What changed in this filing

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Item 1A. Risk Factors

2023-02-16 compared with 2022-02-10 · 160 added, 122 removed, 364 unchanged (44% of the section changed)

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

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

• delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from permitting, wastewater disposal, emission 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;

• supply chain disruptions or labor shortage impacts, including as a result of the COVID-19 pandemic or other global pandemics;

• equipment failures, accidents or other unexpected operational events;

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issues related to compliance with environmental regulations;

environmental hazards, such as natural gas leaks, oil and diesel spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized releases of brine, well stimulation and completion fluids, toxic gases or other pollutants into the environment, especially those that reach surface water or groundwater;

inadvertent third-party damage to our assets, and natural disasters.

We also face various risks or threats to the operation and security of our or third parties' facilities and infrastructure, such as processing plants, compressor stations and pipelines.

environmental hazards, such as natural gas leaks, oil and diesel spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized releases of brine, well stimulation and completion fluids, wastewater, toxic gases or other pollutants into the environment, especially those that reach surface water or groundwater;

inadvertent third-party damage to our assets;

and natural disasters.

We also face various

risks or threats to the operation and security of our or third parties' facilities and infrastructure, such as processing plants, compressor stations and pipelines.

Any of these risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property, equipment and natural resources, pollution or other environmental damage, loss of hydrocarbons, disruptions to our operations, regulatory investigations and penalties, suspension of our operations, repair and remediation costs, and loss of sensitive confidential information.

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The occurrence of an event that is not fully covered by insurance could materially adversely affect our business, results of operations, cash flows and financial position.

A terrorist attack or armed conflict targeting our systems or natural gas infrastructure generally could materially adversely impact our operations.

Growing geopolitical instability and armed conflicts (including the armed conflict between Russia and Ukraine) has resulted in energy infrastructure becoming a more prominent target of attack by terrorists and conflicting countries.

Natural gas, NGLs and oil related facilities, including those operated by us or our service providers, could be direct targets of physical or cyber attacks, and, if infrastructure integral to our operations is destroyed or damaged, we may experience a significant disruption in our operations.

Any such disruption could materially adversely affect our financial condition, results of operations and cash flows.

Costs for insurance and other security may increase as a result of increased threats, and certain insurance coverage may become more difficult to obtain, if available at all.

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

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These well locations represent a significant part of our business strategy.

Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas, NGLs and oil prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results, lease expirations, topography, gathering system and pipeline transportation costs and constraints, access to and availability of water sourcing and distribution systems, coordination with coal mining, regulatory approvals and other factors.

Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas, NGLs and oil prices;

the availability and cost of capital;

drilling and production costs;

the availability of drilling services and equipment;

drilling results;

lease expirations;

gathering system and pipeline transportation costs and constraints;

access to and availability of sand and water and corresponding materials sourcing and distribution systems, including railroads;

coordination with coal mining;

regulatory approvals;

and other factors.

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

In addition, 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.

In addition, if production is not established within the spacing units covering our undeveloped acres in accordance with the requisite timeframe set forth in the applicable lease, our leases for such acreage will expire.

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

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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.

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, 2022, 2021 and 2020, we recorded impairment and expiration of leases of $176.6 million, $311.8 million and $306.7 million, respectively.

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

Our inability to cure any title defects in our leases in a timely and cost-efficient manner may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves.

The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial position.

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

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

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

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

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

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

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

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

Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as reserves are produced.

Future natural gas, NGLs and oil production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable.

Our future natural gas, NGLs and oil production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable.

We cannot be certain that we will be able to find or acquire and develop additional reserves at an acceptable cost.

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In accordance with SEC requirements, we based the discounted future net cash flows from our proved reserves on the twelve-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions.

Actual future net cash flows from our properties will be affected by factors such as the actual prices we receive for natural gas, NGLs and oil, the amount, timing and cost of actual production and changes in governmental regulations or taxation.

Actual future net cash flows from our reserves will be affected by factors such as the actual prices we receive for natural gas, NGLs and oil, the

amount, timing and cost of actual production and changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value.

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The estimated future cash flows used to test our proved oil and gas properties for recoverability are based on proved and, if determined reasonable by management, risk-adjusted probable reserves, utilizing assumptions generally consistent with the assumptions used by our management for internal planning and budgeting purposes.

Key assumptions used in our analyses, include, among other things, the intended use of the asset, the anticipated production from reserves, future market prices for natural gas, NGLs and oil, future operating costs, inflation and the anticipated proceeds that may be received upon divestiture if there is a possibility that the asset will be divested prior to the end of its useful life.

Key assumptions used in our analyses include, among other things, the intended use of the asset, the anticipated production from reserves, future market prices for natural gas, NGLs and oil, future operating and development costs, inflation and the anticipated proceeds that may be received upon divestiture if there is a possibility that the asset will be divested prior to the end of its useful life.

Commodity pricing is estimated by using a combination of the five-year NYMEX forward strip prices and assumptions related to gas quality, locational basis adjustments and inflation.

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Such charges could be material to our results of operations and could adversely affect our results of operations and financial position.

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

See "Critical Accounting Policies and Estimates" included in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 to the Consolidated Financial Statements for a discussion of our accounting policies and significant assumptions related to accounting for natural gas, NGLs and oil producing activities and impairment of our oil and gas properties.

Financial and Market Risks Applicable to Our Business

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

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

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

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.

The prices for natural gas, NGLs and oil have historically been volatile and have been particularly volatile in recent years.

The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $9.85 per MMBtu to a low of $3.46 per MMBtu between the period from January 1, 2022 through December 31, 2022, and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of $123.64 per barrel to a low of $71.05 per barrel during the same period.

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

We expect commodity price volatility to continue or increase in the future due to rising macroeconomic uncertainty and geopolitical tensions, including the Russian invasion of Ukraine, which began in February 2022 and has put upward pressure on natural gas and oil prices.

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

• weather conditions and seasonal trends;

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

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

• national and worldwide economic and political conditions;

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

• national and worldwide economic and political conditions, particularly those in, or affecting, other countries which are significant producers of natural gas and/or oil;

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

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

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

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

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.

However, due to the volatility of commodity prices and the multitude of external factors that impact commodity prices, many of which are unknown and unforeseeable, we are unable to predict with certainty future potential movements in the market prices for natural gas, NGLs and oil.

The success of our plans and strategies could be negatively affected if our projections of future hydrocarbon prices are significantly different from the ultimate actual price.

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

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

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

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

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

Reduced cash flows could also result in us having to make downward adjustments to our financial projections, such as free cash flow, and could cause us to revise our shareholder returns initiatives, including the amount of dividends paid on our common stock, which could negatively impact the price of our common stock and our ability to access the capital markets.

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

See "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.

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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.

In addition, to the

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

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

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

A financial crisis or deterioration in general economic, business or geopolitical conditions could materially adversely affect our operations and financial condition.

Concerns over global economic conditions, stock market volatility, energy costs, geopolitical issues (including continued hostilities between Russia and Ukraine), inflation and U.S.

Federal Reserve interest rate increases in response thereto, the availability and cost of credit, and slowing of economic growth in the United States and abroad and fears of a recession have contributed and may continue to contribute to increased economic uncertainty and diminished expectations for the global economy.

Global economic conditions, geopolitical issues and inflation have constrained global and domestic supply chains, which has impacted and could in the future continue to impact our ability to develop our reserves in accordance with our drilling and completions schedule.

Additionally, global economic conditions have a significant impact on commodity prices and any stagnation or deterioration in global economic conditions could result in decreased demand and, thus, lower prices for natural gas, NGLs or oil.

Such uncertainty could also result in higher natural gas, NGL and oil prices, which could potentially result in increased inflation worldwide and could negatively impact demand for natural gas, NGLs and oil.

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

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

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

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

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

In December 2021, we outlined a leverage and debt retirement strategy with the goal of retiring a significant amount of our total debt by the end of 2023 (our Debt Retirement Plan).

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

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

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

Our 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 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.

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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, 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).

As of December 31, 2022, our senior notes were rated "Ba1" with a "positive" outlook by Moody's Investors Services (Moody's), "BBB-" with a "stable" outlook by Standard & Poor's Ratings Service (S&P) and "BBB-" with a "stable" outlook by Fitch Ratings Service (Fitch).

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

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

Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our lines of credit, the interest rate on 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.

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

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

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

Our debt agreements also require compliance with certain covenants.

Our debt agreements also require us to comply with certain covenants.

If the price that we receive for our natural gas, NGLs and oil production deteriorates from current levels or continues for an extended period, it could lead to reduced revenues, cash flow and earnings, which in turn could lead to a default due to lack of covenant compliance.

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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, 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.

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 $4.6 billion loss in 2022 and 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.

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If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

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

On April 28, 2020, we issued the Convertible Notes (defined in Note 10 to the Consolidated Financial Statements) due May 1, 2026 unless earlier redeemed, repurchased or converted.

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

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

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

We will report lower net income (or greater net loss) in our financial results because GAAP requires interest to include both the current period's amortization of the debt discount and the instrument's coupon interest, which could adversely affect our reported or future financial results, the market price of our common stock and the trading price of the Convertible Notes.

In addition, because we have the ability and intent to settle the Convertible Notes, upon conversion, by paying or delivering cash equal to the principal amount of the obligation and common stock for amounts over the principal amount, the shares issuable upon conversion of the Convertible Notes are accounted for using the treasury stock method and, as such, are not included in the calculation of diluted earnings per share except to the extent that the conversion value of the Convertible Notes exceeds their principal amount.

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

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

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

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

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

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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 and new venture 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 energy transition initiatives geared towards enhancing our strategy.

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

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Moreover, economic or other circumstances may change from those contemplated by our business plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

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

Our business and the natural gas and oil industry in general have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications, and the maintenance of our financial and other records has long been dependent upon such technologies.

Cyber incidents targeting our digital work environment or other technologies or energy infrastructure may adversely impact our operations.

Our business and the natural gas industry in general have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications, and the maintenance of our financial and other records has long been dependent upon such technologies.

We depend on this technology to record and store data, estimate quantities of natural gas, NGLs and oil reserves, analyze and share operating data and communicate internally and externally.

Computers and mobile devices control nearly all of the natural gas, NGLs and oil distribution systems in the U.S., which are necessary to transport our products to market.

government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats.

government has issued public warnings that indicate that energy assets might be specific targets of cyber or other security or physical threats, and the continuing armed conflict between Russia and Ukraine and associated economic sanctions on Russia may have increased the likelihood of such threats.

We can provide no assurance that we will not suffer such attacks in the future.

Deliberate attacks on, or unintentional events affecting, our digital work environment or other technologies and infrastructure, the systems or infrastructure of third parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery of natural gas, NGLs and oil, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, personal injury, property damage, other operational disruptions and third-party liability.

Further, as cyber incidents continue to evolve and cyber attackers become more sophisticated, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

Further, as cyber incidents continue to evolve and cyber attackers become more sophisticated, we may be required to expend additional resources to continue to

modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

The cost to remedy an unintended dissemination of sensitive information or data may be significant.

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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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Access to midstream assets may be unavailable due to market conditions or mechanical or other reasons.

In addition, at current commodity prices, construction of new pipelines and building of such infrastructure may occur more slowly.

In addition, due to regulatory and economic constraints, construction of new pipelines and building of such infrastructure may occur more slowly.

A lack of access to needed infrastructure, or an extended interruption of access to or service from third-party pipelines and facilities for any reason, including vandalism, terroristic acts, sabotage or cyber-attacks on such pipelines and facilities or service interruptions due to gas quality, could result in adverse consequences to us, such as delays in producing and selling our natural gas, NGLs and oil.

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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 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.

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

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

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

however this new fee structure does not take effect until the Mountain Valley Pipeline's in-service date.

There can be no assurance that the in-service date of the Mountain Valley Pipeline will not be delayed, or that the project will not be cancelled entirely, which would consequently delay, possibly indefinitely, the effective date of the fee reductions contemplated in the Consolidated GGA.

Neither Equitrans Midstream nor EQM is under any obligation to renegotiate their contracts with us, including the Consolidated GGA, in the event of a prolonged depressed commodity price environment or if the Mountain Valley Pipeline's in-service date is delayed.

We have recorded in our Consolidated Balance Sheet a contract asset of $410 million representing the estimated fair value of the rate relief provided by the Consolidated GGA that would be realized beginning with the Mountain Valley Pipeline’s in-service date.

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

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

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.

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.

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Further, insufficient takeaway capacity in the Appalachian Basin could cause significant fluctuations in our realized natural gas prices.

The Appalachian Basin has experienced periods in which production has surpassed local takeaway capacity, resulting in substantial discounts in the price received by producers such as us and others at times being possibly shut in.

Although additional Appalachian Basin takeaway capacity has been added in recent years, the existing and expected capacity may not be sufficient to keep pace with the increased production caused by accelerated drilling in the area in the short term.

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

Most recently, at COP27, President Biden announced the EPA’s proposed standards to reduce methane emissions from existing oil and gas sources, and agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas.

Various state and local governments have also publicly committed to furthering the goals of the Paris Agreement.

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.

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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.

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

On November 11, 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule.

Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to identify large emissions events, referred to in the proposed rule as “super emitters.” The EPA is expected to issue a final rule by May 2023.

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

In November 2021, Congress approved a $1 trillion legislative infrastructure package which includes a number of climate-focused spending initiatives targeted at climate resilience, enhanced response and preparation for extreme weather events, and clean energy and transportation investments.

The Inflation Reduction Act also provides significant funding and incentives for research and development of low-carbon energy production methods, carbon capture, and other programs directed at addressing climate change, including imposing a fee on a facility’s methane emissions in excess of a specified threshold.

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.

Pennsylvania became a member of RGGI in April 2022, though its membership is currently the subject of legal challenges.

Depending on the outcome of such litigation, Pennsylvania’s membership in RGGI will result in increased operating costs should we be required to purchase emission allowances in connection with our operations.

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

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

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.

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

Environmental, health and safety legal requirements govern discharges of substances into the air, ground and water;

Environmental and occupational health and safety legal requirements govern discharges of substances into the air, ground and water;

the management and disposal of hazardous substances and wastes;

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

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

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

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

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

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

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

Most recently, on August 16, 2022, legislation commonly known as the Inflation Reduction Act was signed into law.

Among other things, the Inflation Reduction Act includes a 1% excise tax on corporate stock repurchases, applicable to repurchases made after December 31, 2022, and also a new minimum tax based on book income.

We are in the process of evaluating the potential impacts of the Inflation Reduction Act to us.

While we do not currently expect the Inflation Reduction Act to have a material impact on our financial statements, our analysis of the effect of the Inflation Reduction Act on us is ongoing and incomplete, and it is possible that the Inflation Reduction Act (or implementing regulations and other guidance) could adversely impact our current and deferred federal tax liability.

Additionally, state and local taxing authorities in

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

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

We use financial derivative instruments to hedge the impact of fluctuations in natural gas, NGLs and oil prices on our results of operations and cash flows.

In 2010, Congress adopted the Dodd-Frank Act, which established federal oversight and regulation of the OTC derivative market and entities, such as us, that participate in that market.

The Dodd-Frank Act required the CFTC, the SEC and certain federal agencies that regulate the banking and insurance sectors (Prudential Regulators) to promulgate rules and regulations implementing the legislation.

Among other things, the Dodd-Frank Act established margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail their derivative activities.

Although some of the rules necessary to implement the Dodd-Frank Act have yet to be adopted, the CFTC, the SEC and Prudential Regulators have issued numerous rules, including the End-User Exception, which exempts certain "end-users" from having to comply with mandatory clearing, a Margin Rule mandating margining for certain uncleared swaps, and a Position Limits Rule imposing federal position limits on certain futures contracts relating to energy products, including natural gas.

We qualify as a "non-financial entity" for purposes of the End-User Exception and, as such, we are eligible for such exception.

As a result, our hedging activities are not subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing, although we are subject to certain recordkeeping and reporting obligations associated with such rule.

We also qualify as a "non-financial end user" for purposes of the Margin Rule;

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

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

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

In addition, the European Union and other non-U.S.

jurisdictions have enacted laws and regulations related to derivatives (collectively, Foreign Regulations) which apply to our transactions with counterparties subject to such Foreign Regulations.

The Dodd-Frank Act, the rules adopted thereunder and the Foreign Regulations could increase the cost of our derivative contracts, alter the terms of our derivative contracts, reduce the availability of derivatives to protect against the price risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, lessen the number of available counterparties and, in turn, increase our exposure to less creditworthy counterparties.

If our use of derivatives is reduced as a result of the Dodd-Frank Act, related regulations or the Foreign Regulations, our results of operations may become more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for, and fund, our capital expenditure requirements.

Any of these consequences could have a material and adverse effect on our business, financial position and results of operations.

As disclosed above in Item 1., "Business-Regulation," the Dodd-Frank Act, the rules adopted thereunder and various other foreign regulations could increase the cost of our derivative contracts, alter the terms of our derivative contracts, reduce the availability of derivatives to protect against the price risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and lessen the number of available counterparties and, in turn, increase our exposure to less creditworthy counterparties.

If our use of derivatives is reduced as a result of the Dodd-Frank Act, related regulations or such foreign regulations, our results of operations may become more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for, and fund, our capital expenditure requirements.

Any of these consequences could have a material adverse effect on our business, financial position and results of operations.

We have experienced increased, and anticipate additional, compliance costs and changes to current market practices as participants continue to adapt to a changing financial regulatory environment.

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We have been named from time to time as a defendant in litigation related to such matters.

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

conduct, our development programs.

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

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

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

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

The EPA is undergoing a rulemaking process to redefine the definition of WOTUS which could be impacted by the U.S.

Supreme Court's pending decision in Sackett v.

EPA, a case regarding the proper test in determining whether wetlands qualify as WOTUS.

A final rule, known as "Rule 1" was announced by the EPA and the Corps in December 2022.

The EPA and the Corps are expected to propose a second rule, known as "Rule 2," further refining Rule 1 by November 2023 and issue a final rule by July 2024.

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.

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

Securities class action and derivative lawsuits may be brought against us in connection with strategic transactions, such as the Tug Hill and XcL Midstream Acquisition, which could result in substantial costs and may delay or prevent such transactions from being completed.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements.

Even if such a lawsuit is without merit, defending against these

claims can result in substantial costs and divert management time and resources.

An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition.

Lawsuits that may be brought against us or our or their directors could also seek, among other things, injunctive relief or other equitable relief, including a request to enjoin us from consummating the acquisition.

One of the conditions to the closing of the Tug Hill and XcL Midstream Acquisition is that no court, tribunal or other governmental authority of competent jurisdiction has issued a final and non-appealable order, decree, judgment or law prohibiting the consummation of the Tug Hill and XcL Midstream Acquisition.

Consequently, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Tug Hill and XcL Midstream Acquisition, that injunction may delay or prevent the Tug Hill and XcL Midstream Acquisition from being completed within the expected timeframe or at all, which may adversely affect our business, financial position and results of operation.

Completion of the Tug Hill and XcL Midstream Acquisition is subject to conditions, including certain conditions that may not be satisfied or completed on a timely basis or at all.

Failure to complete the Tug Hill and XcL Midstream Acquisition could have material and adverse effects on us.

Completion of the Tug Hill and XcL Midstream Acquisition is subject to a number of conditions, including, among other things, the termination or expiration of the applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.

Such conditions, some of which are beyond our control, may not be satisfied or waived in a timely manner or at all and therefore make the completion and timing of the completion of the Tug Hill and XcL Midstream Acquisition uncertain.

In addition, the Tug Hill and XcL Midstream Purchase Agreement (defined in Note 6 to the Consolidated Financial Statements) contains certain termination rights for both us and the Sellers (defined in Note 6 to the Consolidated Financial Statements), which if exercised, will also result in the Tug Hill and XcL Midstream Acquisition not being consummated.

Furthermore, the governmental authorities from which the regulatory approvals are required may impose conditions on the completion of the Tug Hill and XcL Midstream Acquisition or require changes to the terms thereof.

Such conditions or changes and the process of obtaining regulatory approvals could have the effect of delaying or impeding consummation of the transactions or of imposing additional costs or limitations on us following completion of the Tug Hill and XcL Midstream Acquisition, any of which might have an adverse effect on us following completion of the Tug Hill and XcL Midstream Acquisition.

If the Tug Hill and XcL Midstream Acquisition is not completed, our ongoing business may be adversely affected and, without realizing any of the benefits of having completed the Tug Hill and XcL Midstream Acquisition, we will be subject to a number of risks, including the following:

• we will be required to pay our costs relating to the Tug Hill and XcL Midstream Acquisition, such as legal, accounting and financial advisory expenses, whether or not the transaction is completed;

• time and resources committed by our management to matters relating to the Tug Hill and XcL Midstream Acquisition could otherwise have been devoted to pursuing other beneficial opportunities;

• the market price of our common stock could decline to the extent that the current market price reflects a market assumption that the Tug Hill and XcL Midstream Acquisition will be completed.

In addition to the above risks, if the Tug Hill and XcL Midstream Purchase Agreement is terminated and our Board of Directors seeks another acquisition, our shareholders cannot be certain that we will be able to find a party willing to enter into a transaction as attractive to us as the Tug Hill and XcL Midstream Acquisition.

Also, if the Tug Hill and XcL Midstream Purchase Agreement is terminated under certain specified circumstances by the Sellers, the $150.0 million loan provided by us to the Upstream Seller (defined in Note 6 to the Consolidated Financial Statements), which would have been credited toward the cash consideration payable at the closing of the Tug Hill and XcL Midstream Acquisition, will be extinguished and we will not recover the principal or any interest thereunder.

We and the entities that we intend to acquire in the Tug Hill and XcL Midstream Acquisition (the Tug Hill and XcL Midstream Companies) will be subject to business uncertainties while the Tug Hill and XcL Midstream Acquisition is pending, which could adversely affect our business.

In connection with the pendency of the Tug Hill and XcL Midstream Acquisition, it is possible that certain persons with whom we or the Tug Hill and XcL Midstream Companies have a business relationship may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationships with us or the Tug Hill and XcL Midstream Companies, as the case may be, as a result of the Tug Hill and XcL Midstream Acquisition, which could negatively affect our or the Tug Hill and XcL Midstream Companies’ revenues, earnings and cash flows as well as the market price of our common stock, regardless of whether the Tug Hill and XcL Midstream Acquisition is completed.

Also, our and the Tug Hill and XcL Midstream Companies’ ability to attract, retain and motivate employees may be impaired until the Tug Hill and XcL Midstream Acquisition is completed, and our ability to do so may be impaired for a period of time thereafter, as current and prospective

employees may experience uncertainty about their roles within the company following the Tug Hill and XcL Midstream Acquisition.

Under the terms of the Tug Hill and XcL Midstream Purchase Agreement, both we and the Tug Hill and XcL Midstream Companies are subject to certain restrictions on the conduct of business prior to the effective time of the Tug Hill and XcL Midstream Acquisition, which may adversely affect our and the Tug Hill and XcL Midstream Companies’ ability to execute certain of our and their business strategies, including the ability in certain cases to modify or enter into certain contracts, acquire or dispose of certain assets, incur or prepay certain indebtedness, incur encumbrances, make capital expenditures or settle claims.

Such limitations could negatively affect our and the Tug Hill and XcL Midstream Companies’ businesses and operations prior to the completion of the Tug Hill and XcL Midstream Acquisition.

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

Successful property acquisitions require an assessment of a number of factors beyond our control.

These factors include estimates of recoverable reserves, exploration potential, future natural gas, NGLs and oil prices, operating costs, production taxes and potential environmental and other liabilities.

In particular, if the Tug Hill and XcL Midstream Acquisition is consummated, we may be unable to successfully integrate the acquired assets into our business or achieve the anticipated benefits of the Tug Hill and XcL Midstream Acquisition.

Successful property acquisitions, including assets we intend to acquire in the Tug Hill and XcL Midstream Acquisition, require an assessment of a number of factors beyond our control.

These factors include estimates of recoverable reserves;

exploration potential;

future natural gas, NGLs and oil prices and their appropriate differentials;

availability and cost of transportation of production to markets;

availability and cost of drilling equipment and of skilled personnel;

development and operating costs, including access to water;

production taxes;

potential environmental and other liabilities;

and regulatory, permitting and similar matters.

These assessments are complex and inherently imprecise.

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We do not inspect every well or lease that we acquire, and even when we inspect a well or lease we may not discover structural, subsurface, or environmental problems that may exist or arise.

In connection with our assessment of the assets of the Upstream Seller, we have performed a review of the subject properties that we believe to be generally consistent with industry practices.

The review was based on our analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines without review by an independent petroleum engineering firm.

Data used in such review was furnished by the Sellers or obtained from publicly available sources.

Our review may not reveal all existing or potential problems or permit us to fully assess the deficiencies and potential recoverable reserves for all of the Upstream Seller's assets, and the reserves and production related to the Upstream Seller's assets may differ materially after such data is reviewed by an independent petroleum engineering firm or further by us.

Inspections were not performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken.

There may be threatened or contemplated claims against the assets or businesses we acquire related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations.

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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.

Also, our ability to achieve the anticipated benefits of an acquisition, including the Tug Hill and XcL Midstream Acquisition, will depend in part upon whether we can integrate the acquired assets and their operations into our existing business in an efficient and effective manner.

The integration process may be subject to delays or changed circumstances, and we can give no assurance that acquired assets will perform in accordance with our expectations or that our expectations with respect to integration or cost savings as a result of an acquisition, such as the Tug Hill and XcL Midstream Acquisition, will materialize.

We will incur significant transaction costs in connection with the Tug Hill and XcL Midstream Acquisition.

We have incurred, and are expected to continue to incur, a number of non-recurring costs associated with the Tug Hill and XcL Midstream Acquisition, combining the operations of the acquired assets with ours and achieving desired synergies.

These costs have been, and will continue to be, substantial and, in many cases, will be borne by us whether or not the Tug Hill and XcL Midstream Acquisition is completed.

A substantial majority of non-recurring expenses will consist of transaction costs and include, among others, fees paid to financial, legal, accounting and other advisors and employee retention, severance and benefit costs.

We will also incur costs related to formulating and implementing integration plans.

Although we expect that the

elimination of duplicative costs, as well as the realization of synergies and efficiencies related to the integration of the acquired assets, should allow us to offset these transaction costs over time, this net benefit may not be achieved in the near term or at all.

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

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

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

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

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

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

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

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

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

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

However, we can offer no assurance that we will be able to complete such disposition or as to the value we will realize.

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

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

Unresolved Staff Comments

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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