What changed in this filing

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Item 1. Business

2024-02-14 compared with 2023-02-16 · 137 added, 150 removed, 398 unchanged (42% of the section changed)

We are a natural gas production company with operations focused in the Marcellus and Utica Shales of the Appalachian Basin.

Based on average daily sales volume, we are the largest producer of natural gas in the United States.

As of December 31, 2022, we had 25.0 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 2.0 million gross acres, including approximately 1.8 million gross acres in the Marcellus play.

We are a natural gas production company with operations focused in the Appalachian Basin.

As of December 31, 2023, we had 27.6 Tcfe of proved natural gas, NGLs and oil reserves across approximately 2.1 million gross acres, and, based on average daily sales volume, we were the largest producer of natural gas in the United States.

We are committed to responsibly developing our world-class asset base and being the operator of choice for all stakeholders.

By promoting a culture that prioritizes operational efficiency, technology and sustainability, we seek to continuously improve the way we produce environmentally responsible, reliable low-cost energy.

We measure sustainability through our best-in-class team and culture, ESG-focused operations, substantial inventory of core drilling locations and strong balance sheet.

We believe that the scale and contiguity of our acreage position differentiates us from our Appalachian Basin peers and that our evolution into a modern, digitally-enabled exploration and production business enhances our strategic advantage.

By promoting a culture that prioritizes operational efficiency, technology, sustainability and safety, we seek to continuously improve the way we produce environmentally responsible, reliable low-cost energy.

We measure sustainability through consideration of our best-in-class team and culture, the ESG performance of our operations, our substantial inventory of core drilling locations and our investment grade balance sheet.

We believe that the scale and contiguity of our acreage position differentiates us from our Appalachian Basin peers and that our digitally-enabled exploration and production business enhances our strategic advantage.

Our operational strategy focuses on the successful execution of combo-development projects.

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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.

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 debt retirements, dividends and strategic share repurchases.

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.

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

the timely verification of midstream connectivity;

timely midstream connectivity;

and the ability to quickly respond to internal and external stimuli.

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

Without a 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.

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2023 Highlights

• 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.

• Generated $3.2 billion of net cash provided by operating activities with an average NYMEX price of $2.74 per MMBtu.

• Retired $1.1 billion aggregate principal of debt.

• Increased quarterly base dividend by 5% to $0.1575 per share ($0.63 per share annualized).

• Paid $228 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 $1,400 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.

• Repurchased $200 million of common stock, reducing our outstanding share count by 5.9 million shares.

• Completed the Tug Hill and XcL Midstream Acquisition (defined and discussed in Note 6 to the Consolidated Financial Statements).

• Increased total proved reserves by 2,594 Bcfe, or 10.4%, compared to 2022.

• Achieved investment grade credit rating from Moody's Investors Services, making us investment grade rated by all three credit rating agencies.

In 2024, we expect to spend approximately $2.15 billion to $2.35 billion in total capital expenditures.

We expect to allocate the total planned capital expenditures as follows:

approximately $1,685 million to $1,775 million to fund reserve development, approximately $220 million to $250 million to fund midstream and other infrastructure, approximately $125 million to $190 million to fund land and lease acquisitions, approximately $70 million to $80 million towards capitalized overhead and approximately $50 million to $55 million towards capitalized interest and other items.

Included in total planned capital expenditures is approximately $200 million to $300 million for strategic growth projects composed of approximately $70 million to $90 million for water infrastructure within reserve development, approximately $50 million to $70 million for growth projects within midstream and other infrastructure and approximately $80 million to $140 million for in-fill leasing and mineral purchases within land and lease acquisitions.

In 2024, we expect our sales volume to be 2,200 Bcfe to 2,300 Bcfe.

We are committed to maintaining investment grade credit metrics, and we have a goal to reduce our absolute debt to $3.5 billion, subject to 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 quarterly cash dividend and share repurchase program, pursuant to which we are authorized to repurchase shares of our outstanding common stock for an aggregate purchase price of up to $2 billion, excluding fees, commissions and expenses.

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.

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

Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas, NGLs and oil at our ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations.

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

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 "Critical Accounting 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 significant accounting policies and 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.

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Substantially all of our assets and operations are located in the Appalachian Basin.

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

The following table summarizes our proved developed and undeveloped natural gas, NGLs and oil reserves using average first-day-of-the-month closing prices for the prior twelve months and disaggregated by product.

Substantially all of our reserves reside in continuous accumulations.

December 31, 2023

Natural Gas NGLs and Crude Oil Total

Natural Gas NGLs and Oil Total (a)

(Bcf) (MMbbl) (Bcfe)

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Total proved reserves 25,795 301 27,597

December 31, 2022

Marcellus Ohio Utica Other Total

Proved developed reserves 16,718 708 88 17,514

Proved undeveloped reserves 7,468 17 4 7,489

Total proved reserves 24,186 725 92 25,003

(a) The Marcellus Shale comprises 91% of our total proved developed reserves, 98% of our total proved undeveloped reserves and 93% of our total proved reserves.

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

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Net proved undeveloped drilling locations 174 172 1 347

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.

Our 2023 total proved reserves increased by 2,594 Bcfe, or 10.4%, compared to 2022 due to extensions, discoveries and other additions of 3,412 Bcfe and acquisitions of 2,600 Bcfe from the Tug Hill and XcL Midstream Acquisition, partly offset by production of 2,016 Bcfe and revisions to previous estimates of 1,402 Bcfe.

Our 2023 proved undeveloped reserves increased by 550 Bcfe, or 7.3%, compared to 2022.

The following table provides a roll-forward of our proved undeveloped reserves.

Proved Undeveloped Reserves

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Balance at December 31, 2023 8,039

(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.

(a) Composed of (i) negative revisions of 755 Bcfe related to proved undeveloped locations that we no longer expect to develop as proved reserves within five years of initial booking as a result of development schedule changes, (ii) negative revisions of 367 Bcfe due primarily to revisions to type curves and commodity price change, partly offset by (iii) positive revisions of 290 Bcfe due to changes in ownership interests.

(b) Composed of (i) 1,670 Bcfe from proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2023 reserve development that expanded the number of our proven locations and additions to our five-year drilling plan, (ii) 1,341 Bcfe of proved undeveloped additions for previously proved undeveloped properties reclassified from unproved properties due to their addition to our five-year development plan and (iii) positive revisions of 92 Bcfe from the extension of lateral lengths of proved undeveloped reserves.

As of December 31, 2023, we had zero wells with proved undeveloped reserves that had remained undeveloped for more than five years from their time of booking.

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2023 2022 2021

(Millions, except prices)

(Millions, unless otherwise noted)

Future net cash flow $ 19,031 $ 87,612 $ 36,567

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(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 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 GAAP.

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

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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.

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

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

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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.

See Note 14 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 oil reserves.

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

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If the prices used in the calculation of the Standardized Measure instead reflected five-year strip pricing as of December 29, 2023 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 24,971 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.

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 28,042 Bcfe, the Standardized Measure after taxes of our proved reserves would be $18,176 million, the discounted future net cash flows before taxes would be $22,903 million and the average realized product prices weighted by production over the remaining lives of the properties would be $49.71 per barrel of oil, $23.08 per barrel of NGLs and $2.846 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.

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Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC pricing, when considering our reserves.

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

At our current drilling pace, these net locations provide more than 20 years of drilling inventory based on net undeveloped Marcellus acres, average expected lateral length of 12,000 feet and well spacing of 1,000 feet.

Based on our mix of proved undeveloped probable and possible reserves, we estimate that we have an undeveloped drilling inventory of approximately 4,000 gross locations.

At our current drilling pace, these locations provide more than 30 years of drilling inventory based on gross undeveloped acres, average expected lateral length of 12,000 feet and well spacing of 1,000 feet.

We believe that our combo-development strategy, coupled with our undeveloped inventory located in a premier core asset base, will lead to sustainable free cash flow generation and higher returns on invested capital.

The following table summarizes our capital expenditures for reserve development.

Years Ended December 31,

2022 2021 2020

$ 1,102 $ 788 $ 737

Utica 29 40 102

Total $ 1,131 $ 828 $ 839

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.

For the years ended December 31, 2023, 2022 and 2021, lease operating expenses per Mcfe were $0.08, $0.08 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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We primarily sell NGLs recovered from our natural gas production.

We primarily contract with MarkWest Energy Partners, L.P.

(MarkWest) to process our natural gas and extract from the produced natural gas heavier hydrocarbon streams (consisting predominately of ethane, propane, isobutane, normal butane and natural gasoline).

We also contract with MarkWest to market a portion of our NGLs.

In addition, we have contractual arrangements with Williams Ohio Valley Midstream LLC to process our natural gas and market a portion of our NGLs.

We contract with MarkWest Energy Partners, L.P., Williams Ohio Valley Midstream LLC and Blue Racer Midstream to process our natural gas and extract heavier hydrocarbon streams (consisting predominately of ethane, propane, isobutane, normal butane and natural gasoline) from our produced natural gas.

We market the majority of our NGLs.

Average Sales Price.

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We have access to approximately 3.6 Bcf per day of firm pipeline takeaway capacity and 0.9 Bcf per day of firm processing capacity.

In addition, we are committed to an initial 1.29 Bcf per day of firm capacity on the Mountain Valley Pipeline upon its in-service date.

In addition, we are committed to an initial 1.29 Bcf per day of firm capacity on the Mountain Valley Pipeline once in service.

These firm transportation and processing agreements may require minimum volume delivery commitments, which we expect to principally fulfill with production from existing reserves.

During 2021, we entered into a long-term asset management agreement with an investment grade entity, pursuant to which, we agreed to deliver and sell up to 525,000 Dth of natural gas per day to the investment grade entity for a period of up to six years while managing and using our committed capacity on the Mountain Valley Pipeline upon its in-service date.

The asset management agreement is subject to currently unsatisfied conditions;

therefore, its impacts have been excluded from the 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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Thereafter 1,840 31,030

During the fourth quarter of 2023, we entered into two firm sales agreements, pursuant to which we agreed to deliver and sell to the parties thereto up to an aggregate 1.2 Bcf per day of gas using our Mountain Valley Pipeline capacity for up to ten years beginning in 2027.

The firm sales agreements are subject to currently unsatisfied conditions related to the in-service dates of the Mountain Valley Pipeline and Transco Southeast Supply Enhancement;

therefore, their impact has been excluded from the schedule of total gross commitments in the table above.

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months.

Seasonal anomalies such as mild winters or summers may also impact demand.

Seasonal anomalies such as mild winters or summers may also affect demand.

Other natural gas producers compete with us in the acquisition of properties;

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spill prevention plans;

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

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

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

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

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.

West Virginia allows the operator of a proposed horizontal well 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.

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.

We maintain limited gathering operations that are subject to various federal and state environmental laws and local zoning ordinances, including the following:

We also have gathering and processing operations used for our own produced natural gas and NGLs that are subject to various federal and state environmental laws and local zoning ordinances, including the following:

air permitting requirements for compressor station and dehydration units and other permitting requirements;

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These regulations may increase the costs of operating existing pipelines and compressor stations and increase the costs of, and the time to develop, new or expanded pipelines and compressor stations.

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 comprehensive financial reform legislation that established federal oversight and regulation of the OTC derivative market and entities, such as us, that participate in that market.

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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.

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 almost $1.5 million per day for each violation and disgorgement of profits associated with any violation.

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 $1.5 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.

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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.

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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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.

The FTC holds substantial enforcement authority under these regulations, including the ability to assess civil penalties of almost $1.5 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.

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Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations.

The FERC's regulation of crude oil and NGLs transportation rates may tend to increase the cost of transporting crude oil and NGLs by interstate pipelines, although the annual adjustments may result in decreased rates in a given year.

The FERC's regulation of oil and NGLs transportation rates may tend to increase the cost of transporting oil and NGLs by interstate pipelines, although the annual adjustments may result in decreased rates in a given year.

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

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Violations of these laws can result in substantial administrative, civil and criminal penalties.

These laws and regulations may require us to acquire permits before drilling or other regulated activity commences;

restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production;

These laws and regulations may require us to acquire permits before drilling, constructing pipelines or other regulated activity commences;

restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with our operations;

govern the sourcing and disposal of water used in the drilling and completion process;

limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands and other protected areas or areas with endangered or threatened species restrictions;

limit or prohibit drilling activities or pipeline construction in certain areas and on certain lands lying within wilderness, wetlands and other protected areas or areas with endangered or threatened species restrictions;

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

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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.

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;

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

however, we are unaware of any liabilities arising under CERCLA for which we may be held responsible that would materially and adversely affect us.

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

RCRA specifically excludes drilling fluids, produced water 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 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.

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In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control.

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

We are able to directly control 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 the current owner or operator under CERCLA.

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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 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 January 2023, the EPA and the Corps issued a final rule that based the definition of WOTUS on the pre-2015 definition.

The definition of WOTUS was further impacted by the U.S.

Supreme Court's decision issued in May 2023 in Sackett v.

EPA , wherein the Court held that the jurisdiction of the CWA extends only to those adjacent wetlands that are indistinguishable from traditional navigable bodies of water due to a continuous surface connection and rejected the "significant nexus" test embraced in earlier jurisprudence.

In September 2023, the EPA and the Corps published a direct-to-final rule redefining WOTUS to amend the January 2023 rule and align with the decision in Sackett .

The final rule eliminated the "significant nexus" test from consideration when determining federal jurisdiction and clarified that the CWA only extends to relatively permanent bodies of water and wetlands that have a continuous surface connection with such bodies of water.

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

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

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

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

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

Also, pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or stormwater and to develop and implement spill prevention, control and countermeasure (SPCC) plans in connection with on-site storage of significant quantities of oil.

These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances and may impose substantial potential liability for the costs of removal, remediation and natural resource and other damages.

Air Emissions.

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New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits.

In June 2016, the EPA finalized regulations establishing New Source Performance Standards (NSPS), known as Subpart OOOOa, for methane and volatile organic compounds (VOC) from new and modified oil and natural gas production and natural gas processing and transmission facilities.

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

The first 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.

On June 30, 2021, President Biden signed a Congressional Review Act (CRA) resolution passed by Congress that revoked the 2020 Policy Rule.

The CRA did not address the 2020 Technical Rule.

Further, on November 15, 2021, the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources.

The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA, including intermittent vent pneumatic controllers and associated gas and liquids unloading facilities.

In addition, the proposed rule would establish "Emissions Guidelines," creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA.

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

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.

In November 2021, the EPA announced a proposed rule expanding upon its New Source Performance Standards (NSPS) rule, establishing standards for methane and volatile organic compounds (VOCs) from new and modified oil and natural gas production and natural gas processing and transmission facilities which would establish standards for existing wells, impose more frequent and stringent leak monitoring, and mandate that all pneumatic controllers have zero emissions.

The proposed rule sought to make existing regulations more stringent, create a Subpart OOOOb to expand reduction requirements for new, modified and reconstructed natural gas and oil sources, and create a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA.

In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule, which, among other things, created a new third-party monitoring program to identify large emissions events, referred to in the proposed rule as "super emitters." The EPA announced a final rule in December 2023, which, among other things, requires the phase out of routine flaring of natural gas from new oil wells and routine leak monitoring at all well sites and compressor stations.

Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with applicable compliance dates under state plans.

The final rule gives states two years to develop and submit their plans for reducing methane from existing sources.

Subpart OOOOc then provides three years from the plan submission deadline for existing sources to comply.

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.

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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.

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 December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change (COP) 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 require pledges to voluntarily limit or reduce future emissions.

Pursuant to the terms of the Paris Agreement, the Biden Administration announced goals aimed at reducing the U.S.'s GHG emissions by 50 – 52% (compared to 2005 levels) by 2030.

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 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.

Since its formal launch at COP26, over 150 countries have joined the Global Methane Pledge, and at COP27, the Biden Administration 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.

In November 2023, the European Union reached a provisional political agreement on a regulation to track and reduce methane emissions in the energy sector.

The regulation introduces new requirements for the oil and gas sectors to measure, report and verify methane emissions and implements mitigation measures to avoid such emissions.

The regulation also introduces new global monitoring tools to ensure transparency on methane emissions from imports of oil, gas and coal into the European Union.

Monitoring, reporting and verification measures will be required to be applied by exporters to the European Union by January 1, 2027 and "maximum methane intensity values" must be met by 2030.

Each member state will have the power to impose administrative penalties for failure to comply and the standard will be mandatory for supply contracts signed after the law takes effect.

Most recently, at COP28, President Biden announced the EPA's final standards to reduce methane emissions from existing oil and gas sources.

Additionally, at COP28, nearly 200 countries, including the United States, agreed to transition away from fossil fuels while accelerating action in this decade to achieve net zero by 2050 and entered into an agreement that calls for actions towards achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030.

The goals of the agreement, among other things, are to accelerate efforts towards the phase-down of unabated coal power, phase out inefficient fossil fuel subsidies, and take other measures that drive the transition away from fossil fuels in energy systems.

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.

In recent years, the U.S.

Congress has considered legislation to reduce GHG emissions.

While Congress has not passed comprehensive climate legislation regulating the emission of GHGs, energy legislation and other regulatory initiatives have been enacted or proposed that are relevant to GHG emissions and climate change.

In particular, in November 2021, Congress approved a $1 trillion legislative infrastructure package known as the Inflation Reduction Act of 2022 (IRA) which includes a number of climate-focused spending initiatives.

The IRA 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 instituting a methane emissions reduction program known as the Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems.

This program requires the EPA to impose a fee known as a "waste emissions charge" on methane emissions from certain natural gas and oil facilities that are in excess of a specified threshold.

In January 2024, the EPA proposed a rule implementing the IRA's methane emissions charge.

The methane emissions charge imposed under the program for 2024 is $900 per ton emitted over the annual methane emissions threshold, and will increase to $1,200 in 2025, and $1,500 in 2026.

The proposed rule includes potential methodologies for calculating the amount by which a facility's reported methane emissions are below or exceed the waste emissions thresholds and contemplates approaches for implementing certain exemptions created by the IRA.

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.

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

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.

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.

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

Further, in July 2023, the EPA proposed to expand the scope of the Greenhouse Gas Reporting Program for petroleum and natural gas systems (Subpart W), as required by the IRA.

Among other things, the proposed rule expands the emissions events that are subject to reporting requirements to include "other large release events" and applies reporting requirements to certain new sources and sectors, which may result in an increase in reported methane and other GHG emissions under Subpart W for many operators, including us.

The rule is currently scheduled to be finalized in the spring of 2024 and would take effect on January 1, 2025 in advance of the deadline for reporting emissions for calendar year 2024 under Subpart W.

Furthermore, in May 2023, the EPA issued proposed carbon emission limits and guidelines for new, modified, reconstructed and existing fossil fuel-fired (i.e., coal, oil and gas-fired) power plants.

The proposed rule purports to reflect the best system of emissions reduction and use of technology-based improvements, including carbon capture and sequestration and low-GHG hydrogen.

The proposed rule also revises the NSPS for new fossil fuel-fired stationary combustion turbine units and existing fossil fuel-fired steam generating electric generating units (EGUs), proposes new GHG emissions guidelines for existing fossil fuel-fired steam generating EGUs and for existing large, frequently operated stationary combustion turbines.

The proposed rule requires states to submit plans for the establishment, implementation, and enforcement of performance standards for existing sources to the EPA within 24 months of the effective date of the emission guidelines, and compliance deadlines for stationary sources begin by 2030 for existing steam generating units, and 2032 or 2035 for existing combustion turbine units, depending on their subcategory.

A supplemental notice of proposed rulemaking was issued in November 2023, which requested comments on the EPA's initial regulatory flexibility analysis of the rule (particularly reliability concerns raised by small businesses and other commenters), and a final rule is anticipated by April 2024.

Additionally, a number of U.S.

state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of carbon taxes, policies and incentives, and cap-and-trade programs.

In October 2019, then-Pennsylvania Governor Tom Wolf signed an Executive Order directing the Pennsylvania Department of Environmental Protection to draft regulations establishing a cap-and-trade program with the intent of enabling Pennsylvania to join the Regional Greenhouse Gas Initiative (RGGI), a multi-state regional cap-and-trade program comprised of several Eastern U.S.

Pennsylvania became a member of RGGI in April 2022;

however, since joining RGGI, Pennsylvania's membership has been the subject of various legal challenges.

Most recently, in November 2023, the Pennsylvania Commonwealth Court held that the state's participation in RGGI is unconstitutional, and funds raised by the state through its participation in RGGI constitute an invalid tax, which ruling has been appealed.

At this time, it is unclear to what extent, if any, Pennsylvania will continue to seek participation in RGGI or a similar emissions cap-and-trade program.

Regulations requiring the disclosure of GHG emissions and other climate-related information or information substantiating climate-related claims are also increasingly being adopted or proposed at the federal and state level.

For example, the SEC issued a proposed rule in March 2022 that would mandate extensive disclosure of climate-related data, risks, and opportunities, including financial impacts, physical and transition risks, related governance and strategy, and GHG emissions, for certain public companies.

At the state level, California enacted legislation in October 2023 that will ultimately require certain companies that do business in California to publicly disclose their Scopes 1, 2, and 3 GHG emissions, with third party assurance of such data, and issue public reports on their climate-related financial risk and related mitigation measures, as well as legislation that requires companies operating in California to disclose information that supports certain climate-related claims.

Any legislation or regulatory programs at the international, 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.

It is not possible at this time to predict how legislation or regulations that may be adopted to address climate change, methane and other GHG emissions would impact our business.

However, existing laws and regulations and any such future laws and regulations of this nature, including those 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.

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

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

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

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

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

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

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

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

Hydraulic Fracturing Activities.

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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.

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 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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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, which was challenged by a coalition of states and environmental groups.

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.

In June 2023, the FWS issued three proposed rules governing interagency cooperation, listing species and designating critical habitat, and expanding protection options for species listed as threatened pursuant to the ESA.

The final rules are expected by April 2024.

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.

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

however, the status of the rulemaking is still pending.

The proposed rule was anticipated in November 2023, with final action expected by April 2024, but the FWS instead announced in November 2023 that it had received additional technical comments that need further review.

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.

Further, the designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves.

Further, the designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration, production and midstream activities that could have an adverse impact on our ability to develop and produce reserves and transport products to points of sale.

There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us or our customers to incur costs or take other measures that may adversely impact our business or operations.

See Note 11 to the Consolidated Financial Statements for a description of expenditures related to environmental matters.

Human Capital Resources

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, 74% are male and 26% are female.

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

As of December 31, 2023, we had 881 employees (excluding temporary employees and contractors), none of whom were subject to a collective bargaining agreement.

Of our employee base, 76% are male and 24% are female.

Approximately 64% of our employees work remotely, with 94% residing in Pennsylvania, Texas or West Virginia.

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

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

We believe that this helps promote real-time feedback and a greater degree of employee engagement, which lays the foundation for the success of our remote workforce.

We believe that this helps promote real-time feedback and a greater degree of employee engagement, which lays the foundation for the success of our workforce.

We understand that providing employees with the resources and support they need to live a physically, mentally and financially healthy life is critical for sustaining a workplace of choice.

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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 (alternating Fridays).

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.

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

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

Availability of Reports and Other Information

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Reports filed with the SEC are also available on the SEC's website, http://www.sec.gov.

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

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

We generally post the following to our investor relations website shortly before or promptly following its first use or release:

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Sales of natural gas, natural gas liquids and oil $ 5,044,768 $ 12,114,168 $ 6,804,020

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

Gain (loss) on derivatives 1,838,941 (4,642,932) (3,775,042)

Net marketing services and other 25,214 26,453 35,685

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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