regional cap-and-trade program comprised of several Eastern U.S.

In September 2020, the Pennsylvania Environmental Quality Board approved promulgation of the RGGI regulation, and a public comment period and hearings regarding the regulation commenced at the end of 2020.

Based on the current timeline for implementation, final rulemaking is expected to be sent to the Pennsylvania Environmental Quality Board for review and approval in the fourth quarter of 2021, with the first year of compliance anticipated to begin in 2022.

Assuming Pennsylvania ultimately becomes a member of the RGGI in 2022, as currently anticipated, it will result in increased operating costs if we are required to purchase emission allowances in connection with our operations.

On an international level, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, which calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets.

The Paris Agreement was signed by the United States in April 2016 and entered into force on November 4, 2016;

however, the Paris Agreement does not impose any binding obligations on its participants.

In August 2017, the U.S.

Department of State officially informed the United Nations of the United States' intent to withdraw from the Paris Agreement, with such withdrawal becoming effective in November 2020.

However, on January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which will become effective in 30 days from such date.

Substantial limitations on GHG emissions could also adversely affect demand for the natural gas, NGLs and oil we produce and lower the value of our reserves.

Further, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector.

Moreover, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities.

While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult to engage in exploration and production activities.

Finally, it should be noted that a number of scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events;

See "Business-Regulation-Environmental, Health and Safety Regulation" for more information.

Risks Associated with Strategic Transactions

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In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties.

The Separation and Distribution may subject us to future liabilities.

In November 2018, we completed the Separation and Distribution (each defined and discussed in Note 8 to the Consolidated Financial Statements), resulting in the spin-off of Equitrans Midstream, a standalone publicly traded corporation that holds our former midstream business.

Pursuant to agreements we entered into with Equitrans Midstream in connection with the Separation, we and Equitrans Midstream are each generally responsible for the obligations and liabilities related to our respective businesses.

Pursuant to those agreements, we and Equitrans Midstream each agreed to cross-indemnities principally designed to allocate financial responsibility for the obligations and liabilities of our business to us and those of Equitrans Midstream's business to it.

However, third parties, including governmental agencies, could seek to hold us responsible for obligations and liabilities that Equitrans Midstream agreed to retain or assume, and there can be no assurance that the indemnification from Equitrans Midstream will be sufficient to protect us against the full amount of such obligations and liabilities, or that Equitrans Midstream will be able to fully satisfy its indemnification obligations.

Additionally, if a court were to determine that the Separation or related transactions were consummated with the actual intent to hinder, delay or defraud current or future creditors or resulted in Equitrans Midstream receiving less than reasonably equivalent value when it was insolvent, or that it was rendered insolvent, inadequately capitalized or unable to pay its debts as they become due, then it is possible that the court could disregard the allocation of obligations and liabilities agreed to between us and Equitrans Midstream, impose substantial obligations and liabilities on us and void some or all of the Separation-related transactions.

Any of the foregoing could adversely affect our results of operations and financial position.

If there is a later determination that the Distribution or certain related transactions are taxable for U.S.

If there is a later determination that our spin-off of Equitrans Midstream or certain related transactions are taxable for U.S.

federal income tax purposes because the facts, assumptions, representations or undertakings underlying the IRS private letter ruling and/or opinion of counsel are incorrect or for any other reason, significant liabilities could be incurred by us, our shareholders or Equitrans Midstream.

In connection with the Separation and Distribution, we obtained a private letter ruling from the IRS and an opinion of outside counsel regarding the qualification of the Distribution, together with certain related transactions, as a transaction that is generally tax-free, for U.S.

In connection with our 2018 spin-off of Equitrans Midstream as a separate, publicly-traded company, we obtained a private letter ruling from the IRS and an opinion of outside counsel regarding the qualification of the Distribution (defined and discussed in Note 9 to the Consolidated Financial Statements), together with certain related transactions, as a transaction that is generally tax-free, for U.S.

federal income tax purposes, under Sections 355 and 368(a)(1)(D) of the U.S.

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The IRS private letter ruling and the opinion of counsel are based on and rely on, among other things, various facts and assumptions, as well as certain representations, statements and undertakings of us and Equitrans Midstream, including those relating to the past and future conduct of us and Equitrans Midstream.

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

If any of these representations, statements or undertakings is, or becomes, inaccurate or incomplete, or if we or Equitrans Midstream breach any representations or covenants contained in any of the spin-off-related agreements and documents or in any documents relating to the IRS private letter ruling and/or the opinion of counsel, we and our shareholders may not be able to rely on the IRS private letter ruling or the opinion of counsel.

Notwithstanding receipt of the IRS private letter ruling and the opinion of counsel, the IRS could determine on audit that the Distribution and/or certain related transactions should be treated as taxable transactions for U.S.

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federal and state income tax liabilities.

In connection with the Separation, we and Equitrans Midstream entered into a tax matters agreement, which described the sharing of any such liabilities between us and Equitrans Midstream.

In connection with the spin-off, we and Equitrans Midstream entered into a tax matters agreement, which described the sharing of any such liabilities between us and Equitrans Midstream.

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

Following the Separation and Distribution, we retained approximately 19.9% of the outstanding shares of Equitrans Midstream's common stock.

Following the spin-off of Equitrans Midstream, we retained approximately 19.9% of the outstanding shares of Equitrans Midstream's common stock.

On February 26, 2020, we entered into share purchase agreements with Equitrans Midstream to sell approximately 50% of our equity interest in Equitrans Midstream to Equitrans Midstream (the Equitrans Share Exchange) in exchange for a combination of cash and fee relief under our gathering agreements with EQM.

We currently own 25,296,026 shares of Equitrans Midstream's common stock.

The value of our investment in Equitrans Midstream may be adversely affected by negative changes in its results of operations, cash flows and financial position, which may occur as a result of the many risks attendant with operating in the midstream industry, including loss of gathering and transportation volumes, the effect of laws and regulations on the operation of its business and development of its assets, increased competition, loss of contracted volumes, adverse rate-making decisions, policies and rulings by the FERC, pipeline safety rulemakings initiated or finalized by the Department of Transportation's Pipeline and Hazardous Materials Safety Administration, delays in the timing of, or the failure to complete, expansion projects, lack of access to capital and operating risks and hazards.

We subsequently sold additional shares of our retained interest in Equitrans Midstream through open market sales and we currently own 22,796,026 shares of Equitrans Midstream's common stock.

The value of our investment in Equitrans Midstream may be adversely affected by negative changes in its results of operations, cash flows and financial position, which may occur as a result of the many risks attendant with operating in the midstream industry, including loss of gathering and transportation volume, the effect of laws and regulations on the operation of its business and development of its assets, increased competition, loss of contracted volume, adverse rate-making decisions, policies and rulings by the FERC, pipeline safety rulemakings initiated or finalized by the Department of Transportation's Pipeline and Hazardous Materials Safety Administration, delays in the timing of, or the failure to complete, expansion projects, lack of access to capital and operating risks and hazards.

We intend to dispose of our remaining interest in Equitrans Midstream through one or more divestitures of our shares of Equitrans Midstream's common stock.

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The occurrence of any of these and other risks faced by Equitrans Midstream could adversely affect the value of our investment in Equitrans Midstream.

Risks Related to the COVID-19 Pandemic

The novel coronavirus, or COVID-19, pandemic has affected and may materially adversely affect, and any future outbreak of any other highly infectious or contagious diseases may materially adversely affect, our operations, financial performance and condition, operating results and cash flows.

The COVID-19 pandemic has affected, and may materially adversely affect, our business and financial and operating results.

The severity, magnitude and duration of the COVID-19 pandemic is uncertain, rapidly changing and hard to predict.

In 2020, the pandemic significantly impacted economic activity and markets around the world, and, in the future, COVID-19 or another similar pandemic could negatively impact our business in numerous ways, including, but not limited to, the following:

• our revenue may be reduced if the pandemic results in an economic downturn or recession that leads to a prolonged decrease in the demand for natural gas and, to a lesser extent, NGLs and oil;

• our operations may be disrupted or impaired (thus lowering our production level), if a significant portion of our employees or contractors are unable to work due to illness or if our field operations are suspended or temporarily shut-down or restricted due to control measures designed to contain the pandemic;

• the operations of our midstream service providers, on whom we rely for the transmission, gathering and processing of a significant portion of our produced natural gas, NGLs and oil, may be disrupted or suspended in response to containing the pandemic, and/or the difficult economic environment may lead to the bankruptcy or closing of the facilities and infrastructure of our midstream service providers, which may result in substantial discounts in the prices

we receive for our produced natural gas, NGLs and oil or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties;

• the disruption and instability in the financial markets and the uncertainty in the general business environment may affect our ability to raise capital or find attractive asset monetization opportunities and successfully execute our Deleveraging Plan within our anticipated timeframe or at all.

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

Active development operations, including drilling and fracking operations, represent the greatest risk for transmission given the number of personnel and contractors on site.

While we believe that we are following best practices under COVID-19 guidance, the potential for transmission still exists.

In certain instances, it may be necessary or determined advisable for us to delay development operations.

To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other risks set forth herein, such as those relating to our financial performance, our ability to access capital and credit markets, our credit ratings and debt obligations.

The rapid development and fluidity of this situation precludes any prediction as to the ultimate adverse impact of COVID-19 on our business, which will depend on numerous evolving factors and future developments that we are not able to predict, including the length of time that the pandemic continues, its effect on the demand for natural gas, NGLs and oil, the response of the overall economy and the financial markets as well as the effect of governmental actions taken in response to the pandemic.

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

2 unchanged sentences

Our corporate headquarters is located in leased office space in Pittsburgh, Pennsylvania.

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

We also own or lease office space in Pennsylvania, West Virginia and Texas.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1A. Risk Factors