What changed in this filing

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Item 1. Business

2023-02-16 compared with 2022-02-10 · 194 added, 142 removed, 354 unchanged (49% of the section changed)

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In the drilling stage, rigs spend more time drilling and less time transitioning to new sites.

Advanced planning, a prerequisite to pursuing combo-development, facilitates the delivery of bulk hydraulic fracturing sand and piped fresh water (as opposed to truck-transported water), the ability to continuously meet completions supply needs and the use of environmentally friendly technologies.

Advanced planning, a prerequisite to pursuing combo-development, facilitates the delivery of bulk hydraulic fracturing sand and piped fresh and recycled water (as opposed to truck-transported water), and provides the ability to continuously meet completions supply needs and the use of environmentally friendly technologies.

Operational efficiencies realized from combo-development are passed on to our service providers, which reduces overall contract rates.

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and engaging with stakeholders to understand, and align our actions with, their needs and expectations.

Combo-development, when compared to similar production from non-combo-development operations, translates into fewer trucks on the road, decreased fuel usage, shorter periods of noise pollution, fewer areas impacted by midstream pipeline construction and shortened duration of site operations, all of which fosters a greater focus on safety and environmental protection.

Combo-development projects require significant advanced planning, including the establishment of a large, contiguous leasehold position;

We believe that combo-development projects are key to delivering sustainably low well costs and higher returns on invested capital.

Our business model has been developed to enable us to generate sustainable free cash flow and correspondingly, we have implemented a robust capital allocation strategy directed at responsibly developing our assets while also returning capital to our shareholders through a combination of dividends, strategic share repurchases, and debt retirements.

We are also focused on maintaining investment grade credit metrics, which allows us to capture a lower cost of capital and further enhance shareholder returns.

Our strategy, and combo-development projects in particular, requires significant advanced planning, including the establishment of a large, contiguous leasehold position;

the advanced acquisition of regulatory permits and sourcing of fracturing sand and water;

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Without a modern, digitally-connected operating model or an acreage position that enables operations of this scale, combo-development would not be possible.

Furthermore, we believe the benefits of our operating model can be magnified through select strategic transactions, and part of our strategy includes creating value through mergers and acquisitions, divestitures, joint ventures and similar business transactions, as well as investing in energy transition opportunities directed at complementing, and in certain cases diversifying, our core business operations.

We believe that our proprietary digital work environment, in conjunction with the size and contiguity of our asset base, uniquely position us to execute on a multi-year inventory of combo-development projects in our core acreage position.

Our operational strategy employs this differentiation to advance our mission of being the operator of choice for all stakeholders.

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

We believe our business model is sustainable and we expect to generate significant free cash flow over the next six years.

Our capital allocation plan is focused on reducing our debt and leverage, while also returning capital to shareholders through a combination of dividends and a share repurchase program.

We are focused on achieving and maintaining investment grade credit metrics as well as regaining our investment grade credit rating in the near term, which will allow us to capture a lower cost of capital and enhance shareholder returns.

Our operational strategy employs this differentiation to advance our mission of being the operator of choice for all stakeholders, while simultaneously helping to address energy security and affordability both domestically and globally.

2022 Highlights

• Achieved 2021 sales volume of 1,858 Bcfe, average daily sales volume of 5.1 Bcfe per day;

received an average realized price of $2.50 per Mcfe.

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

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

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

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

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

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

In 2022, we expect to spend approximately $1.30 to $1.45 billion in total capital expenditures, excluding amounts attributable to noncontrolling interest.

• Generated $3,466 million of net cash provided by operating activities.

• Achieved investment grade credit ratings from Fitch and S&P and upgraded to positive outlook at Moody's.

• Delivered on our capital return strategy through debt retirements, share buybacks and dividends.

◦ Repaid or repurchased $826 million aggregate principal of senior notes.

◦ Repurchased $85 million aggregate principal of convertible notes, reducing our fully diluted share count by 5.7 million shares.

◦ Repurchased $393 million of common stock, reducing our share count by 13.1 million shares.

◦ Increased quarterly base dividend by 20% to $0.15 per share ($0.60 per share annualized).

◦ Paid $204 million in dividends to shareholders.

• Authorized to repurchase up to $2.0 billion of our shares through December 31, 2023.

• Announced agreement to acquire Tug Hill and XcL Midstream.

• Added to the S&P 500 Index, joining top companies across all sectors of the U.S.

• Successfully completed our initiative to eliminate natural gas-powered pneumatic devices from our production operations, meaningfully reducing our methane and carbon emissions.

• Announced Appalachian Regional Clean Hydrogen Hub (ARCH2) collaboration with the State of West Virginia and leading energy and technology companies.

• Announced Appalachian Methane Initiative (AMI) collaboration to further enhance methane monitoring throughout the Appalachian Basin.

In 2023, we expect to spend approximately $1.7 to $1.9 billion in total capital expenditures, excluding amounts attributable to noncontrolling interests and acquisitions.

We expect to allocate the planned capital expenditures as follows:

approximately $1.0 to $1.1 billion to fund reserve development, approximately $110 to $130 million to fund land and lease acquisitions, approximately $120 to $160 million to fund other production infrastructure and approximately $55 to $75 million applied towards capitalized overhead.

Our 2022 capital expenditure program is expected to deliver sales volume of 1,950 to 2,050 Bcfe.

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

In addition, we announced our plan to return capital to shareholders, which included the commencement of a share repurchase program, under which we are authorized to repurchase $1.0 billion of our outstanding common stock, and the reinstatement of a quarterly cash dividend at an annual rate of $0.50 per share of our common stock starting in the first quarter of 2022.

Our capital allocation plan is focused on maintaining production volumes.

We have aligned our hedge strategy in a manner that we believe will mitigate the risk of volatility of future natural gas and NGLs prices, which will enable us to execute on our capital expenditure, debt reduction and shareholder return strategy.

approximately $1,400 to $1,535 million to fund reserve development, approximately $120 to $140 million to fund land and lease acquisitions, approximately $125 to $160 million to fund other production infrastructure and approximately $55 to $65 million applied towards capitalized overhead.

In 2023, we expect our sales volume to be 1,900 to 2,000 Bcfe, excluding amounts attributable acquisitions.

We are committed to maintaining investment grade credit metrics and we have a goal to retire at least $4.0 billion of our debt between January 1, 2022 and December 31, 2023, subject to the occurrence and timing of the closing of the Tug Hill and XcL Midstream Acquisition and the overall performance of the commodity markets.

Our capital allocation plan is focused on maintaining production volumes while also returning capital to shareholders, including through our share repurchase program, under which we are authorized to repurchase up to $2.0 billion of our outstanding common stock, and through our quarterly cash dividend, which is currently an annual rate of $0.60 per share.

Furthermore, we have aligned our hedge strategy in a manner that we believe will mitigate the risk of volatility of future natural gas and NGLs prices, thereby enabling us to execute on our capital expenditure, debt retirement and shareholder return strategy.

Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our reserves of, natural gas, NGLs and oil.

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Any such impairments or downward adjustments to our estimated reserves could potentially be material to us.

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

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.

See also Item 1A., "Risk Factors – Natural gas, NGLs and oil price declines, and changes in our development strategy, have resulted in impairment of certain of our assets.

Future declines in commodity prices, increases in operating costs or adverse changes in well performance or additional changes in our development strategy may result in additional write-downs of the carrying amounts of our assets, including long-lived intangible assets, which could materially and adversely affect our results of operations in future periods."

Segment and Geographical Information

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December 31, 2022

Marcellus Upper Devonian Ohio Utica Other Total

Marcellus Ohio Utica Other Total

Proved developed reserves 16,718 708 88 17,514

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Net proved undeveloped drilling locations 194 106 1 301

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

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

Our 2022 total proved reserves increased by 41 Bcfe, or 0.2%, compared to 2021 due to extensions, discoveries and other additions of 2,495 Bcfe and acquisitions of 141 Bcfe from the 2022 Asset Acquisition (defined in Note 6 to the Consolidated Financial Statements), partly offset by production of 1,940 Bcfe and revisions to previous estimates of 655 Bcfe.

Our 2022 proved undeveloped reserves decreased by 254 Bcfe, or 3.3%, compared to 2021.

The following table provides a rollforward of our proved undeveloped reserves.

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Balance at December 31, 2022 7,489

(a) Composed of (i) negative revisions of 819 Bcfe from proved undeveloped locations that are no longer expected to be developed within five years of initial booking as proved reserves as a result of changes to our development plan to support the continued implementation of our combo-development strategy;

and (ii) negative revisions of 62 Bcfe due primarily to changes in working interests and net revenue interests.

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

and (ii) 52 Bcfe from the extension of lateral lengths of proved undeveloped reserves.

(a) Composed of (i) negative revisions of 1,625 Bcfe related to proved undeveloped locations that are no longer expected to be developed as proved reserves within five years of initial booking as a result of development schedule changes, driven largely by third-party impacts, which has pushed planned completion dates into a future period from when originally planned;

and (ii) positive revisions of 518 Bcfe due primarily to changes in ownership interests.

(b) Composed of 2,077 Bcfe from proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2022 reserve development that expanded the number of our proven locations and additions to our five-year drilling plan.

As of December 31, 2022, we had zero wells with proved undeveloped reserves that had remained undeveloped for more than five years from their time of booking.

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

As of December 31, 2021, the standardized measure of our estimated future net cash flows from natural gas and crude oil reserves, which is calculated using average first-day-of-the-month closing prices for the prior twelve months (referred to as SEC pricing), was $17,281 million, as described in Note 18 to the Consolidated Financial Statements.

The following table provides the estimated future net cash flows, excluding open derivative contracts, from proved reserves, the present value of those net cash flows discounted at a rate of 10% (PV-10) and the prices used in projecting net cash flows over the past three years.

Our reserve estimates do not include any probable or possible reserves.

Years Ended December 31,

2022 2021 2020

(Millions, except prices)

Future net cash flow $ 87,612 $ 36,567 $ 7,543

Standardized measure of discounted future net cash flow 40,065 17,281 3,366

PV-10 (a) 51,512 21,496 3,967

Prices, including regional adjustments:

Natural gas price ($/Mcf) $ 5.543 $ 2.694 $ 1.380

NGLs price ($/Bbl) 38.66 29.95 11.97

Oil price ($/Bbl) 76.83 51.57 20.94

(a) PV-10 is a non-GAAP financial measure.

PV-10 is derived from the standardized measure of discounted future net cash flows (the Standardized Measure), which is the most directly comparable financial measure computed using U.S.

PV-10 differs from the Standardized Measure because it does not include the effects of income taxes on future net revenues.

We believe the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to proved reserves held by companies without regard to the specific income tax characteristics of such entities and is a useful measure of evaluating the relative monetary significance of our oil and natural gas properties.

Investors may utilize PV-10 as a basis for comparing the relative size and value of our proved reserves to other companies.

PV-10 should not be considered as a substitute for, or more meaningful than, the Standardized Measure as determined in accordance with U.S.

Neither PV-10 nor the Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties.

See below for a reconciliation of the Standardized Measure to PV-10.

Future net cash flows represent projected revenues from the sale of proved reserves, net of production and development costs (including transportation and gathering expenses, operating expenses and production taxes) and net of estimated income taxes.

Revenues are based on a twelve-month unweighted average of the first-day-of-the-month pricing, without escalation.

Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current economic conditions at each year-end.

There can be no assurance that the proved reserves will be produced in the future or that prices, production or development costs will remain constant.

There are numerous uncertainties inherent in estimating reserves and related information.

See Note 16 to the Consolidated Financial

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

The following table provides the reconciliation of the Standardized Measure to PV-10.

Years Ended December 31,

2022 2021 2020

Standardized measure of discounted future net cash flow $ 40,065 $ 17,281 $ 3,366

Estimated discounted income taxes on future net revenues 11,447 4,215 601

PV-10 $ 51,512 $ 21,496 $ 3,967

If the prices used in the calculation of the Standardized Measure instead reflected five-year strip pricing as of December 30, 2022 and held constant thereafter using (i) the NYMEX five-year strip adjusted for regional differentials using Texas Eastern Transmission Corp.

M-2, Transcontinental Gas Pipe Line, Leidy Line, and Tennessee Gas Pipeline Co., Zone 4-300 Leg for gas and (ii) the NYMEX WTI five-year strip for oil, adjusted for regional differentials consistent with those used in the standardized measure, and holding all other assumptions constant, our total proved reserves would be 24,913 Bcfe, the standardized measure of our discounted net future cash flows after taxes of our proved reserves would be $16,059 million and the discounted future net cash flows before taxes would be $19,672 million.

The average realized product prices weighted by production over the remaining lives of the properties would be $46.84 per barrel of oil, $27.22 per barrel of NGLs and $2.448 per Mcf of gas (compared to $51.57 per barrel of oil, $29.95 per barrel of NGLs and $2.694 per Mcf of gas using SEC pricing, as described in Note 18 to the Consolidated Financial Statements).

The NYMEX strip price proved reserves and related metrics are intended to illustrate reserve sensitivities to market expectations of commodity prices and should not be confused with SEC pricing proved reserves and do not comply with SEC pricing assumptions.

M-2, Transcontinental Gas Pipe Line, Leidy Line, and Tennessee Gas Pipeline Co., Zone 4-300 Leg for gas and (ii) the NYMEX WTI five-year strip for oil, adjusted for regional differentials consistent with those used in the Standardized Measure, and holding all other assumptions constant, our total proved reserves would be 24,971 Bcfe, the Standardized Measure after taxes of our proved reserves would be $22,625 million and the discounted future net cash flows before taxes would be $29,169 million.

The average realized product prices weighted by production over the remaining lives of the properties would be $50.13 per barrel of oil, $27.30 per barrel of NGLs and $3.565 per Mcf of gas.

The NYMEX strip price for proved reserves and related metrics are intended to illustrate reserve sensitivities to market expectations of commodity prices and should not be confused with SEC pricing for proved reserves and do not comply with SEC pricing assumptions.

We believe that the presentation of reserve volume and related metrics using NYMEX forward strip prices provides investors with additional useful information about our reserves because the forward prices are based on the market's forward-looking expectations of oil and gas prices as of a certain date.

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In addition, we use such forward-looking market-based data in developing our drilling plans, assessing our capital expenditure needs and projecting future cash flows.

While NYMEX strip prices represent a consensus estimate of future pricing, such prices are only an estimate and not necessarily an accurate projection of future oil and gas prices.

Actual future prices may vary significantly from the NYMEX prices;

While NYMEX strip prices represent a consensus estimate of future pricing, such prices are only an estimate and are not necessarily an accurate projection of future oil and gas prices.

Actual future prices may vary significantly from NYMEX prices;

therefore, actual revenue and value generated may be more or less than the amounts disclosed.

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Total $ 1,131 $ 828 $ 839

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

For the years ended December 31, 2022, 2021 and 2020, lease operating expenses, excluding production taxes per Mcfe were $0.08, $0.07 and $0.07, respectively.

The majority of our acreage is held by lease or occupied under perpetual easements or other rights acquired, for the most part, without warranty of underlying land titles.

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December 31, 2022

Pennsylvania West

Virginia Ohio Total

Pennsylvania West Virginia Ohio Total

Total gross productive acreage 465,353 133,541 52,480 651,374

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Average net revenue interest of proved developed reserves (a) 59.2 % 76.1 % 43.9 % 61.1 %

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

(a) As of December 31, 2022, the average net revenue interest of proved developed reserves was 79.8% for southwestern Pennsylvania and 30.5% for northeastern Pennsylvania.

We have an active lease renewal program in areas targeted for development.

In the event that production is not established or we do not extend or renew the terms of our expiring leases, 25,797, 27,728 and 17,096 of our net undeveloped acreage as of December 31, 2022 will expire in the years ending December 31, 2023, 2024 and 2025, respectively.

The following tables summarize our productive and in-process natural gas wells.

We had no productive or in-process oil wells as of December 31, 2021.

December 31, 2021

The following table summarizes our natural gas, NGLs and oil produced and sold volume by state.

Pennsylvania West Virginia Ohio Total

Year Ended December 31, 2022 1,493,568 323,113 123,362 1,940,043

Year Ended December 31, 2021 1,422,294 271,747 163,776 1,857,817

Year Ended December 31, 2020 1,051,869 267,708 178,215 1,497,792

Productive Wells

Total gross 4,527

Total net 3,510

In-process wells:

Total gross 282

Total net 248

The following table summarizes our productive and in-process natural gas wells.

We had no productive or in-process oil wells as of December 31, 2022.

December 31, 2022

Pennsylvania West Virginia Ohio Total

Productive wells:

Total gross productive wells (a) 3,666 744 287 4,697

Total net productive wells 2,758 702 143 3,603

In-process wells:

Total gross in-process wells 196 155 3 354

Total net in-process wells 165 142 1 308

(a) Of our total gross productive wells, there are 608 gross conventional wells in Pennsylvania and 3 gross conventional wells in West Virginia.

We have no gross conventional wells in Ohio.

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

During the years ended December 31, 2021, 2020 and 2019, we drilled zero net dry development, net productive exploratory and net dry exploratory wells.

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

Our sales volume in 2021 from the Marcellus Shale was 1,685 Bcfe.

The following table summarizes our produced and sold volume by state.

Drilling Activity

The following table summarizes our completed net productive development wells.

During the years ended December 31, 2022, 2021 and 2020, we did not drill any net dry development, net productive exploratory or net dry exploratory wells.

Pennsylvania West Virginia Ohio Total

Produced and sold natural gas, NGLs and oil for the years ended December 31,

2021 1,422,294 271,747 163,776 1,857,817

2020 1,051,869 267,708 178,215 1,497,792

2019 1,001,973 274,378 231,545 1,507,896

Year Ended December 31, 2022 55 26 2 83

Year Ended December 31, 2021 60 17 5 82

Year Ended December 31, 2020 84 6 8 98

The following table summarizes the gross and net wells on which we commenced drilling operations (spud) in 2022.

Pennsylvania West Virginia Ohio Total

Gross wells spud 123 17 16 156

Net wells spud 75 7 2 84

Markets and Customers

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Natural gas is a commodity and, therefore, we typically receive market-based pricing for our produced natural gas.

The market price for natural gas in the Appalachian Basin is typically lower relative to NYMEX Henry Hub, Louisiana (the location for pricing NYMEX natural gas futures) as a result of increased supply of natural gas in the Northeast United States.

To protect cash flow from undue exposure to the risk of changing commodity prices, we hedge a portion of our forecasted natural gas production at, for the most part, NYMEX natural gas prices.

To protect our cash flow from undue exposure to the risk of changing commodity prices, we hedge a portion of our forecasted natural gas production at, for the most part, NYMEX natural gas prices.

We also enter into derivative instruments to hedge basis.

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Ethane ($/Bbl):

Average sales price, excluding cash settled derivatives $ 8.85 $ 3.48 $ 6.16

Average sales price, including cash settled derivatives 8.85 3.48 7.18

Average sales price $ 14.20 $ 8.85 $ 3.48

Average sales price $ 77.06 $ 56.82 $ 25.57

Natural gas, NGLs and oil ($/Mcfe):

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The asset management agreement is subject to currently unsatisfied conditions;

therefore, its impacts have been excluded from the schedule of total gross commitments summarized in the table below.

therefore, its impacts have been excluded from the firm capacity on the Mountain Valley Pipeline noted above and the schedule of total gross commitments summarized in the table below.

We have contractually agreed to deliver firm quantities of gas and NGLs to various customers, which we expect to fulfill with production from existing reserves.

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2026 360 4,250

2027 328 3,650

Thereafter 2,155 34,690

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spill prevention plans;

the use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;

the use, transportation, storage and disposal of fluids and materials incidental to oil and gas

surface usage and the reclamation of properties upon which wells or other facilities have been located;

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and the unitization or pooling of natural gas properties.

Ohio and, for Utica or other deep wells, West Virginia allow the statutory pooling or unitization of tracts to facilitate development and exploration.

In West Virginia, we must rely on voluntary pooling of lands and leases for Marcellus acreage.

Ohio allows the statutory pooling or unitization of tracts to facilitate development and exploration.

In Pennsylvania, lease integration legislation authorizes joint development of existing contiguous leases.

In addition, state conservation and oil and gas laws generally limit the venting or flaring of natural gas.

West Virginia historically only allowed statutory pooling of Utica acreage and for other deep wells, which required operators to rely on voluntary pooling of lands and leases to develop Marcellus acreage.

However, in March 2022, the West Virginia legislature passed Senate Bill 694 allowing the operator of a proposed horizontal well (regardless of formation) to develop the acreage of non-consenting and unlocatable and unknown owners if 75% of the mineral interest owners and 55% of the working interest owners in the proposed well unit consent to the development.

Senate Bill 694, and the corresponding unitization provisions thereunder, went into effect on June 7, 2022.

Additionally, state conservation and oil and gas laws generally limit the venting or flaring of natural gas.

Various states also impose certain regulatory requirements to transfer wells to third parties or discontinue operations in the event of divestitures by us.

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The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), required the CFTC, the SEC and other regulatory agencies to promulgate rules and regulations implementing this legislation.

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

Although some of the rules necessary to implement the Dodd-Frank Act have yet to be adopted, regulators have issued numerous rules under the Dodd-Frank Act, including a rule establishing an "end-user" exception to mandatory clearing (End-User Exception), a rule requiring the posting of margin for certain uncleared swaps (Margin Rule) and a rule imposing federal position limits on certain futures contracts relating to energy products, including natural gas (Position Limits Rule).

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

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

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

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

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

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

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

jurisdictions have enacted laws and regulations related to derivatives which apply to our transactions with counterparties subject to such foreign regulations.

The Dodd-Frank Act also created new categories of regulated market participants, such as “swap dealers” (SDs) and “security-based swap dealers” (SBSDs) that are subject to significant new capital, registration, recordkeeping, reporting, disclosure, business conduct and other regulatory requirements, a large number of which have been implemented.

This regulatory framework has significantly increased the costs of entering into derivatives transactions for end-users of derivatives, such as ourselves.

In particular, new margin requirements and capital charges, even when not directly applicable to us, have increased the pricing of derivatives that we transact in.

New exchange trading margin regulations, trade reporting requirements and position limits may lead to changes in the liquidity of our derivative transactions or higher pricing.

That said, 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 the Dodd-Frank Act.

Additionally, 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 applicable federal and exchange-mandated position limits rules and are not materially impacted by the limitations under such rules.

In addition to U.S.

laws and regulations relating to derivatives, certain non-U.S.

regulatory authorities have passed or proposed, or may propose in the future, legislation similar to that imposed by the Dodd-Frank Act.

For example, European Union legislation imposes position limits on certain commodity transactions, and the European Market Infrastructure Regulation (EMIR) requires reporting of derivatives and various risk mitigation techniques to be applied to derivatives entered into by parties that are subject to EMIR.

Other similar regulations are in development throughout the globe and may increase our cost of doing business even if not directly binding on us.

Regulators periodically review or audit our compliance with applicable regulatory requirements.

We anticipate that compliance with existing laws and regulations governing current operations will not have a material adverse effect upon our capital expenditures, earnings or competitive position.

Additional proposals that affect the oil and gas industry are regularly considered by Congress, the states, regulatory agencies and the courts.

We anticipate that compliance with existing laws and regulations governing our current operations will not have a material adverse effect on our capital expenditures, earnings or competitive position.

Additional proposals that affect the oil and gas industry are regularly considered

by Congress, the states, regulatory agencies and the courts.

We cannot predict when or whether any such proposals may become effective or the effect that such proposals may have on us.

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Various federal laws enacted since 1978 have resulted in the removal of all price and non-price controls for sales of domestic natural gas sold in first sales, which include all of our sales of our own production.

Under the Energy Policy Act of 2005, the FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties of over $1.3 million per day for each violation and disgorgement of profits associated with any violation.

While our production activities have not been regulated by the FERC as a natural gas company under the NGA, we are required to report aggregate volume of natural gas purchased or sold at wholesale to the extent such transactions use, contribute to or may contribute to the formation of price indices.

Under the Energy Policy Act of 2005, the FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties of almost $1.5 million per day for each violation and disgorgement of profits associated with any violation.

While our production activities have not been regulated by the FERC as a natural gas company under the NGA, we are required to report the aggregate volume of natural gas purchased or sold at wholesale to the extent such transactions use, contribute to or may contribute to the formation of price indices.

In addition, Congress may enact legislation or the FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation.

Failure to comply with those regulations in the future could subject us to civil penalties.

The CFTC also holds authority to monitor certain segments of the physical, futures and other derivatives with respect to energy commodities markets, including natural gas, NGLs and oil.

With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that we undertake, we are thus required to observe anti-market manipulation and disruptive trading practices laws and related regulations enforced by the CFTC.

The CFTC also holds authority to monitor certain segments of the physical, futures and other derivatives energy commodities markets, including natural gas, NGLs and oil.

With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation and disruptive trading practices laws and related regulations enforced by the CFTC.

The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties.

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We believe that the third-party natural gas pipelines on which our gas is gathered meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to regulation as a natural gas company.

However, the distinction between the FERC-regulated transportation services and federally unregulated gathering services could be subject to potential litigation, so the classification and regulation of those gathering facilities are subject to change based on future determinations by the FERC, the courts or Congress.

State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements.

However, the distinction between the FERC-regulated transportation services and federally unregulated gathering services could be subject to potential litigation, and the classification and regulation of those gathering facilities are subject to change based on future determinations by the FERC, the courts or Congress.

State regulation of natural

gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements.

Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

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Sales prices of oil and NGLs are not currently regulated and are made at market prices.

Our sales of these commodities are, however, subject to laws and regulations issued by the Federal Trade Commission (FTC) prohibiting manipulative or fraudulent conduct in the wholesale petroleum market.

Our sales of these commodities are, however, subject to laws and regulations issued by the FTC prohibiting manipulative or fraudulent conduct in the wholesale petroleum market.

The FTC holds substantial enforcement authority under these regulations, including the ability to assess civil penalties of over $1.4 million per day per violation.

Our sales of these commodities, and any related hedging activities, are also subject to CFTC oversight and enforcement authority as discussed above.

The price we receive from the sale of our produced oil and NGLs may be affected by the cost of transporting the products to market.

The price we receive from the sale of our produced oil and NGLs may be affected by the cost of transporting such products to market.

Some of our transportation of oil and NGLs is through FERC-regulated interstate common carrier pipelines.

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Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry.

The FERC's five-year index level for 2021–2026 went into effect on July 1, 2021.

The FERC's five-year index level for 2021 through 2026 went into effect on July 1, 2021.

In January 2022, the FERC issued an order on rehearing, lowering the index level and directing oil pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022 to ensure compliance with the new index level.

Environmental, Health and Safety Regulation.

Environmental, Health and Safety Regulations.

Our business operations are also subject to numerous stringent federal, state and local environmental, health and safety laws and regulations pertaining to, among other things, the release, emission or discharge of materials into the environment;

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require some form of remedial action to prevent, remediate or mitigate pollution from operations, such as plugging abandoned wells or closing earthen pits;

establish specific safety and health criteria addressing worker protection;

establish specific health and safety criteria addressing worker protection;

and impose substantial liabilities for pollution resulting from operations or failure to comply with applicable laws and regulations.

In addition, these laws and regulations may restrict the rate of production.

In addition, these laws and regulations may restrict the rate of our production.

Moreover, the trend has been for stricter regulation of activities that have the potential to affect the environment.

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We have established procedures, however, for the ongoing evaluation of our operations to identify potential environmental exposures and to track compliance with regulatory policies and procedures.

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

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

Hazardous Substances and Waste Handling.

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These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred.

Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

allegedly caused by the hazardous substances released into the environment.

In addition, despite the "petroleum exclusion" of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we generate materials in the course of our operations that may be regulated as hazardous substances based on their characteristics;

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The Resource Conservation and Recovery Act (RCRA) and analogous state laws establish detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes.

RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes.

RCRA specifically excludes drilling fluids, produced water and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes.

However, these wastes may be regulated by the EPA, or state agencies under RCRA's less stringent nonhazardous solid waste provisions, or under state laws or other federal laws.

Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future.

In April 2019, following litigation and a resulting consent decree related to the EPA's requirements under RCRA to review oil and gas waste regulations, the EPA determined that revisions to the regulations were not required, concluding that any adverse effects related to oil and gas waste were more appropriately and readily addressed within the framework of existing state regulatory programs.

Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes currently classified as nonhazardous solid wastes could be classified as hazardous wastes in the future.

Any changes to state or federal programs could result in an increase in our costs to manage and dispose waste, which could have a material adverse effect on our results of operations and financial condition.

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We are able to control directly the operation of only those wells with respect to which we act or have acted as operator.

The failure of a prior owner or operator to comply with applicable environmental regulations may, in certain circumstances, be attributed to us as current owner or operator under CERCLA.

The failure of a prior owner or operator to comply with applicable environmental regulations may, in certain circumstances, be attributed to us as the current owner or operator under CERCLA.

These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws.

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

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

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

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.

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

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

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In September 2020, the EPA finalized two sets of amendments to the 2016 Subpart OOOOa standards.

The first, known as the 2020 Technical Rule, reduced the 2016 rule's fugitive emissions monitoring requirements and expanded exceptions to pneumatic pump requirements, among other changes.

The second, known as the 2020 Policy Rule, rescinded the methane-specific requirements for certain oil and natural gas sources in the production and processing segments.

The first amendment, known as the "2020 Technical Rule", reduced the 2016 rule's fugitive emissions monitoring requirements and expanded exceptions to pneumatic pump requirements, among other changes.

The second amendment, known as the "2020 Policy Rule", rescinded the methane-specific requirements for certain oil and natural gas sources in the production and processing segments.

On January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the 2020 Technical Rule by September 2021 and consider revising the 2020 Policy Rule.

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Under the proposed rule, states would have three years to develop their compliance plan for existing sources and the regulations for new sources would take effect immediately upon issuance of a final rule.

The EPA is expected to issue both a supplemental proposed rule, which may expand or modify the current proposed rule, and final rule by the end of 2022.

As a result of these regulatory changes, the scope of any final methane regulations or the costs for complying with federal methane regulations are uncertain.

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.

As a result of these regulatory changes, the scope of any final air emissions regulations or the costs for complying with such regulations are uncertain.

We may incur costs as necessary to remain in compliance with these regulations.

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Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

Climate Change and Regulation of Greenhouse Gas Emissions.

Climate Change and Regulation of Methane and Other Greenhouse Gas Emissions .

In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in nearly 200 countries, including the United States, coming together to develop the Paris Agreement, which calls for the signatories to the agreement to undertake "ambitious efforts" to limit increases in the average global temperature.

Although the agreement does not create any binding obligations for nations to limit their greenhouse gas (GHG) emissions, it does include pledges to voluntarily limit or reduce future emissions.

On June 1, 2017, President Trump announced that the U.S.

would withdraw from the Paris Agreement and completed the process of withdrawing from the Paris Agreement on November 4, 2020.

However, on January 20, 2021, President Biden issued written notification to the United Nations of the U.S.'s intention to rejoin the Paris Agreement, which became effective on February 19, 2021.

In 2020, President Trump completed the process of withdrawing the United States from the Paris Agreement.

However, on February 19, 2021 the United States rejoined the Paris Agreement under the mandate of President Biden.

In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions to at least 30% below 2020 levels by 2030.

Since its formal launch at the United Nations Climate Change Conference (COP26), over 100 countries have joined the pledge.

On November 3, 2021, the U.S.

House of Representatives passed budget reconciliation bill H.R.

5376, known as the Build Back Better Act.

The House version of the bill includes a provision targeting methane emissions from oil and gas sources by proposing to implement fees for excess methane leaking from wells, storage sites and pipelines as well as fees for new producing and non-producing oil and gas leases and off-shore pipelines.

It is unclear whether the Build Back Better Act will be passed in its current form by the U.S.

Since its formal launch at the 26th Conference of Parties to the United Nations Convention on Climate Change (COP26), over 100 countries have joined the Global Methane Pledge.

Most recently, at the 27th Conference of Parties (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 August 2022, President Biden signed into law the Inflation Reduction Act of 2022 (Inflation Reduction Act), which among other things, includes a methane emissions reduction program that amends the CAA to include a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems.

This program requires the EPA to impose a “waste emissions charge” on certain oil and gas sources that are already required to report under the EPA’s Greenhouse Gas Reporting Program (GHGRP).

The waste emissions charge will become effective on January 1, 2024 and will apply to a facility’s emissions (as reported under the EPA’s GHGRP) in excess of a specified threshold, as set forth in the Inflation Reduction Act based upon the emitting facility’s segment category.

The fee for emissions in excess of the specified threshold will initially be $900 per metric ton of methane emitted in 2024 and will increase to $1,200 in 2025, and $1,500 in 2026.

For petroleum and natural gas production facilities, the threshold is methane emissions in excess of 0.2% of the natural gas sent to sale from the facility.

If a facility’s methane emissions do not exceed the 0.2% threshold, no fee would be assessed under the rule.

current methane emissions do not exceed the 0.2% threshold, and accordingly, we do not believe we will be assessed a fee under the Methane Emissions and Waste Reduction Incentive Program.

The $1 trillion legislative infrastructure package passed by Congress in November 2021 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.

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

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

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

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

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

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

Any legislation or regulatory programs at the federal, state or city levels designed to reduce GHG emissions could increase the cost of consuming, and thereby reduce demand for, the natural gas, NGLs and oil we produce.

Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.

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

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

Notwithstanding potential risks related to climate change, the International Energy Agency estimates that natural gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades.

Pennsylvania ultimately became a member of RGGI, 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.

Any legislation or regulatory programs at the federal, state or city levels designed to reduce methane or other GHG emissions could increase the cost of consuming, and thereby reduce demand for, the natural gas, NGLs and oil we produce.

Consequently, legislation and regulatory programs designed to reduce emissions of methane or other GHGs could have an adverse effect on our business, financial condition and results of 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 GHG emissions from, our equipment and operations could require us to incur costs to comply with such regulations.

Substantial limitations 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.

Notwithstanding potential risks related to climate change, natural gas continues to represent a major share of global energy use, and certain private sector studies project continued growth in demand for the next two decades.

Nonetheless, recent activism directed at shifting funding away from fossil fuel companies could result in limitations or restrictions on certain sources of funding for the sector.

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To assess water sources near our drilling locations, we conduct multiple pre-drill samplings for all water sources within 3,000 feet of our sites and post-drill samplings for sources within 1,500 feet of our sites.

Hydraulic fracturing typically is regulated by state oil and natural gas agencies, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (SDWA) over certain hydraulic fracturing activities involving the use of diesel fuels and has prohibited the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

wastewater treatment plants.

Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities.

For example, in January 2020, the EQB approved a well permit fee increase from $5,000 to $12,500 for all unconventional wells.

For example, in January 2020, the Pennsylvania EQB approved a well permit fee increase from $5,000 to $12,500 for all unconventional wells.

Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.

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Occupational Safety and Health Act.

We are also subject to the requirements of the federal Occupational Safety and Health Act (OSH Act) and comparable state laws that regulate the protection of the health and safety of employees.

In addition, the Occupational Health and Safety Administration's (OSHA) hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require us to maintain information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities, and citizens.

We are also subject to the requirements of the federal Occupational Safety and Health Act and comparable state laws that regulate the protection of the health and safety of employees.

In addition, the Occupational Health and Safety Administration's (OSHA) hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require us to maintain information about hazardous materials used or produced in our operations and this information is required to be provided to employees, state and local government authorities, and citizens.

Endangered Species Act and Migratory Bird Treaty Act.

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Fish and Wildlife Service (FWS) may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species.

In August 2019, the FWS and National Marine Fisheries Service (NMFS) issued three rules amending implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitat.

A coalition of states and environmental groups have challenged the three rules and litigation remains pending.

In addition, in December 2020, the FWS amended its regulations governing critical habitat designations;

the amended regulations are subject to ongoing litigation.

In June 2021, the FWS and the NMFS announced plans to begin rulemaking processes to rescind these rules.

In addition, in December 2020, the FWS amended its regulations governing critical habitat designations, which were also the subject of litigation.

In June and July 2022, the FWS issued final rules rescinding the regulations defining "habitat" and governing critical habitat exclusions.

Protections similar to the ESA are offered to migratory birds under the Migratory Bird Treaty Act (MBTA), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit.

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however, the Department of the Interior revoked the rule in October 2021 and issued an advance notice of proposed rulemaking seeking comment on the Department's plan to develop regulations that authorize incidental taking under certain prescribed conditions.

Future implementation of the rules implementing the ESA and the MBTA are uncertain.

The notice of proposed rulemaking was due to be issued in August 2022;

however, the status of the rulemaking is still pending.

Future implementation of the rules impacting the ESA and the MBTA are uncertain.

A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for natural gas development.

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As of December 31, 2022, we had 744 permanent employees, none of whom were subject to a collective bargaining agreement.

Of our total permanent employee base, 75% were male and 25% were female.

Approximately 70% of our permanent employees worked remotely, with 93% residing in Pennsylvania or West Virginia.

Of our total permanent employee base, 74% are male and 26% are female.

Approximately 66% of our permanent employees work remotely, with 91% residing in Pennsylvania or West Virginia.

We aim to develop a workforce that produces peer leading results.

To further that goal, we have focused on creating a modern, innovative, collaborative and digitally-enabled work environment.

In 2019, we simplified our organizational structure and instituted a cloud-based digital work environment with an emphasis on the democratization of data.

Our digital work environment serves as our primary platform for communication and collaboration as well as the home for our critical work processes and drives decision-making based on a shared and transparent view of operational data.

Our cloud-based digital work environment serves as our primary platform for communication and collaboration as well as the home for our critical work processes and drives decision-making based on a shared and transparent view of operational data.

We use our digital work environment to engage directly with our employees by sharing company updates and personnel accomplishments as well as to solicit suggestions and comments from all employees.

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We offer benefits that include subsidized health insurance, a company contribution and company match on 401(k) retirement savings, an employee stock purchase plan, paid maternity and paternity leave, flexible work arrangements, volunteer time off and a company match on employee donations to qualified non-profits.

We also offer our employees the flexibility to elect to work a "9/80" work schedule, under which, during the standard 80-hour pay period, an employee works eight 9-hour days and one 8-hour day (Friday), with a tenth day off (alternative Friday).

In 2020, we launched an "equity-for-all" program, pursuant to which, in 2021, we granted equity awards to all of our permanent employees.

In 2022, we continued our equity-for-all program by granting equity awards to all permanent employees.

We offer an "equity-for-all" program, pursuant to which, we grant annual equity awards to all of our permanent employees.

With the equity-for-all program, all of our permanent employees become owners of EQT and have the opportunity to share directly in our financial success.

Equity-for-all grants are in addition to, and not in lieu of, the existing compensation opportunities for our employees.

Availability of Reports and Other Information

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Sales of natural gas, natural gas liquids and oil $ 12,114,168 $ 6,804,020 $ 2,650,299

(Loss) gain on derivatives not designated as hedges (3,775,042) 400,214 616,634

(Loss) gain on derivatives (4,642,932) (3,775,042) 400,214

Net marketing services and other 26,453 35,685 8,330

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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 1. Business