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What changed in ANTERO RESOURCES Corp's 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of ANTERO RESOURCES Corp's 2023 and 2024 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2024 report.

+359 added−410 removedSource: 10-K (2025-02-12) vs 10-K (2024-02-14)

Top changes in ANTERO RESOURCES Corp's 2024 10-K

359 paragraphs added · 410 removed · 293 edited across 2 sections

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

155 edited+33 added−66 removed256 unchanged
Biggest changeOur oil and gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and gas, including the possibility of: ● environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination; ● abnormally pressured formations; ● mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse; ● fires, explosions and ruptures of pipelines; ● personal injuries and death; ● natural disasters; and ● terrorist attacks targeting natural gas and oil related facilities and infrastructure.
Biggest changeOur oil and gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and gas, including the possibility of: ● environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination; ● abnormally pressured formations; ● mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse; ● fires, explosions and ruptures of pipelines; ● personal injuries and death; ● natural disasters; and ● terrorist attacks targeting natural gas and oil related facilities and infrastructure. 27 Table of Contents Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for: ● injury or loss of life; ● damage to and destruction of property, natural resources and equipment; ● pollution and other environmental damage; ● regulatory investigations and penalties; ● suspension of our operations; and ● repair and remediation costs.
The availability of water may change over time in ways that we cannot control, including as a result of climate change-related effects such as shifting weather patterns. Additionally, the imposition of new environmental initiatives and regulations could include restrictions on our ability to obtain water or dispose of waste and adversely affect our business and operating results.
The availability of water may change over time in ways that we cannot control, including as a result of climate related effects such as shifting weather patterns. Additionally, the imposition of new environmental initiatives and regulations could include restrictions on our ability to obtain water or dispose of waste and adversely affect our business and operating results.
The operations of the processing facilities or pipelines could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within the operator’s nor our control, such as: ● unscheduled maintenance or catastrophic events, including damages to facilities, related equipment and surrounding properties caused by earthquakes, tornadoes, hurricanes, floods, fires, severe weather, explosions and other natural disasters; ● restrictions imposed by governmental authorities or court proceedings; 32 Table of Contents ● labor difficulties that result in a work stoppage or slowdown; ● disruption in the supply of power, water and other resources necessary to operate the facilities; ● damage to the facilities resulting from NGLs that do not comply with applicable specifications; ● inadequate fractionation capacity or market access to support production volumes, including lack of availability of rail cars, barges, trucks and pipeline capacity, or market constraints, including reduced demand or limited markets for certain NGLs; and ● terrorist attacks or cyberattacks.
The operations of the processing facilities or pipelines could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within the operator’s nor our control, such as: ● unscheduled maintenance or catastrophic events, including damages to facilities, related equipment and surrounding properties caused by earthquakes, tornadoes, hurricanes, floods, fires, severe weather, explosions and other natural disasters; ● restrictions imposed by governmental authorities or court proceedings; ● labor difficulties that result in a work stoppage or slowdown; ● disruption in the supply of power, water and other resources necessary to operate the facilities; ● damage to the facilities resulting from NGLs that do not comply with applicable specifications; ● inadequate fractionation capacity or market access to support production volumes, including lack of availability of rail cars, barges, trucks and pipeline capacity, or market constraints, including reduced demand or limited markets for certain NGLs; and 32 Table of Contents ● terrorist attacks or cyberattacks.
Certain of our stockholders have investments in our affiliates that may conflict with the interests of other stockholders. Paul M. Rady and an individual affiliated with Yorktown serve as members of our Board of Directors and the Board of Directors of Antero Midstream. Mr. Rady and Yorktown also own a significant portion of the shares of our common stock.
Certain of our stockholders have investments in our affiliates that may conflict with the interests of other stockholders. Paul M. Rady and an individual affiliated with Yorktown serve as members of our Board of Directors and the Board of Directors of Antero Midstream. Mr. Rady and Yorktown also own a significant portion of the shares of our common stock. Mr.
The loss of the services of our senior management or technical personnel, including Paul M. Rady, our Chairman, Chief Executive Officer and President, could have a material adverse effect on our business, financial condition and results of operations. Our officers and employees provide services to both us and Antero Midstream.
The loss of the services of our senior management or technical personnel, including Paul M. Rady, our Chairman, President and Chief Executive Officer, could have a material adverse effect on our business, financial condition and results of operations. Our officers and employees provide services to both us and Antero Midstream.
Separately, enhanced climate related disclosure requirements could lead to reputational or other harm with customers, regulators, investors or other stakeholders and could also increase our litigation risks relating to statements alleged to have been made by us or others in our industry regarding climate change risks, or in connection with any future disclosures we may make regarding reported emissions, particularly given the inherent uncertainties and estimations with respect to calculating and reporting GHG emissions.
Separately, enhanced climate related disclosure requirements could lead to reputational or other harm with customers, regulators, investors or other stakeholders and could also increase our litigation risks relating to statements alleged to have been made by us or others in our industry regarding climate risks, or in connection with any future disclosures we may make regarding reported emissions, particularly given the inherent uncertainties and estimations with respect to calculating and reporting GHG emissions.
While we expect to be able to (i) utilize all of our U.S. federal NOL carryforwards, (ii) utilize a portion of our state NOL carryforwards and (iii) generate deductions to offset a portion of our future taxable income, in the event that our NOL carryforwards are subject to future limitation (including due to an ownership change under Section 382), deductions are not generated as expected, or if one or more of our tax positions are successfully challenged by the IRS or other tax authorities (in a tax audit or otherwise), our future tax liabilities may be greater than expected, which could adversely affect our operating results and cash flows.
While we expect to be able to (i) utilize all of our U.S. federal NOL and tax credit carryforwards, (ii) utilize a portion of our state NOL carryforwards and (iii) generate deductions to offset a portion of our future taxable income, in the event that our NOL or tax credit carryforwards are subject to future limitation (including due to an ownership change under Section 382 of the Code), deductions are not generated as expected, or if one or more of our tax positions are successfully challenged by the IRS or other tax authorities (in a tax audit or otherwise), our future tax liabilities may be greater than expected, which could adversely affect our operating results and cash flows.
In accordance with SEC requirements, we based the discounted future net cash flows from our proved reserves on the twelve-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions.
In accordance with SEC requirements, we based the discounted future net cash flows from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions.
In general, the provisions of Section 203 of the DGCL prohibit a Delaware corporation, including those whose securities are listed for trading on the New York Stock Exchange, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless: ● prior to such time, the business combination or the transaction which resulted in the stockholder becoming an interested stockholder is approved by our B oard of Directors ; ● upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced (excluding certain specified shares); or ● on or after such time the business combination is approved by our Board of Directors and authorized at a meeting of stockholders by the holders of at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.
In general, the provisions of Section 203 of the DGCL prohibit a Delaware corporation, including those whose securities are listed for trading on the New York Stock Exchange, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless: ● prior to such time, the business combination or the transaction which resulted in the stockholder becoming an interested stockholder is approved by our B oard of Directors ; ● upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced (excluding certain specified shares); or 34 Table of Contents ● on or after such time the business combination is approved by our Board of Directors and authorized at a meeting of stockholders by the holders of at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.
Among other things, our certificate of incorporation and bylaws: ● provide advance notice procedures with regard to stockholder nominations of candidates for election as directors or other stockholder proposals to be brought before meetings of our stockholders, which may preclude our stockholders from bringing certain matters before our stockholders at an annual or special meeting; ● provide our Board of Directors the ability to authorize issuance of preferred stock in one or more series, which makes it possible for our B oard of Directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us and which may have the effect of deterring hostile takeovers or delaying changes in control or management of us; ● provide that the authorized number of directors may be changed only by resolution of our Board of Directors ; ● provide that, subject to the rights of holders of any series of preferred stock to elect directors or fill vacancies in respect of such directors as specified in the related preferred stock designation, all vacancies, including newly created directorships be filled by the affirmative vote of holders of a majority of directors then in office, even if less than a quorum, or by the sole remaining director, and will not be filled by our stockholders; ● provide that, subject to the rights of the holders of any series of preferred stock to elect directors under specified circumstances, if any, any action required or permitted to be taken by our stockholders must be effected at a duly called annual or special meeting of our stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders; ● provide for our Board of Directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three-year terms; ● provide that, subject to the rights of the holders of shares of any series of preferred stock, if any, to remove directors elected by such series of preferred stock pursuant to our certificate of incorporation (including any preferred stock designation thereunder), directors may be removed from office at any time, only for cause and by the holders of a majority of the voting power of all outstanding voting shares entitled to vote generally in the election of directors; ● provide that special meetings of our stockholders may only be called by the Chief Executive Officer, the Chairman of our Board of Directors or our Board of Directors pursuant to a resolution adopted by a majority of the total number of directors that we would have if there were no vacancies; ● provide that (i) Yorktown Partners LLC (“Yorktown”) and their affiliates are permitted to participate (directly or indirectly) in venture capital and other direct investments in corporations, joint ventures, limited liability companies and other entities conducting business of any kind, nature or description, (ii) Yorktown and their affiliates are permitted to have interests in, participate with, aid and maintain seats on the boards of directors or similar governing bodies of any such investments, in each case that may, are or will be competitive with our business and the business of our subsidiaries or in the same or similar lines of business as us and our subsidiaries, or that could be suitable for us or our subsidiaries and (iii) we have, subject to limited exceptions, renounced, to the fullest extent permitted by law, any interest or expectancy in, or in being offered an opportunity to participate in, such corporate opportunities; ● provide that the provisions of our certificate of incorporation can only be amended or repealed by the affirmative vote of the holders of at least 66 2/3% in voting power of the outstanding shares of our common stock entitled to vote thereon, voting together as a single class; and ● provide that our bylaws can be altered or repealed by (a) our Board of Directors or (b) our stockholders upon the affirmative vote of holders of at least 66 2/3% of the voting power of our common stock outstanding and entitled to vote thereon, voting together as a single class. 34 Table of Contents We have elected not to be subject to the provisions of Section 203 of the Delaware General Corporation Law (the “DGCL”), regulating corporate takeovers.
Among other things, our certificate of incorporation and bylaws: ● provide advance notice procedures with regard to stockholder nominations of candidates for election as directors or other stockholder proposals to be brought before meetings of our stockholders, which may preclude our stockholders from bringing certain matters before our stockholders at an annual or special meeting; 33 Table of Contents ● provide our Board of Directors the ability to authorize issuance of preferred stock in one or more series, which makes it possible for our B oard of Directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us and which may have the effect of deterring hostile takeovers or delaying changes in control or management of us; ● provide that the authorized number of directors may be changed only by resolution of our Board of Directors ; ● provide that, subject to the rights of holders of any series of preferred stock to elect directors or fill vacancies in respect of such directors as specified in the related preferred stock designation, all vacancies, including newly created directorships be filled by the affirmative vote of holders of a majority of directors then in office, even if less than a quorum, or by the sole remaining director, and will not be filled by our stockholders; ● provide that, subject to the rights of the holders of any series of preferred stock to elect directors under specified circumstances, if any, any action required or permitted to be taken by our stockholders must be effected at a duly called annual or special meeting of our stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders; ● provide for our Board of Directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three-year terms; ● provide that, subject to the rights of the holders of shares of any series of preferred stock, if any, to remove directors elected by such series of preferred stock pursuant to our certificate of incorporation (including any preferred stock designation thereunder), directors may be removed from office at any time, only for cause and by the holders of a majority of the voting power of all outstanding voting shares entitled to vote generally in the election of directors; ● provide that special meetings of our stockholders may only be called by the Chief Executive Officer, the Chairman of our Board of Directors or our Board of Directors pursuant to a resolution adopted by a majority of the total number of directors that we would have if there were no vacancies; ● provide that (i) Yorktown Partners LLC (“Yorktown”) and their affiliates are permitted to participate (directly or indirectly) in venture capital and other direct investments in corporations, joint ventures, limited liability companies and other entities conducting business of any kind, nature or description, (ii) Yorktown and their affiliates are permitted to have interests in, participate with, aid and maintain seats on the boards of directors or similar governing bodies of any such investments, in each case that may, are or will be competitive with our business and the business of our subsidiaries or in the same or similar lines of business as us and our subsidiaries, or that could be suitable for us or our subsidiaries and (iii) we have, subject to limited exceptions, renounced, to the fullest extent permitted by law, any interest or expectancy in, or in being offered an opportunity to participate in, such corporate opportunities; ● provide that the provisions of our certificate of incorporation can only be amended or repealed by the affirmative vote of the holders of at least 66 2/3% in voting power of the outstanding shares of our common stock entitled to vote thereon, voting together as a single class; and ● provide that our bylaws can be altered or repealed by (a) our Board of Directors or (b) our stockholders upon the affirmative vote of holders of at least 66 2/3% of the voting power of our common stock outstanding and entitled to vote thereon, voting together as a single class.
Conversely, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which : ● production volumes are less than expected; ● commodity prices rise significantly in excess of our hedged price, resulting in significant cash payments to our hedge counterparties; ● we are unable to find available counterparties in the future; ● the creditworthiness of our hedge counterparties or their guarantors is substantially impaired; or ● counterparties have credit limits that may constrain our ability to hedge additional volumes. ​ If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.
Conversely, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which : 21 Table of Contents ● production volumes are less than expected; ● commodity prices rise significantly in excess of our hedged price, resulting in significant cash payments to our hedge counterparties; ● we are unable to find available counterparties in the future; ● the creditworthiness of our hedge counterparties or their guarantors is substantially impaired; or ● counterparties have credit limits that may constrain our ability to hedge additional volumes. ​ If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.
These factors include the following: ● worldwide and regional economic conditions impacting the global supply and demand for natural gas, NGLs and oil; ● the price and quantity of imports of foreign, and exports of domestic, oil, natural gas and NGLs including liquefied natural gas; ● political conditions in or affecting other producing countries, including conflicts in or among the Middle East, Africa, South America and Russia; ● the level of global exploration and production; ● the level of global inventories; ● events that impact global market demand; ● prevailing prices on local price indexes in the areas in which we operate; ● localized and global supply and demand fundamentals and transportation availability; ● weather conditions; ● technological advances affecting energy consumption; ● the price and availability of alternative fuels; and ● domestic, local and foreign governmental regulation and taxes.
These factors include the following: ● worldwide and regional economic conditions impacting the global supply and demand for natural gas, NGLs and oil; ● the price and quantity of imports of foreign, and exports of domestic, oil, natural gas and NGLs including liquefied natural gas; ● political conditions in or affecting other producing countries, including conflicts in or among the Middle East, Africa, South America and Russia; ● the level of global exploration and production; 20 Table of Contents ● the level of global inventories; ● events that impact global market demand; ● prevailing prices on local price indexes in the areas in which we operate; ● localized and global supply and demand fundamentals and transportation availability; ● weather conditions; ● technological advances affecting energy consumption; ● the price and availability of alternative fuels; and ● domestic, local and foreign governmental regulation and taxes.
Approximately 50% of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.
Approximately 48% of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.
Through December 31, 2023, we have repurchased 28 million shares of our common stock through our share repurchase program at a total cost of $949 million. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws.
Through December 31, 2024, we have repurchased 28 million shares of our common stock through our share repurchase program at a total cost of $949 million. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws.
Dividend Restrictions Our ability to pay dividends is governed by (i) the provisions of Delaware general corporation law, (ii) our Certificate of Incorporation and Bylaws, (iii) the indentures relating to our Senior Notes and 2026 Convertible Notes and (iv) the Credit Facility. We have not paid or declared any dividends on our common stock.
Dividend Restrictions Our ability to pay dividends is governed by (i) the provisions of Delaware general corporation law, (ii) our Certificate of Incorporation and Bylaws, (iii) the indentures relating to our Senior Notes and (iv) the Credit Facility. We have not paid or declared any dividends on our common stock.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives related to climate change or GHG emissions from oil and natural gas facilities could result in increased costs of compliance or costs of consumption, thereby reducing demand for our products.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives related to climate risks or GHG emissions from oil and natural gas facilities could result in increased costs of compliance or costs of consumption, thereby reducing demand for our products.
A corporation is generally an applicable corporation subject to CAMT in any taxable year following a taxable year in which the “average annual adjusted financial statement income” of the corporation and certain of its subsidiaries and affiliates exceeds $1 billion for a specified three taxable year period. We were not an applicable corporation subject to CAMT in 2023.
A corporation is generally an applicable corporation subject to CAMT in any taxable year following a taxable year in which the “average annual adjusted financial statement income” of the corporation and certain of its subsidiaries and affiliates exceeds $1 billion for a specified three taxable year period. We were not an applicable corporation subject to CAMT in 2024.
Such proposed legislative changes include, but are not limited to, (i) the elimination of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) an extension of the amortization period for certain geological and geophysical expenditures, (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies and (v) an increase in the U.S. federal income tax rate applicable to corporations.
Such proposed legislative changes include, but are not limited to, (i) the elimination of the 42 Table of Contents percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) an extension of the amortization period for certain geological and geophysical expenditures, (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies and (v) an increase in the U.S. federal income tax rate applicable to corporations.
Approximately 50% of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Approximately 48% of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022.
The charge is set to start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022.
Our 4.3 Tcfe of estimated proved undeveloped reserves will require an estimated $1.8 billion of development capital over the next five years. Moreover, the development of probable and possible reserves will require additional capital expenditures and such reserves are less certain to be recovered than proved reserves.
Our 4.2 Tcfe of estimated proved undeveloped reserves will require an estimated $1.8 billion of development capital over the next five years. Moreover, the development of probable and possible reserves will require additional capital expenditures and such reserves are less certain to be recovered than proved reserves.
Lower commodity prices may lead to reductions in our drilling and completion program, which may result in insufficient production to fully utilize our firm transportation and processing capacity. Our firm transportation agreements expire at various dates from 2024 to 2058 and our gas processing, gathering, and compression services agreements expire at various dates from 2024 to 2038.
Lower commodity prices may lead to reductions in our drilling and completion program, which may result in insufficient production to fully utilize our firm transportation and processing capacity. Our firm transportation agreements expire at various dates from 2025 to 2058 and our gas processing, gathering, and compression services agreements expire at various dates from 2025 to 2038.
Our ability to make scheduled payments on, or to refinance, our indebtedness, including the Credit Facility, our Senior Notes and our 2026 Convertible Notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control.
Our ability to make scheduled payments on, or to refinance, our indebtedness, including the Credit Facility and our Senior Notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control.
Moreover, economic or other circumstances may change from those contemplated by our 2024 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives. We periodically engage in acquisitions, dispositions and other strategic transactions, including joint ventures.
Moreover, economic or other circumstances may change from those contemplated by our 2025 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives. We periodically engage in acquisitions, dispositions and other strategic transactions, including joint ventures.
Our CAO regularly briefs senior management, the Board of Directors and the Audit Committee on cybersecurity issues as part of our overall enterprise risk management program, including quarterly updates to the Audit Committee, which may include information regarding our exposure to privacy and cybersecurity risks, plans and activities to monitor and mitigate privacy and cybersecurity risks, IT governance policies and programs, including our cybersecurity incident response plan, and legislative and regulatory developments that could impact our privacy and cybersecurity risks.
Our Vice President – IT regularly briefs senior management, the Board of Directors and the Audit Committee on cybersecurity issues as part of our overall enterprise risk management program, including quarterly updates to the Audit Committee , which may include information regarding our exposure to privacy and cybersecurity risks, plans and activities to monitor and mitigate privacy and cybersecurity risks, IT governance policies and programs, including our cybersecurity incident response plan, and legislative and regulatory developments that could impact our privacy and cybersecurity risks.
Also, institutional lenders may decide not to provide funding for oil and natural gas companies or the corresponding infrastructure projects based on climate change related concerns, which could affect our access to capital for potential growth projects.
Also, certain institutional lenders may decide not to provide funding for oil and natural gas companies or the corresponding infrastructure projects based on climate related concerns, which could affect our access to capital for potential growth projects.
If we have insufficient production to meet the minimum volumes or are otherwise unable to fulfill all or a portion of our volume commitments, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and 31 Table of Contents capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations.
If we have insufficient production to meet the minimum volumes or are otherwise unable to fulfill all or a portion of our volume commitments, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations.
We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness, including the Senior Notes and 2026 Convertible Notes.
We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness, including the Senior Notes.
Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of our preferred stock could affect the residual value of our common stock. ITEM 1B. UNRESOLVED STAFF COMMENTS Not applicable. ​ 46 Table of Contents ITEM 1C.
Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of our preferred stock could affect the residual value of our common stock. 44 Table of Contents ITEM 1B. UNRESOLVED STAFF COMMENTS Not applicable. ITEM 1C.
Institutional lenders who provide financing to fossil-fuel energy companies have also become more attentive to sustainable lending practices, and some of them may elect in future not to provide funding for oil and natural gas companies.
Certain institutional lenders who provide financing to fossil-fuel energy companies have also become more attentive to lending practices, and some of them may elect in future not to provide funding for oil and natural gas companies.
Declines in prices could also adversely affect our drilling activities and the amount of natural gas, NGLs and oil that we can produce economically, which may result in our having to make significant downward 21 Table of Contents adjustments to the value of our assets and could cause us to incur non-cash impairment charges to earnings in future periods.
Declines in prices could also adversely affect our drilling activities and the amount of natural gas, NGLs and oil that we can produce economically, which may result in our having to make significant downward adjustments to the value of our assets and could cause us to incur non-cash impairment charges to earnings in future periods.
Cybersecurity attacks are also becoming more sophisticated and include, but 29 Table of Contents are not limited to, ransomware, credential stuffing, spear phishing, social engineering, use of deepfakes (e.g., highly realistic synthetic media generated by artificial intelligence) and other attempts to gain unauthorized access to data for purposes of extortion or other malfeasance.
Cybersecurity attacks are also becoming more sophisticated and include, but are not limited to, ransomware, credential stuffing, spear phishing, social engineering, use of deepfakes (e.g., highly realistic synthetic media generated by artificial intelligence) and other attempts to gain unauthorized access to data for purposes of extortion or other malfeasance.
In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. The federal regulation of methane from oil and gas facilities has been subject to substantial uncertainty in recent years.
In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. 39 Table of Contents The federal regulation of methane from oil and gas facilities has been subject to substantial uncertainty in recent years.
Our producing properties are geographically concentrated in the Appalachian Basin in West Virginia and Ohio. As of December 31, 2023, all of our total estimated proved reserves were attributable to properties located in this area.
Our producing properties are geographically concentrated in the Appalachian Basin in West Virginia and Ohio. As of December 31, 2024, all of our total estimated proved reserves were attributable to properties located in this area.
If activism against oil and natural gas exploration and development persists or increases, there could be a material adverse effect on our business, financial condition and results of operations. 30 Table of Contents Customer Concentration and Credit Risk The inability of our significant customers to meet their obligations to us may adversely affect our financial results.
If activism against oil and natural gas exploration and development persists or increases, there could be a material adverse effect on our business, financial condition and results of operations. Customer Concentration and Credit Risk The inability of our significant customers to meet their obligations to us may adversely affect our financial results.
Such agreements also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses. 33 Table of Contents Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals , which may adversely affect the market price of our common stock.
Such agreements also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses. Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals , which may adversely affect the market price of our common stock.
Although the market for high-yield debt securities has improved compared to 2020, if the high-yield market deteriorates, or if we are unable to access alternative means of debt or equity financing on acceptable terms or at all, we may be unable to implement our development plan or otherwise carry out our business plan, which could have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.
Although the market for senior note debt securities has improved compared to 2020, if the senior note market deteriorates, or if we are unable to access alternative means of debt or equity financing on acceptable terms or at all, we may be unable to implement our development plan or otherwise carry out our business plan, which could have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.
A cyberattack or security breach could result in liability resulting from data privacy or cybersecurity claims, liability under data privacy laws, regulatory penalties, damage to our reputation, long-lasting loss of confidence in us, or additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could have a material and adverse effect on our business, financial condition or results of operations.
A successful cyberattack or security breach could result in liability resulting from data privacy or cybersecurity 29 Table of Contents claims, liability under data privacy laws, regulatory penalties, damage to our reputation, long-lasting loss of confidence in us, or additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could have a material and adverse effect on our business, financial condition or results of operations.
The standardized measure of discounted future net cash flows from our proved reserves is not the same as the current market value of our estimated oil and gas reserves. Investors should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and gas reserves.
Investors should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and gas reserves.
Our net capital budget for 2024 is $725 million to $800 million. Our budget includes: a range of $650 million to $700 million for drilling and completion and $75 million to $100 million for leasehold expenditures. Our capital budget excludes acquisitions, except for leasehold acquisitions.
Our net capital budget for 2025 is $725 million to $800 million. Our budget includes: a range of $650 million to $700 million for drilling and completion and $75 million to $100 million for leasehold expenditures. Our capital budget excludes acquisitions, except for leasehold acquisitions.
If such officers and employees do not devote sufficient attention to the management and operation of our business, our financial results may suffer. Related Parties Conflicts of interest will arise from time to time between Antero Midstream and us, and Antero Midstream may favor its own interests to the detriment of us and our stockholders.
If such officers and employees do not devote sufficient attention to the management and operation of our business, our financial results may suffer. 41 Table of Contents Related Parties Conflicts of interest will arise from time to time between Antero Midstream and us, and Antero Midstream may favor its own interests to the detriment of us and our stockholders.
We are unable to predict the extent to which another world health event 22 Table of Contents could impact our business results and operations, but such events could give rise to an imbalance between the supply of and demand for our products that could adversely affect our financial condition and results of operations .
We are unable to predict the extent to which another world health event could impact our business results and operations, but such events could give rise to an imbalance between the supply of and demand for our products that could adversely affect our financial condition and results of operations .
Moreover, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively or recruit or retain employees, which may adversely affect our operations. Such ESG matters may also impact Antero Midstream and our 27 Table of Contents customers, which may adversely impact our business, financial condition or results of operations.
Moreover, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively or recruit or retain employees, which may adversely affect our operations. Such ESG matters may also impact Antero Midstream and our customers, which may adversely impact our business, financial condition or results of operations.
There is no assurance that we will pay any cash dividends on our common stock. 49 Table of Contents Stock Performance Graph The graph below shows the cumulative total shareholder return assuming the investment of $100 on December 31, 2018 in each of our common stock, the Standard & Poor’s 500 (“S&P 500”) Index, and the Dow Jones U.S.
There is no assurance that we will pay any cash dividends on our common stock. 47 Table of Contents Stock Performance Graph The graph below shows the cumulative total shareholder return assuming the investment of $100 on December 31, 2019 in each of our common stock, the Standard & Poor’s 500 (“S&P 500”) Index, and the Dow Jones U.S.
Our inability to complete a transaction or to achieve our strategic or financial goals in any transaction could have significant adverse effects on our financial position, results of operations and cash flows. World health events may materially adversely affect our business.
Our inability to complete a transaction or to achieve our strategic or financial goals in any transaction could have significant adverse effects on our financial position, results of operations and cash flows. 28 Table of Contents World health events may materially adversely affect our business.
Transportation rates on FERC-regulated pipelines are subject to change, and depending on the amount of any increase, such an increase in rates could have an adverse effect on our results of operations. As of December 31, 2023, our long- term contractual obligations under agreements with minimum volume commitments totaled $10.4 billion over the term of the contracts.
Transportation rates on FERC-regulated pipelines are subject to change, and depending on the amount of any increase, such an increase in rates could have an adverse effect on our results of operations. As of December 31, 2024, our long- term contractual obligations under agreements with minimum volume commitments totaled $9.4 billion over the term of the contracts.
Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,544,521 per day for each violation and disgorgement of profits associated with any violation.
Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,584,648 per day for each violation and disgorgement of profits associated with any violation.
Given uncertainties related to the use of emerging technologies, the state of markets for and the availability of verified carbon offsets, we cannot predict whether or not we will be able to timely meet these goals, if at all.
Given uncertainties related to the use of emerging technologies, the state of markets 26 Table of Contents for and the availability of verified carbon offsets, we cannot predict whether or not we will be able to timely meet these goals, if at all.
Our operations are subject to a series of risks related to climate change that could result in increased operating costs, limit the areas in which we may conduct oil and natural gas exploration and production activities, and reduce demand for our products. The threat of climate change continues to attract considerable attention in the United States and in foreign countries.
Our operations are subject to a series of risks related to climate that could result in increased operating costs, limit the areas in which we may conduct oil and natural gas exploration and production activities, and reduce demand for our products. Climate risks continue to attract considerable attention in the United States and in foreign countries.
Specific factors that may have a significant effect on the market price for our common stock include: ● our operating and financial performance and prospects and the trading price of our common stock; ● the level of any dividends we may declare; ● quarterly variations in the rate of growth of our financial indicators, such as net income and revenues; ● levels of indebtedness; ● changes in revenue or earnings estimates or publication of research reports by analysts; ● speculation by the press or investment community; ● sales of our common stock by other stockholders; ● announcements by us or our competitors of significant contracts, acquisitions, strategic partnerships, joint ventures, securities offerings or capital commitments; ● general market conditions; ● changes in accounting standards, policies, guidance, interpretations or principles; ● adverse changes in tax laws or regulations; and ● domestic and international economic, legal and regulatory factors related to our performance. 45 Table of Contents Sales of a substantial amount of shares of our common stock in the public market could adversely affect the market price of our shares.
Specific factors that may have a significant effect on the market price for our common stock include: ● our operating and financial performance and prospects and the trading price of our common stock; ● the level of any dividends we may declare; ● quarterly variations in the rate of growth of our financial indicators, such as net income and revenues; ● levels of indebtedness; ● changes in revenue or earnings estimates or publication of research reports by analysts; ● speculation by the press or investment community; ● sales of our common stock by other stockholders; ● announcements by us or our competitors of significant contracts, acquisitions, strategic partnerships, joint ventures, securities offerings or capital commitments; 43 Table of Contents ● general market conditions; ● changes in accounting standards, policies, guidance, interpretations or principles; ● adverse changes in tax laws or regulations; and ● domestic and international economic, legal and regulatory factors related to our performance.
Our principal exposures to credit risk are through receivables resulting from the sale of our natural gas, NGLs and oil production that we market to energy companies, end users, and refineries ($384 million as of December 31, 2023). We are also subject to credit risk due to concentration of receivables with several significant customers.
Our principal exposures to credit risk are through receivables resulting from the sale of our natural gas, NGLs and oil production that we market to energy companies, end users, and refineries ($453 million as of December 31, 2024). We are also subject to credit risk due to concentration of receivables with several significant customers.
The Governor of California has directed further consideration of the implementation deadlines for each of the laws, and there is potential for legal challenges to be filed with respect to the scope of the law, but, absent clarification or revisions to the law, alongside the SEC proposed rule, finalization and implementation may result in additional costs to comply with these disclosure requirements as well as increased costs of and restrictions on access to capital.
The Governor of California has directed further consideration of the implementation deadlines for each of the laws, and there is potential for legal challenges to be filed with respect to the scope of the law, but, absent clarification or revisions to the law, alongside the SEC final rule, if implemented, may result in additional costs to comply with these disclosure requirements as well as increased costs of and restrictions on access to capital.
We have proved undeveloped reserves of 337 Bcfe related to such acreage that is subject to renewal prior to drilling. In addition, 12% of our natural gas leases related to our Appalachian Basin acreage require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases.
We have proved undeveloped reserves of 366 Bcfe related to such acreage that is subject to renewal prior to drilling. In addition, 14% of our natural gas leases related to our Appalachian Basin acreage require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases.
Additionally, in response to concerns related to climate change, companies in the oil and natural gas industry may be exposed to increasing financial risks. Financial institutions, including investment advisors and certain sovereign wealth, pension and endowment funds, may elect in the future to shift some or all of their investment into non-oil and natural gas related sectors.
Additionally, companies in the oil and natural gas industry may be exposed to increasing financial risks. Financial institutions, including investment advisors and certain sovereign wealth, pension and endowment funds, may elect in the future to shift some or all of their investment into non-oil and natural gas related sectors.
Additionally, political, litigation, and financial risks may result in (i) restriction or cancellation of certain oil and natural gas production activities, (ii) incurrence of obligations for alleged damages resulting from climate change, or (iii) impairment of our ability to continue operating in an economic manner.
Additionally, political, litigation, and financial risks may result in (i) restriction or cancellation of certain oil and natural gas production activities, (ii) incurrence of obligations for alleged damages, or (iii) impairment of our ability to continue operating in an economic manner.
Our cash flows from operations and access to capital are subject to a number of variables, including: ● our proved reserves; ● the level of hydrocarbons we are able to produce from existing wells; ● the prices at which our production is sold; ● our ability to acquire, locate and produce new reserves; ● the value of our commodity derivative portfolio; and ● our ability to borrow under the Credit Facility.
Our cash flows from operations and access to capital are subject to a number of variables, including: ● our proved reserves; ● the level of hydrocarbons we are able to produce from existing wells; ● the prices at which our production is sold; ● our ability to acquire, locate and produce new reserves; 35 Table of Contents ● the value of our commodity derivative portfolio; and ● availability under the Credit Facility.
Reserves The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced. As of December 31, 2023, 24% of our total estimated proved reserves were classified as proved undeveloped.
Reserves The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced. As of December 31, 2024, 23% of our total estimated proved reserves were classified as proved undeveloped.
If our revenues or the borrowing base under the Credit Facility decrease as a result of sustained periods of low natural gas, NGLs and oil prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels.
If our revenues decrease as a result of sustained periods of low natural gas, NGLs and oil prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels.
Separately, the SEC has also from time to time applied additional scrutiny to existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures misleading or deficient .
Separately, the SEC has also from time to time applied additional scrutiny to existing climate-change related disclosures in public filings, and there is the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures misleading or deficient .
These expectations are based upon assumptions we have made regarding, among other things, our income, capital expenditures and net working capital, and upon our NOL carryforwards not becoming subject to future limitation under Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), or otherwise. ​ Section 382 generally imposes an annual limitation on the amount of NOL carryforwards that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382).
These expectations are based upon assumptions we have made regarding, among other things, our income, capital expenditures and net working capital, and upon our NOL carryforwards not becoming subject to future limitation under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), or otherwise. ​ Section 382 and Section 383 of the Code generally impose an annual limitation on the amount of NOL carryforwards and tax credit carryforwards that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382 of the Code).
Plans to remediate cybersecurity risks are approved and monitored regularly for completion. Incident Identification and Response We have implemented a monitoring and detection system, with oversight from our CAO to help promptly identify cybersecurity incidents.
Plans to remediate cybersecurity risks are approved and monitored regularly for completion. Incident Identification and Response We have implemented a monitoring and detection system, with oversight from our Vice President – IT to help promptly identify cybersecurity incidents.
Assuming 2024 production is unchanged from 2023 production, we estimate that we will incur annual net marketing costs of $0.05 per Mcfe to $0.07 per Mcfe in 2024 for unutilized transportation capacity depending on the amount of unutilized capacity that can be marketed to third parties or utilized to transport third-party gas and capture positive basis differentials.
Assuming 2025 production is unchanged from 2024 production, we estimate that we will incur annual net marketing costs of $0.04 per Mcfe to $0.06 per Mcfe in 2025 for unutilized transportation capacity depending on the amount of unutilized capacity that can be marketed to third parties or utilized to transport third-party gas and capture positive basis differentials.
Any significant variance in our interpretation of current tax laws, including as result of the release of final Treasury Regulations or other interpretive guidance implementing the Tax Cuts and Jobs Act or the IRA 2022, or a successful challenge of one or more of our tax positions by the IRS or other state or local tax authorities could increase our future tax liabilities and adversely affect our operating results and cash flows.
Any significant variance in our interpretation of current tax laws, including as result of the release of final Treasury Regulations or other interpretive guidance, or a successful challenge of one or more of our tax positions by the IRS or other state or local tax authorities could increase our future tax liabilities and adversely affect our operating results and cash flows.
If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base.
If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness.
For example, during 2023, we had average outstanding borrowings under the Credit Facility of $342 million, and the impact of a 1.0% increase in interest rates on this amount of indebtedness would result in increased interest expense for that period of $3 million and a corresponding decrease in our cash flows and net income before the effects of income taxes.
For example, during 2024, we had average outstanding borrowings under the Credit Facility of $440 million, and the impact of a 1.0% increase in interest rates on this amount of indebtedness would result in increased interest expense for that period of $4 million and a corresponding decrease in our cash flows and net income before the effects of income taxes.
Taxes Our future tax liabilities may be greater than expected if our net operating loss (“NOL”) carryforwards are limited, we do not generate expected deductions, or tax authorities challenge our tax positions. ​ As of December 31, 2023, we have U.S. federal and state NOL carryforwards of $1.0 billion and $1.9 billion, respectively.
Taxes Our future tax liabilities may be greater than expected if our net operating loss (“NOL”) and tax credit carryforwards are limited, we do not generate expected deductions, or tax authorities challenge our tax positions. ​ As of December 31, 2024, we have U.S. federal and state NOL carryforwards of $0.6 billion and $1.9 billion, respectively, and U.S. federal tax credit carryforwards of $148 million.
While oil and natural gas prices were substantially lower in 2023 than they were in 2022, the markets for these commodities have historically been volatile, and these markets will likely continue to be volatile in the future.
Natural gas prices were substantially lower in 2024 than they were in 2023, while oil prices were relatively consistent in 2024 and 2023. The markets for these commodities have historically been volatile, and these markets will likely continue to be volatile in the future.
In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness and may result in us having to post collateral with, or provide letters of credit to, certain transactional counterparties.
In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness, could result in more onerous restrictions in our debt securities and facilities and may result in us having to post collateral with, or provide letters of credit to, certain transactional counterparties.
We may not be able to develop, find or 23 Table of Contents acquire sufficient additional reserves to replace our current and future production, and any such acquisition and development may be offset by any asset disposition.
We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production, and any such acquisition and development may be offset by any asset disposition.
Increasing attention to climate change, societal expectations on companies to address climate change, investor, regulatory and societal expectations regarding voluntary and mandatory ESG disclosures and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, negative impacts on our stock price and reduced access to capital markets.
Stakeholder attention to climate risks, societal expectations on companies related to climate risks, investor, regulatory and societal expectations regarding voluntary and mandatory ESG disclosures and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, negative impacts on our stock price and reduced access to capital markets.
Our common stock is listed on the New York Stock Exchange and traded under the symbol “AR.” On February 9, 2024, our common stock was held by 103 holders of record. The number of holders does not include the shareholders for whom shares of our common stock are held in a “nominee” or “street” name.
Our common stock is listed on the New York Stock Exchange and traded under the symbol “AR.” On February 7, 2025, our common stock was held by 99 holders of record. The number of holders does not include the shareholders for whom shares of our common stock are held in a “nominee” or “street” name.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities. We may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our exploration, development and production activities.
We may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our exploration, development and production activities.
As a result, 26 Table of Contents management’s view of the likelihood of a material and adverse financial impact from any such proceeding may change in the future. See Note 15—Contingencies to the consolidated financial statements for more information on legal proceedings. Increasing attention to ESG matters and conservation measures may adversely impact our business.
As a result, management’s view of the likelihood of a material and adverse financial impact from any such proceeding may change in the future. See Note 15—Contingencies to the consolidated financial statements for additional information on legal proceedings. ESG matters and conservation measures may adversely impact our business.
Our CAO oversees the Company’s cybersecurity strategy, cybersecurity and data privacy policies, measures and controls, and Board of Directors and Audit Committee communications on cybersecurity matters.
Our Vice President – IT oversees the Company’s cybersecurity strategy, cybersecurity and data privacy policies, measures and controls, and Board of Directors and Audit Committee communications on cybersecurity matters.
A default, if not waived, could result in acceleration of the indebtedness outstanding under the facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable.
A default, if not waived, could result in our inability to access loans under the Credit Facility or acceleration of the indebtedness outstanding under the Credit Facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable.
These restrictions, 37 Table of Contents together with those in the indentures governing our Senior Notes and our 2026 Convertible Notes, may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities.
These restrictions, together with those in the indentures governing our Senior Notes may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities.
The oil and gas industry is capital intensive. We make, and expect to continue to make, substantial capital expenditures for the exploration, development, production, and acquisition of oil and gas reserves. Our cash flow used in investing activities for 2023 35 Table of Contents included drilling and completion costs of $964 million and leasehold expenditures of $151 million.
The oil and gas industry is capital intensive. We make, and expect to continue to make, substantial capital expenditures for the exploration, development, production, and acquisition of oil and gas reserves. Our cash flow used in investing activities for 2024 included drilling and completion costs of $615 million and leasehold expenditures of $91 million.
The rule also establishes a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements. Fines and penalties for violations of these rules can be substantial. It is likely, however, that the final rule and its requirements will be subject to legal challenges.
The rule also establishes a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements. Fines and penalties for violations of these rules can be substantial.
Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. The Inflation Reduction Act could accelerate the transition to a low carbon economy and could impose new costs on our operations.
Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. The Inflation Reduction Act could adversely impact demand for oil and gas and could impose new costs on our operations.
As a result of their investments in Antero Midstream, Mr. Rady and Yorktown may have conflicting interests with other stockholders. Conflicts of interest could arise in the future between us, on the one hand, and Mr.
Rady and Yorktown may have conflicting interests with other stockholders. Conflicts of interest could arise in the future between us, on the one hand, and Mr.

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Item 6. [Reserved]

Selected Financial Data — reserved (removed by SEC in 2021)

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Biggest changeYear Ended December 31, 2022 Compared to Year Ended December 31, 2023 The operating results of our reportable segments were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2022 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliate Total Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 5,520,419 ​ ​ — ​ ​ — ​ ​ — ​ ​ 5,520,419 ​ Natural gas liquids sales ​ ​ 2,498,657 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,498,657 ​ Oil sales ​ ​ 275,673 ​ ​ — ​ ​ — ​ ​ — ​ ​ 275,673 ​ Commodity derivative fair value losses ​ ​ (1,615,836) ​ ​ — ​ ​ — ​ ​ — ​ ​ (1,615,836) ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 919,985 ​ ​ (919,985) ​ ​ — ​ Marketing ​ ​ — ​ ​ 416,758 ​ ​ — ​ ​ — ​ ​ 416,758 ​ Amortization of deferred revenue, VPP ​ ​ 37,603 ​ ​ — ​ ​ — ​ ​ — ​ ​ 37,603 ​ Other revenue and income ​ ​ 5,162 ​ ​ — ​ ​ — ​ ​ — ​ ​ 5,162 ​ Total revenue ​ ​ 6,721,678 ​ ​ 416,758 ​ ​ 919,985 ​ ​ (919,985) ​ ​ 7,138,436 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 99,595 ​ ​ — ​ ​ — ​ ​ — ​ ​ 99,595 ​ Gathering and compression ​ ​ 892,533 ​ ​ — ​ ​ 75,889 ​ ​ (75,889) ​ ​ 892,533 ​ Processing ​ ​ 869,744 ​ ​ — ​ ​ — ​ ​ — ​ ​ 869,744 ​ Transportation ​ ​ 843,103 ​ ​ — ​ ​ — ​ ​ — ​ ​ 843,103 ​ Water handling ​ ​ — ​ ​ — ​ ​ 104,365 ​ ​ (104,365) ​ ​ — ​ Production and ad valorem taxes ​ ​ 287,406 ​ ​ — ​ ​ — ​ ​ — ​ ​ 287,406 ​ Marketing ​ ​ — ​ ​ 531,304 ​ ​ — ​ ​ — ​ ​ 531,304 ​ Exploration and mine expenses ​ ​ 7,409 ​ ​ — ​ ​ — ​ ​ — ​ ​ 7,409 ​ General and administrative (excluding equity-based compensation) ​ ​ 137,466 ​ ​ — ​ ​ 42,471 ​ ​ (42,471) ​ ​ 137,466 ​ Equity-based compensation ​ ​ 35,443 ​ ​ — ​ ​ 19,654 ​ ​ (19,654) ​ ​ 35,443 ​ Depletion, depreciation and amortization ​ ​ 680,600 ​ ​ — ​ ​ 131,762 ​ ​ (131,762) ​ ​ 680,600 ​ Impairment of property and equipment ​ ​ 149,731 ​ ​ — ​ ​ 3,702 ​ ​ (3,702) ​ ​ 149,731 ​ Accretion of asset retirement obligations ​ ​ 4,627 ​ ​ — ​ ​ 222 ​ ​ (222) ​ ​ 4,627 ​ Contract termination, loss contingency and other operating expenses ​ ​ 25,099 ​ ​ — ​ ​ 4,705 ​ ​ (4,705) ​ ​ 25,099 ​ Loss (gain) on sale of assets ​ ​ 471 ​ ​ — ​ ​ (2,251) ​ ​ 2,251 ​ ​ 471 ​ Total operating expenses ​ ​ 4,033,227 ​ ​ 531,304 ​ ​ 380,519 ​ ​ (380,519) ​ ​ 4,564,531 ​ Operating income (loss) ​ $ 2,688,451 ​ ​ (114,546) ​ ​ 539,466 ​ ​ (539,466) ​ ​ 2,573,905 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 72,327 ​ ​ — ​ ​ 94,218 ​ ​ (94,218) ​ ​ 72,327 ​ ​ ​ 56 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2023 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliate Total Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 2,192,349 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,192,349 ​ Natural gas liquids sales ​ ​ 1,836,950 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,836,950 ​ Oil sales ​ ​ 247,146 ​ ​ — ​ ​ — ​ ​ — ​ ​ 247,146 ​ Commodity derivative fair value gains ​ ​ 166,324 ​ ​ — ​ ​ — ​ ​ — ​ ​ 166,324 ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 1,041,771 ​ ​ (1,041,771) ​ ​ — ​ Marketing ​ ​ — ​ ​ 206,122 ​ ​ — ​ ​ — ​ ​ 206,122 ​ Amortization of deferred revenue, VPP ​ ​ 30,552 ​ ​ — ​ ​ — ​ ​ — ​ ​ 30,552 ​ Other revenue and income ​ ​ 2,529 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,529 ​ Total revenue ​ ​ 4,475,850 ​ ​ 206,122 ​ ​ 1,041,771 ​ ​ (1,041,771) ​ ​ 4,681,972 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 118,441 ​ ​ — ​ ​ — ​ ​ — ​ ​ 118,441 ​ Gathering and compression ​ ​ 858,462 ​ ​ — ​ ​ 95,507 ​ ​ (95,507) ​ ​ 858,462 ​ Processing ​ ​ 1,014,181 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,014,181 ​ Transportation ​ ​ 769,715 ​ ​ — ​ ​ — ​ ​ — ​ ​ 769,715 ​ Water handling ​ ​ — ​ ​ — ​ ​ 117,658 ​ ​ (117,658) ​ ​ — ​ Production and ad valorem taxes ​ ​ 158,855 ​ ​ — ​ ​ — ​ ​ — ​ ​ 158,855 ​ Marketing ​ ​ — ​ ​ 284,965 ​ ​ — ​ ​ — ​ ​ 284,965 ​ Exploration and mine expenses ​ ​ 2,700 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,700 ​ General and administrative (excluding equity-based compensation) ​ ​ 164,997 ​ ​ — ​ ​ 39,462 ​ ​ (39,462) ​ ​ 164,997 ​ Equity-based compensation ​ ​ 59,519 ​ ​ — ​ ​ 31,606 ​ ​ (31,606) ​ ​ 59,519 ​ Depletion, depreciation and amortization ​ ​ 689,966 ​ ​ — ​ ​ 136,059 ​ ​ (136,059) ​ ​ 689,966 ​ Impairment of property and equipment ​ ​ 51,302 ​ ​ — ​ ​ 146 ​ ​ (146) ​ ​ 51,302 ​ Accretion of asset retirement obligations ​ ​ 3,244 ​ ​ — ​ ​ 177 ​ ​ (177) ​ ​ 3,244 ​ Loss (gain) on sale of assets ​ ​ (447) ​ ​ — ​ ​ 6,030 ​ ​ (6,030) ​ ​ (447) ​ Contract termination, loss contingency and other operating expenses ​ ​ 29,179 ​ ​ 23,763 ​ ​ 3,264 ​ ​ (3,264) ​ ​ 52,942 ​ Total operating expenses ​ ​ 3,920,114 ​ ​ 308,728 ​ ​ 429,909 ​ ​ (429,909) ​ ​ 4,228,842 ​ Operating income (loss) ​ $ 555,736 ​ ​ (102,606) ​ ​ 611,862 ​ ​ (611,862) ​ ​ 453,130 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 82,952 ​ ​ — ​ ​ 105,456 ​ ​ (105,456) ​ ​ 82,952 ​ ​ 57 Table of Contents Exploration and Production Segment The following table sets forth selected operating data of the exploration and production segment: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended ​ Amount of ​ ​ ​ ​ ​ ​ December 31, ​ Increase ​ Percent ​ ​ ​ 2022 2023 (Decrease) Change ​ ​ Production data (1) (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (Bcf) ​ ​ 798 ​ ​ 815 ​ ​ 17 ​ 2 % ​ C2 Ethane (MBbl) ​ ​ 18,818 ​ ​ 24,657 ​ ​ 5,839 ​ 31 % ​ C3+ NGLs (MBbl) ​ ​ 39,914 ​ ​ 41,927 ​ ​ 2,013 ​ 5 % ​ Oil (MBbl) ​ ​ 3,223 ​ ​ 3,874 ​ ​ 651 ​ 20 % ​ Combined (Bcfe) ​ ​ 1,170 ​ ​ 1,238 ​ ​ 68 ​ 6 % ​ Daily combined production (MMcfe/d) ​ ​ 3,204 ​ ​ 3,392 ​ ​ 188 ​ 6 % ​ Average prices before effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 6.92 ​ ​ 2.69 ​ ​ (4.23) ​ (61) % ​ C2 Ethane (per Bbl) (4) ​ $ 20.41 ​ ​ 10.14 ​ ​ (10.27) ​ (50) % ​ C3+ NGLs (per Bbl) ​ $ 52.98 ​ ​ 37.85 ​ ​ (15.13) ​ (29) % ​ Oil (per Bbl) ​ $ 85.53 ​ ​ 63.80 ​ ​ (21.73) ​ (25) % ​ Weighted Average Combined (per Mcfe) ​ $ 7.09 ​ ​ 3.45 ​ ​ (3.64) ​ (51) % ​ Average realized prices after effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 4.54 ​ ​ 2.66 ​ ​ (1.88) ​ (41) % ​ C2 Ethane (per Bbl) (4) ​ $ 20.38 ​ ​ 10.14 ​ ​ (10.24) ​ (50) % ​ C3+ NGLs (per Bbl) ​ $ 52.63 ​ ​ 37.80 ​ ​ (14.83) ​ (28) % ​ Oil (per Bbl) ​ $ 84.88 ​ ​ 63.50 ​ ​ (21.38) ​ (25) % ​ Weighted Average Combined (per Mcfe) ​ $ 5.46 ​ ​ 3.43 ​ ​ (2.03) ​ (37) % ​ Average costs (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 0.09 ​ ​ 0.10 ​ ​ 0.01 ​ 11 % ​ Gathering and compression ​ $ 0.76 ​ ​ 0.69 ​ ​ (0.07) ​ (9) % ​ Processing ​ $ 0.74 ​ ​ 0.82 ​ ​ 0.08 ​ 11 % ​ Transportation ​ $ 0.72 ​ ​ 0.62 ​ ​ (0.10) ​ (14) % ​ Production and ad valorem taxes ​ $ 0.25 ​ ​ 0.13 ​ ​ (0.12) ​ (48) % ​ Marketing expense, net ​ $ 0.10 ​ ​ 0.06 ​ ​ (0.04) ​ (40) % ​ General and administrative (excluding equity-based compensation) ​ $ 0.12 ​ ​ 0.13 ​ ​ 0.01 ​ 8 % ​ Depletion, depreciation, amortization and accretion ​ $ 0.59 ​ ​ 0.56 ​ ​ (0.03) ​ (5) % ​ (1) Production data excludes volumes related to the VPP.
Biggest changeYear Ended December 31, 2023 Compared to Year Ended December 31, 2024 The operating results of our reportable segments were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2023 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream (1) Affiliate Total Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 2,192,349 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,192,349 ​ Natural gas liquids sales ​ ​ 1,836,950 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,836,950 ​ Oil sales ​ ​ 247,146 ​ ​ — ​ ​ — ​ ​ — ​ ​ 247,146 ​ Commodity derivative fair value gains ​ ​ 166,324 ​ ​ — ​ ​ — ​ ​ — ​ ​ 166,324 ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 1,041,771 ​ ​ (1,041,771) ​ ​ — ​ Marketing ​ ​ — ​ ​ 206,122 ​ ​ — ​ ​ — ​ ​ 206,122 ​ Amortization of deferred revenue, VPP ​ ​ 30,552 ​ ​ — ​ ​ — ​ ​ — ​ ​ 30,552 ​ Other revenue and income ​ ​ 2,529 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,529 ​ Total revenue ​ ​ 4,475,850 ​ ​ 206,122 ​ ​ 1,041,771 ​ ​ (1,041,771) ​ ​ 4,681,972 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 118,441 ​ ​ — ​ ​ — ​ ​ — ​ ​ 118,441 ​ Gathering and compression ​ ​ 858,462 ​ ​ — ​ ​ 95,507 ​ ​ (95,507) ​ ​ 858,462 ​ Processing ​ ​ 1,014,181 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,014,181 ​ Transportation ​ ​ 769,715 ​ ​ — ​ ​ — ​ ​ — ​ ​ 769,715 ​ Water handling ​ ​ — ​ ​ — ​ ​ 117,658 ​ ​ (117,658) ​ ​ — ​ Production and ad valorem taxes ​ ​ 158,855 ​ ​ — ​ ​ — ​ ​ — ​ ​ 158,855 ​ Marketing ​ ​ — ​ ​ 284,965 ​ ​ — ​ ​ — ​ ​ 284,965 ​ Exploration and mine expenses ​ ​ 2,700 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,700 ​ General and administrative (excluding equity-based compensation) ​ ​ 164,997 ​ ​ — ​ ​ 39,462 ​ ​ (39,462) ​ ​ 164,997 ​ Equity-based compensation ​ ​ 59,519 ​ ​ — ​ ​ 31,606 ​ ​ (31,606) ​ ​ 59,519 ​ Depletion, depreciation and amortization ​ ​ 746,849 ​ ​ — ​ ​ 136,059 ​ ​ (136,059) ​ ​ 746,849 ​ Impairment of property and equipment ​ ​ 51,302 ​ ​ — ​ ​ 146 ​ ​ (146) ​ ​ 51,302 ​ Accretion of asset retirement obligations ​ ​ 3,244 ​ ​ — ​ ​ 177 ​ ​ (177) ​ ​ 3,244 ​ Loss (gain) on sale of assets ​ ​ (447) ​ ​ — ​ ​ 6,030 ​ ​ (6,030) ​ ​ (447) ​ Contract termination, loss contingency, settlements and other operating expenses ​ ​ 29,179 ​ ​ 23,763 ​ ​ 3,264 ​ ​ (3,264) ​ ​ 52,942 ​ Total operating expenses ​ ​ 3,976,997 ​ ​ 308,728 ​ ​ 429,909 ​ ​ (429,909) ​ ​ 4,285,725 ​ Operating income (loss) ​ $ 498,853 ​ ​ (102,606) ​ ​ 611,862 ​ ​ (611,862) ​ ​ 396,247 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 82,952 ​ ​ — ​ ​ 105,456 ​ ​ (105,456) ​ ​ 82,952 ​ (1) Amounts reflect those recorded in Antero Midstream Corporation’s consolidated financial statements. ​ ​ 54 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2024 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream (1) Affiliate Total Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 1,818,297 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,818,297 ​ Natural gas liquids sales ​ ​ 2,066,975 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,066,975 ​ Oil sales ​ ​ 230,027 ​ ​ — ​ ​ — ​ ​ — ​ ​ 230,027 ​ Commodity derivative fair value gains ​ ​ 731 ​ ​ — ​ ​ — ​ ​ — ​ ​ 731 ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 1,106,193 ​ ​ (1,106,193) ​ ​ — ​ Marketing ​ ​ — ​ ​ 179,069 ​ ​ — ​ ​ — ​ ​ 179,069 ​ Amortization of deferred revenue, VPP ​ ​ 27,101 ​ ​ — ​ ​ — ​ ​ — ​ ​ 27,101 ​ Other revenue and income ​ ​ 3,396 ​ ​ — ​ ​ — ​ ​ — ​ ​ 3,396 ​ Total revenue ​ ​ 4,146,527 ​ ​ 179,069 ​ ​ 1,106,193 ​ ​ (1,106,193) ​ ​ 4,325,596 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 118,693 ​ ​ — ​ ​ — ​ ​ — ​ ​ 118,693 ​ Gathering and compression ​ ​ 897,160 ​ ​ — ​ ​ 103,053 ​ ​ (103,053) ​ ​ 897,160 ​ Processing ​ ​ 1,069,887 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,069,887 ​ Transportation ​ ​ 735,883 ​ ​ — ​ ​ — ​ ​ — ​ ​ 735,883 ​ Water handling ​ ​ — ​ ​ — ​ ​ 114,923 ​ ​ (114,923) ​ ​ — ​ Production and ad valorem taxes ​ ​ 207,671 ​ ​ — ​ ​ — ​ ​ — ​ ​ 207,671 ​ Marketing ​ ​ — ​ ​ 244,906 ​ ​ — ​ ​ — ​ ​ 244,906 ​ Exploration ​ ​ 2,618 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,618 ​ General and administrative (excluding equity-based compensation) ​ ​ 162,876 ​ ​ — ​ ​ 41,754 ​ ​ (41,754) ​ ​ 162,876 ​ Equity-based compensation ​ ​ 66,462 ​ ​ — ​ ​ 44,332 ​ ​ (44,332) ​ ​ 66,462 ​ Depletion, depreciation and amortization ​ ​ 762,068 ​ ​ — ​ ​ 140,000 ​ ​ (140,000) ​ ​ 762,068 ​ Impairment of property and equipment ​ ​ 47,433 ​ ​ — ​ ​ 332 ​ ​ (332) ​ ​ 47,433 ​ Accretion of asset retirement obligations ​ ​ 3,759 ​ ​ — ​ ​ 189 ​ ​ (189) ​ ​ 3,759 ​ Loss on sale of assets ​ ​ 862 ​ ​ — ​ ​ 723 ​ ​ (723) ​ ​ 862 ​ Contract termination, loss contingency, settlements and other operating expenses ​ ​ 4,858 ​ ​ — ​ ​ 1,721 ​ ​ (1,721) ​ ​ 4,858 ​ Total operating expenses ​ ​ 4,080,230 ​ ​ 244,906 ​ ​ 447,027 ​ ​ (447,027) ​ ​ 4,325,136 ​ Operating income (loss) ​ $ 66,297 ​ ​ (65,837) ​ ​ 659,166 ​ ​ (659,166) ​ ​ 460 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 93,787 ​ ​ — ​ ​ 110,573 ​ ​ (110,573) ​ ​ 93,787 ​ (1) Amounts reflect those recorded in Antero Midstream Corporation’s consolidated financial statements. ​ 55 Table of Contents Exploration and Production Segment The following table sets forth selected operating data of the exploration and production segment: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended ​ Amount of ​ ​ ​ ​ ​ ​ December 31, ​ Increase ​ Percent ​ ​ ​ 2023 2024 (Decrease) Change ​ ​ Production data (1) (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (Bcf) ​ ​ 815 ​ ​ 793 ​ ​ (22) ​ (3) % ​ C2 Ethane (MBbl) ​ ​ 24,657 ​ ​ 30,391 ​ ​ 5,734 ​ 23 % ​ C3+ NGLs (MBbl) ​ ​ 41,927 ​ ​ 42,434 ​ ​ 507 ​ 1 % ​ Oil (MBbl) ​ ​ 3,874 ​ ​ 3,693 ​ ​ (181) ​ (5) % ​ Combined (Bcfe) ​ ​ 1,238 ​ ​ 1,252 ​ ​ 14 ​ 1 % ​ Daily combined production (MMcfe/d) ​ ​ 3,392 ​ ​ 3,421 ​ ​ 29 ​ 1 % ​ Average prices before effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 2.69 ​ ​ 2.29 ​ ​ (0.40) ​ (15) % ​ C2 Ethane (per Bbl) (4) ​ $ 10.14 ​ ​ 9.05 ​ ​ (1.09) ​ (11) % ​ C3+ NGLs (per Bbl) ​ $ 37.85 ​ ​ 42.23 ​ ​ 4.38 ​ 12 % ​ Oil (per Bbl) ​ $ 63.80 ​ ​ 62.29 ​ ​ (1.51) ​ (2) % ​ Weighted Average Combined (per Mcfe) ​ $ 3.45 ​ ​ 3.29 ​ ​ (0.16) ​ (5) % ​ Average realized prices after effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 2.66 ​ ​ 2.30 ​ ​ (0.36) ​ (14) % ​ C2 Ethane (per Bbl) (4) ​ $ 10.14 ​ ​ 9.05 ​ ​ (1.09) ​ (11) % ​ C3+ NGLs (per Bbl) ​ $ 37.80 ​ ​ 42.36 ​ ​ 4.56 ​ 12 % ​ Oil (per Bbl) ​ $ 63.50 ​ ​ 62.15 ​ ​ (1.35) ​ (2) % ​ Weighted Average Combined (per Mcfe) ​ $ 3.43 ​ ​ 3.30 ​ ​ (0.13) ​ (4) % ​ Average costs (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 0.10 ​ ​ 0.09 ​ ​ (0.01) ​ (10) % ​ Gathering and compression ​ $ 0.69 ​ ​ 0.72 ​ ​ 0.03 ​ 4 % ​ Processing ​ $ 0.82 ​ ​ 0.85 ​ ​ 0.03 ​ 4 % ​ Transportation ​ $ 0.62 ​ ​ 0.59 ​ ​ (0.03) ​ (5) % ​ Production and ad valorem taxes ​ $ 0.13 ​ ​ 0.17 ​ ​ 0.04 ​ 31 % ​ Marketing expense, net ​ $ 0.06 ​ ​ 0.05 ​ ​ (0.01) ​ (17) % ​ General and administrative (excluding equity-based compensation) ​ $ 0.13 ​ ​ 0.13 ​ ​ — ​ * ​ ​ Depletion, depreciation, amortization and accretion ​ $ 0.61 ​ ​ 0.61 ​ ​ — ​ * ​ ​ * Not meaningful (1) Production data excludes volumes related to the VPP.
We are subject to state and U.S. federal income taxes, but we are currently not in a cash tax paying position with respect to U.S. federal income taxes.
We are subject to U.S. federal and state income taxes, but we are currently not in a cash tax paying position with respect to U.S. federal income taxes.
For the year ended December 31, 2023, commodity derivative fair value gains included $25 million of net cash payments for settled commodity derivative losses, as well as $202 million for payments on derivatives that were settled prior to their contractual settlement dates.
For the year ended December 31, 2023, commodity derivative fair value gains included $25 million of net cash payments for settled derivative losses, as well as $202 million for payments on derivatives that were settled prior to their contractual settlement dates.
Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment; therefore, all mark to market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations and comprehensive income (loss).
Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment; therefore, all mark to market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations and comprehensive income.
Based on strip prices as of December 31, 2023, we believe that net cash provided from operating activities and available borrowings under the Credit Facility will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures and commitments and contingencies for at least the next 12 months.
Based on strip prices as of December 31, 2024, we believe that net cash provided from operating activities and available borrowings under the Credit Facility will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures and commitments and contingencies for at least the next 12 months.
Our ability to make significant acquisitions for cash would require us to utilize borrowings on the Credit Facility or obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us, or at all. The Credit Facility is funded by a syndicate of 16 banks.
Our ability to make significant acquisitions for cash would require us to utilize borrowings on the Credit Facility or obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us, or at all. The Credit Facility is funded by a syndicate of 13 banks.
If future prices decline from December 31, 2023, the fair value of our properties may be below their carrying amounts and an impairment charge may be necessary. However, we are unable to predict commodity prices with any greater precision than the futures market.
If future prices decline from December 31, 2024, the fair value of our properties may be below their carrying amounts and an impairment charge may be necessary. However, we are unable to predict commodity prices with any greater precision than the futures market.
The estimated fair value of our commodity derivative assets has been risk adjusted using a discount rate based upon the counterparties’ respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) as of December 31, 2023.
The estimated fair value of our commodity derivative assets has been risk-adjusted using a discount rate based upon the counterparties’ respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) as of December 31, 2024.
ITEM 6. RESERVED ​ ​ ​ 50 Table of Contents ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K.
ITEM 6. RESERVED ​ ​ ​ 48 Table of Contents ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K.
As of December 31, 2023, we did not have any past-due receivables from, or payables to, any of the counterparties to our derivative contracts. Interest Rate Risks Our primary exposure to interest rate risk results from outstanding borrowings under the Credit Facility, which has a floating interest rate.
As of December 31, 2024, we did not have any past-due receivables from, or payables to, any of the counterparties to our derivative contracts. Interest Rate Risks Our primary exposure to interest rate risk results from outstanding borrowings under the Credit Facility, which has a floating interest rate.
All of our production is derived from natural gas wells, some of which also produce NGLs which are extracted through processing, and oil. ● Commodity derivatives. We utilize derivative instruments to hedge future sales prices for a portion of our production when circumstances warrant.
All of our production is derived from natural gas wells, some of which also produce NGLs which are extracted through processing, and oil. ● Commodity derivatives. We utilize derivative instruments to hedge future sales prices for our production when circumstances warrant.
We did not record any impairments for proved properties during the years ended December 31, 2021, 2022 and 2023. Based on current future commodity prices, we currently do not anticipate having to record any impairment charge for our proved properties in the near future.
We did not record any impairments for proved properties during the years ended December 31, 2022, 2023 and 2024. Based on current future commodity prices, we currently do not anticipate having to record any impairment charge for our proved properties in the near future.
Additionally, substantially all of our production is currently unhedged for 2024 and beyond, which limits our exposure to volatility in the fair value of our derivative instruments related to commodity price changes in the future. Amortization of deferred revenue, VPP.
Additionally, substantially all of our production is currently unhedged for 2025 and beyond, which limits our exposure to volatility in the fair value of our derivative instruments related to commodity price changes in the future. Amortization of deferred revenue, VPP.
Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity” in our Annual Report on Form 10-K for the year ended December 31, 2022 for a discussion of the cash flows for the year ended December 31, 2021 compared to the year ended December 31, 2022.
Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity” in our Annual Report on Form 10-K for the year ended December 31, 2023 for a discussion of the cash flows for the year ended December 31, 2022 compared to the year ended December 31, 2023.
These costs include impairment and costs associated with leases expirations, impairment of design and initial costs related to pads that are no longer planned to be placed into service and impairment of proved properties due to lower future commodity prices.
These costs include impairment and costs associated with lease expirations, impairment of design and initial costs related to pads that are no longer planned to be placed into service and impairment of proved properties due to lower future commodity prices.
We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the reported amounts in our consolidated financial statements that are not readily apparent from other sources.
We base our estimates on historical experience and various other assumptions that are believed to be reasonable under 61 Table of Contents the circumstances, the results of which form the basis for making judgments about the reported amounts in our consolidated financial statements that are not readily apparent from other sources.
Estimated undiscounted future net cash flows are sensitive to commodity price swings and a decline in prices could result in the carrying amount exceeding the estimated undiscounted future net cash flows at the end of a future reporting period, which would require us to further evaluate if an impairment charge would be necessary.
Estimated undiscounted future net cash flows are sensitive to commodity price swings and a decline in prices could result in the carrying amount exceeding the estimated undiscounted future net cash flows at the end of a future 62 Table of Contents reporting period, which would require us to further evaluate if an impairment charge would be necessary.
Based on our production and our derivative instruments that settled during the year ended December 31, 2023, our revenues would have decreased by $148 million for each $0.10 decrease per MMBtu in natural gas prices and $1.00 decrease per Bbl in oil and NGLs prices, excluding the effects of changes in the fair value of our derivative positions which remain open as of December 31, 2023.
Based on our production and our derivative instruments that settled during the year ended December 31, 2024, our revenues would have decreased by $151 million for each $0.10 decrease per MMBtu in natural gas prices and $1.00 decrease per Bbl in oil and NGLs prices, excluding the effects of changes in the fair value of our derivative positions which remain open as of December 31, 2024.
Based on this evaluation, management of Antero Resources Corporation concluded that our internal control over financial reporting was effective as of December 31, 2023.
Based on this evaluation, management of Antero Resources Corporation concluded that our internal control over financial reporting was effective as of December 31, 2024.
We also classify firm 54 Table of Contents transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize this excess capacity as marketing expenses, because we market this excess capacity to third parties.
We also classify firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize this excess capacity as marketing expenses, because we market this excess capacity to third parties.
These are primarily costs related to unsuccessful leasing efforts, as well as geological and geophysical costs, including seismic costs, costs of unsuccessful exploratory dry holes and costs of other exploratory activities, including costs associated with our sand mine. ● Impairment of property and equipment.
These are primarily costs related to unsuccessful leasing efforts, as well as geological and geophysical costs, including seismic costs, costs of unsuccessful exploratory dry holes and costs of other exploratory activities, including costs associated with our sand mine. 52 Table of Contents ● Impairment of property and equipment.
Under the terms of the arrangement, QL funded development capital of 20%, 15% and 15% for wells spud in 2021, 2022 and 2023, respectively, and will fund 20% of development capital for wells spud in 2024, which funding amounts represent QL’s proportionate working interest in such wells.
Under the terms of the arrangement, QL funded development capital of 20% for wells spud in 2021 and 2024 and 15% for wells spud in 2022 and 2023, which funding amounts represent QL’s proportionate working interest in such wells.
Contract termination, loss contingency and other operating expenses attributable to our marketing segment for the year ended December 31, 2023 relate to a $24 million payment for the early termination of our firm transportation commitment of 200,000 MMBtu/d on the Equitrans pipeline. Antero Midstream Segment Antero Midstream revenue.
Contract termination, loss contingency, settlements and other operating expenses attributable to our marketing segment for the year ended December 31, 2023 relate to a $24 million payment for the early termination of our firm transportation commitment of 200,000 MMBtu/d on the Equitrans pipeline.
For our Utica and Marcellus properties, strip pricing would have to decline by more than 20% and 25%, respectively, from year end 2023 levels before further evaluation of those properties would be required in order to determine if an impairment charge is necessary.
For our Utica and Marcellus properties, strip pricing would have to decline by more than 7% and 25%, respectively, from year end 2024 levels before further evaluation of those properties would be required in order to determine if an impairment charge is necessary.
These economic variables are beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows. Sources of Our Revenues ● Natural gas, NGLs and oil sale revenues.
These economic variables are beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows. ​ 51 Table of Contents Sources of Our Revenues ● Natural gas, NGLs and oil sale revenues.
Our calculation of such after effects includes gains (losses) on settlements of commodity derivatives (but does not include proceeds from the derivative monetizations in 2023), which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes.
Our calculation of such after effects includes gains (losses) on settlements of commodity derivatives (but do not include payments for the derivative monetizations in 2023), which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes.
We recognize in our financial statements those tax positions which we believe are more-likely-than-not to be sustained upon examination by the Internal Revenue Service or state revenue authorities.
We recognize in our financial statements those tax positions which we believe are more-likely-than-not to be sustained upon examination by the IRS or state revenue authorities.
Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity. See Note 17—Reportable Segments to the consolidated financial statements for more information.
Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity. See Note 17—Reportable Segments to our consolidated financial statements for additional information.
See Note 13—Income Taxes to the consolidated financial statements for more information. ​ 55 Table of Contents Results of Operations We have three operating segments: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing and utilization of excess firm transportation capacity; and (iii) midstream services through our equity method investment in Antero Midstream.
See Note 13—Income Taxes to our consolidated financial statements for additional information. 53 Table of Contents Results of Operations We have three reportable segments: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing and utilization of excess firm transportation capacity; and (iii) midstream services through our equity method investment in Antero Midstream.
We have assembled a portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and repeatability. Our drilling opportunities are focused in the Appalachian Basin. As of December 31, 2023, we held approximately 515,000 net acres in the Appalachian Basin.
We have assembled a portfolio of long-lived properties that are characterized by what we believe to be high repeatability and low geologic risk. Our drilling opportunities are focused in the Appalachian Basin. As of December 31, 2024, we held approximately 521,000 net acres in the Appalachian Basin.
Impairment of oil and gas properties related to unproved properties for leases that have expired, or are expected to expire, was $91 million, $98 million and $51 million for the years ended December 31, 2021, 2022 and 2023, respectively.
Impairment of oil and gas properties related to unproved properties for leases that have expired, or are expected to expire, was $98 million, $51 million and $47 million for the years ended December 31, 2022, 2023 and 2024, respectively.
The average annualized interest rate incurred on the Credit Facility for borrowings during the year ended December 31, 2023 was 7.6%. We estimate that a 1.0% increase in the applicable average interest rates for the year ended December 31, 2023 would have resulted in an estimated $3 million increase in interest expense. ITEM 8.
The average annualized interest rate incurred on the Credit Facility for borrowings during the year ended December 31, 2024 was 7.4%. We estimate that a 1.0% increase in the applicable average interest rates for the year ended December 31, 2024 would have resulted in an estimated $4 million increase in interest expense. ITEM 8.
See Note 11—Derivative Instruments to the consolidated financial statements for more information. Economic Indicators The economy experienced elevated inflation levels as a result of global supply and demand imbalances, where global demand outpaced supplies beginning in 2021 and continuing through 2023.
See Note 11—Derivative Instruments to our consolidated financial statements for additional information. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Economic Indicators The economy experienced elevated inflation levels as a result of global supply and demand imbalances, where global demand outpaced supplies beginning in 2021 and continuing through 2024.
The difference between our financial statement income tax expense and our current U.S. federal income tax liability is primarily due to the differences in the tax and financial statement treatment of oil and gas properties, the effects of noncontrolling interests and the deferral of unsettled commodity derivative gains and losses for tax purposes until they are settled.
The difference between our financial statement income tax (expense) benefit and our current U.S. federal income tax liability is primarily due to the differences in the tax and financial statement treatment of oil and gas properties, the effects of noncontrolling interests, the deferral of unsettled commodity derivative gains and losses for tax purposes until they are settled and research and development (“R&D”) tax credits.
Our effective tax rate was different than the statutory rate of 21% primarily due to the effects of state income taxes, the dividends received deduction, equity-based compensation expenses, noncontrolling interests, the effects of a West Virginia apportionment tax law change enacted in 2021 and changes in Pennsylvania’s corporate income tax rate.
Our effective tax rate for the year ended December 31, 2023 was different than the statutory rate of 21% primarily due to the effects of state income taxes, the dividends received deduction, equity-based compensation expenses, noncontrolling interests, the effects of a West Virginia apportionment tax law change enacted in 2021 and changes in Pennsylvania’s corporate income tax rate.
In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased.
In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased. For 2023 and 2024, substantially all of our production was unhedged.
As of December 31, 2023, we had an outstanding balance on the Credit Facility of $417 million with a weighted average interest rate of 7.71%. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions.
As of December 31, 2023 and 2024, we had an outstanding balance on the Credit Facility of $417 million and $393 million, respectively, with a weighted average interest rate of 7.7% and 5.9%, respectively. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions.
(4) The average realized price for the years ended December 31, 2022 and 2023 includes $10 million and $15 million, respectively, of proceeds related to a take-or-pay contract.
(4) The average realized price for the years ended December 31, 2023 and 2024 includes $15 million and $2 million, respectively, of proceeds related to a take-or-pay contract.
During both periods, we recognized impairments primarily related to expiring leases as well as design and initial costs related to pads we no longer plan to place into service . Contract termination, loss contingency and other operating expenses .
During both periods, we recognized impairments primarily related to expiring leases as well as design and initial costs related to pads we no longer plan to utilize . Contract termination, loss contingency, settlements and other operating expenses .
As of December 31, 2022 and 2023, the estimated fair value of our commodity derivative instruments was a net liability of $431 million, and $37 million, respectively, comprised of current and noncurrent assets and liabilities. 67 Table of Contents Counterparty and Customer Credit Risk Our principal exposures to credit risk are through receivables resulting from the following: the sale of our natural gas, NGLs and oil production ($384 million as of December 31, 2023), which we market to energy companies, end users and refineries, and commodity derivative contracts ($17 million as of December 31, 2023).
As of December 31, 2023 and 2024, the estimated fair value of our commodity derivative instruments was a net liability $37 million and $47 million, respectively, comprised of current and noncurrent assets and liabilities. 64 Table of Contents Counterparty and Customer Credit Risk Our principal exposures to credit risk are through receivables resulting from the following: the sale of our natural gas, NGLs and oil production ($453 million as of December 31, 2024), which we market to energy companies, end users and refineries, and commodity derivative contracts ($2 million as of December 31, 2024).
Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives for the years ended December 31, 2022 and 2023 would have been $19.88 per Bbl and $9.55 per Bbl, respectively. ​ Natural gas sales .
Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives for the years ended December 31, 2023 and 2024 would have been $9.55 per Bbl and $8.99 per Bbl, respectively. ​ Natural gas sales .
Higher NGLs production volumes during the year ended December 31, 2023 accounted for an approximate $226 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price). 58 Table of Contents Oil sales .
Higher NGLs production volumes during the year ended December 31, 2024 accounted for an approximate $77 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price). 56 Table of Contents Oil sales .
See Note 11—Derivative Instruments to the consolidated financial statements for more information. Martica Our consolidated VIE, Martica, also maintains a portfolio of fixed swap natural gas, NGLs and oil derivatives for the benefit of the noncontrolling interests in Martica. As such, all gains and losses attributable to Martica’s derivative portfolio are fully attributable to the noncontrolling interests in Martica.
See Note 11—Derivative Instruments to our consolidated financial statements for additional information. Martica Our consolidated VIE, Martica, also maintains a portfolio of fixed price swap derivatives for the benefit of the noncontrolling interests in Martica. As such, all gains and losses attributable to Martica’s derivative portfolio are fully attributable to the noncontrolling interests in Martica.
We cannot predict the amounts or timing of future reserve revisions. 65 Table of Contents We believe that the estimates and assumptions related to reserve quantities is critical because any significant revisions or changes to these estimates and assumptions could affect the future amortization rates of capitalized proved property costs and result in a material asset impairment.
We believe that the estimates and assumptions related to reserve quantities is critical because any significant revisions or changes to these estimates and assumptions could affect the future amortization rates of capitalized proved property costs and result in a material asset impairment.
During 2022 and 2023, our production revenues were comprised of 67% and 51%, respectively, from the sale of natural gas and 33% and 49%, respectively, from the sale of NGLs and oil. Natural gas, NGLs and oil prices are inherently volatile and are influenced by many factors outside of our control.
During 2023 and 2024, our production revenues were comprised of 51% and 44%, respectively, from the sale of natural gas and 49% and 56%, respectively, from the sale of NGLs and oil. Natural gas, NGLs and oil prices are inherently volatile and are influenced by many factors outside of our control.
We record a valuation allowance when we believe all or a portion of our deferred income tax assets will not be realized. In assessing the realizability of our deferred income tax assets, management considers whether some portion or all of the deferred income tax assets will be realized based on a more-likely-than-not standard of judgment.
In assessing the realizability of our deferred income tax assets, management considers whether some portion or all of the deferred income tax assets will be realized based on a more-likely-than-not standard of judgment.
We have recorded deferred income tax expense to the extent our deferred income tax liabilities exceed our deferred income tax assets.
We have recorded deferred income tax expense to the extent our deferred income tax liabilities exceed our deferred income tax assets. We record a deferred income tax benefit to the extent our deferred income tax assets exceed our deferred income tax liabilities.
The ultimate realization of deferred income tax assets is dependent upon our ability to generate future taxable income during the periods in which our deferred income tax assets are deductible.
The ultimate realization of deferred income tax assets is dependent upon our ability to generate future taxable income during the periods in which our deferred income tax assets are deductible or our tax credits can be utilized.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Reports of Independent Registered Public Accounting Firm, Consolidated Financial Statements, and supplementary financial data required for this Item are set forth beginning on page F-2 of this Annual Report on Form 10-K and are incorporated herein by reference. ITEM 9.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Reports of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth beginning on page F-2 of this Annual Report on Form 10-K and are incorporated herein by reference. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable.
The effectiveness of our internal control over financial reporting as of December 31, 2023 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears beginning on page F-2 in this Annual Report on Form 10-K.
The effectiveness of our internal control over financial reporting as of December 31, 2024 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears beginning on page F-2 in this Annual Report on Form 10-K. ITEM 9B. OTHER INFORMATION N o n e .
We believe that all of the counterparties to our derivative instruments are acceptable credit risks as of December 31, 2023. Other than as provided by the Credit Facility, we are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us.
We believe that all of the counterparties to our derivative instruments are acceptable credit risks as of December 31, 2024. We are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us.
Higher natural gas production volumes accounted for an approximate $121 million increase in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price). NGLs sales .
Lower natural gas production volumes accounted for an approximate $61 million decrease in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price). NGLs sales .
Lower oil prices for the year ended December 31, 2023 excluding the effects of derivative settlements) accounted for an approximate $84 million decrease in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes).
Lower oil prices for the year ended December 31, 2024 (excluding the effects of derivative settlements) accounted for an approximate $6 million decrease in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes). Commodity derivative fair value gains.
Lower commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2023 accounted for an approximate $888 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).
Higher commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2024 accounted for an approximate $153 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).
As of December 31, 2023, we had fixed interest rates ranging from 5.375% to 8.375% on our Senior Notes with an aggregate principal balance of $1.1 billion and 4.25% on our 2026 Convertible Notes with an aggregate principal balance of $26 million. See Note 7—Long-Term Debt to the consolidated financial statements for more information. ● Income tax expense.
As of December 31, 2023 and 2024, we had fixed interest rates ranging from 5.375% to 8.375% on our Senior Notes with an aggregate principal balance of $1.1 billion. See Note 7—Long-Term Debt to our consolidated financial statements for additional information. ● Income tax (expense) benefit.
However, our supply chain has not experienced any significant interruptions as a result of such events . Inflationary pressures, particularly as they relate to certain of our long-term contracts with CPI-based adjustments, and supply chain disruptions have and could continue to result in increases to our operating and capital costs that are not fixed.
Inflationary pressures, particularly as they relate to certain of our long-term contracts with CPI-based adjustments, and supply chain disruptions have and could continue to result in increases to our operating and capital costs that are not fixed.
Amortization of deferred revenues associated with the VPP decreased from $38 million for the year ended December 31, 2022 to $31 million for the year ended December 31, 2023, a decrease of $7 million or 19%, primarily due to lower production volumes attributable to the VPP properties between periods.
Amortization of deferred revenues associated with the VPP decreased from $31 million for the year ended December 31, 2023 to $27 million for the year ended December 31, 2024, a decrease of $4 million or 11%, primarily due to lower production volumes attributable to the VPP properties between periods.
See Note 9—Equity-Based Compensation to the consolidated financial statements for more information. ● Interest expense.
See Note 9—Equity-Based Compensation to our consolidated financial statements for additional information. ● Interest expense.
Our marketing segment did not incur any contract termination, loss contingency and other operating expenses for the year ended December 31, 2022.
Our marketing segment did not incur any contract termination, loss contingency, settlements and other operating expenses for the year ended December 31, 2024. Antero Midstream Segment Antero Midstream revenue.
(2) Energy Information Administration calendar month average settled futures price. Hedge Position Antero Resources (Excluding Martica) We are exposed to certain commodity price risks relating to our ongoing business operations, and we use derivative instruments when circumstances warrant to manage such risks.
(4) NYMEX calendar month average settled futures price. 50 Table of Contents Hedge Position Antero Resources (Excluding Martica) We are exposed to certain commodity price risks relating to our ongoing business operations, and we use derivative instruments when circumstances warrant to manage such risks.
Marketing revenue decreased from $417 million for the year ended December 31, 2022 to $206 million for the year ended December 31, 2023, a decrease of $211 million, or 51%. This fluctuation primarily resulted from the following: ● Natural gas marketing revenue decreased by $187 million between periods primarily due to lower natural gas prices and marketing volumes.
Marketing revenue decreased from $206 million for the year ended December 31, 2023 to $179 million for the year ended December 31, 2024, a decrease of $27 million, or 13%. This fluctuation primarily resulted from the following: ● Natural gas marketing revenue decreased by $77 million between periods primarily due to lower natural gas marketing volumes and prices.
Lower commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2023 accounted for an approximate $3.4 billion decrease in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price excluding the net proceeds from the litigation times current year production volumes).
Lower commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2024 accounted for an approximate $313 million decrease in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes).
In addition, we estimate that approximately 172,000 net acres of our leasehold may be prospective for the slightly shallower Upper Devonian Shale. As of December 31, 2023, our estimated proved reserves were 18.1 Tcfe, consisting of 10.6 Tcf of natural gas, 690 MMBbl of assumed recovered ethane, 532 MMBbl of C3+ NGLs and 29 MMBbl of oil.
In addition, we estimate that approximately 170,000 net acres of our leasehold may be prospective for the slightly shallower Upper Devonian Shale. As of December 31, 2024, our estimated proved reserves were 17.9 Tcfe, consisting of 10.6 Tcf of natural gas, 674 MMBbl of assumed recovered ethane, 519 MMBbl of C3+ NGLs and 23 MMBbl of oil.
We believe that the estimates and assumptions related to income taxes are critical because the assumptions and estimates required to assess the likelihood that our deferred income tax assets will be recovered from future taxable income, as well as the amount and timing of a valuation allowance on our deferred income tax assets is an exercise in judgement and susceptible to change as circumstances warrant.
We believe that the estimates and assumptions related to income taxes are critical because of the assumptions and estimates required to assess the likelihood that our deferred income tax assets will be recovered from future taxable income, as well as the judgement required to determine the amount and timing of a valuation allowance on our deferred income tax assets and reserve for uncertain tax positions.
Gathering, compression, processing and transportation expense remained consistent at $2.6 billion for each of the years ended December 31, 2022 and 2023.
Gathering, compression, processing and transportation expense remained relatively consistent at $2.6 billion and $2.7 billion for the years ended December 31, 2023 and 2024, respectively.
We have commodity hedges in place with three different counterparties, two of which are lenders under the Credit Facility. As of December 31, 2023, we did not have any derivative assets with bank counterparties under our Credit Facility.
The creditworthiness of our counterparties is subject to periodic review. As of December 31, 2024, we have commodity hedges in place with four different counterparties, three of which are lenders under the Unsecured Credit Facility. As of December 31, 2024, we did not have any commodity derivative assets with bank counterparties under our Unsecured Credit Facility.
Revenues from sale of oil decreased from $276 million for the year ended December 31, 2022 to $247 million for the year ended December 31, 2023, a decrease of $29 million, or 10%.
Revenues from sale of oil decreased from $247 million for the year ended December 31, 2023 to $230 million for the year ended December 31, 2024, a decrease of $17 million, or 7%.
Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled or monetized or terminated prior to settlement.
For the year ended December 31, 2024, commodity derivative fair value gains included $10 million of net cash proceeds for settled derivative gains. Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled, monetized or terminated prior to settlement.
Accordingly, reserve estimates are generally different from the quantities of natural gas, NGLs and oil that are ultimately recovered.
Accordingly, reserve estimates are generally different from the quantities of natural gas, NGLs and oil that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions.
We expect continued volatility in the fair value of our derivative instruments. Our cash flows are impacted when the associated derivative contracts are settled or monetized by making or receiving payments to or from the counterparty.
Our cash flows are impacted when the associated derivative contracts are settled or monetized by making or receiving payments to or from the counterparty.
This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. Commodity Hedging Activities Our primary market risk exposure is in the price we receive for our natural gas, NGLs and oil production.
These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. Commodity Hedging Activities Our primary market risk exposure is in the price we receive for our natural gas, NGLs and oil production.
Firm transportation costs were $149 million for the year ended December 31, 2022 and $105 million for the year ended December 31, 2023, a decrease of $44 million primarily due to the reduction in firm transportation commitments between periods. Contract termination, loss contingency and other operating expenses.
Firm transportation costs decreased $19 million from $105 million for the year ended December 31, 2023 to $86 million for the year ended December 31, 2024, primarily due to the reduction in firm transportation commitments between periods. Contract termination, loss contingency, settlements and other operating expenses.
We finance a portion of our capital expenditures, working capital requirements and acquisitions with borrowings under our Credit Facility, which has a variable rate of interest based on SOFR (defined below in “—Capital Resources and Liquidity—Debt Agreements—Credit Facility”) or the Alternate Base Rate (each term as defined in the Credit Facility).
We finance a portion of our capital expenditures, working capital requirements and acquisitions with borrowings under our Credit Facility, which has a variable rate of interest based on the Adjusted Term SOFR Rate, the Adjusted Daily Simple SOFR (collectively, “SOFR”) or the Alternate Base Rate, in each case, plus an Applicable Rate (each term as defined in the Credit Facility).
We operate in the following reportable segments: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing of excess firm transportation capacity; and (iii) midstream services through our equity method investment in Antero Midstream Corporation (“Antero Midstream”). All of our operations are conducted in the United States.
We have three reportable segments: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing of excess firm transportation capacity; and (iii) midstream services through our equity method investment in Antero Midstream. All of our operations are conducted in the United States. See Note 17—Reportable Segments to our consolidated financial statements for additional information.
Revenues from sales of natural gas decreased from $5.5 billion, for the year ended December 31, 2022 to $2.2 billion for the year ended December 31, 2023, a decrease of $3.3 billion, or 60%.
Revenues from sales of natural gas decreased from $2.2 billion for the year ended December 31, 2023 to $1.8 billion for the year ended December 31, 2024, a decrease of $0.4 billion, or 17%.
Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased.
Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased. For the years ended December 31, 2023 and 2024, substantially all of our production was unhedged.
As of December 31, 2023, we have recognized a valuation allowance of $55 million related to Colorado, Oklahoma and West Virginia state NOL carryforwards that we do not expect to realize due to expected future reduced income tax apportionment in those states. 66 Table of Contents The calculation of deferred income tax assets and liabilities involves uncertainties in the application of complex tax laws and regulations.
As of December 31, 2024, we have recognized a valuation allowance of $43 million related to Colorado, Oklahoma and West Virginia state NOL carryforwards that we do not expect to realize due to expected future reduced income tax apportionment in those states.
To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions that management deems to be competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review.
When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions that management deems to be competent and competitive market makers.
We completed 70 net horizontal wells during the year ended December 31, 2023. Our net capital budget for 2024 is $725 million to $800 million. Our budget includes: a range of $650 million to $700 million for drilling and completion and $75 million to $100 million for leasehold expenditures. We do not budget for acquisitions.
Our net capital budget for 2025 is $725 million to $800 million. Our budget includes: a range of $650 million to $700 million for drilling and completion and $75 million to $100 million for leasehold expenditures. We do not budget for acquisitions. During 2025, we plan to complete 60 to 65 net horizontal wells in the Appalachian Basin.
Net marketing expense decreased from $115 million, or $0.10 per Mcfe, for the year ended December 31, 2022 to $79 million, or $0.06 per Mcfe, for the year ended December 31, 2023, primarily due to lower firm transportation commitments, partially offset by lower marketing margin on third-party product purchases between periods. Marketing revenue.
Net marketing expense decreased from $79 million, or $0.06 per Mcfe, for the year ended December 31, 2023 to $66 million, or $0.05 per Mcfe, for the year ended December 31, 2024, primarily due to lower firm transportation commitments between periods. Marketing revenue.

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