ANTERO RESOURCES Corp

Previous wording

We are an independent oil and natural gas company engaged in the development, production, exploration and acquisition of natural gas, NGLs and oil properties located in the Appalachian Basin. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to develop our reserves and production, primarily on our existing multi-year inventory of drilling locations.

Current wording

We have assembled a portfolio of long-lived properties that are characterized by what we believe to be high repeatability and low geologic risk. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to develop our reserves and production, primarily on our existing multi-year inventory of drilling locations in the Appalachian Basin. As of December 31, 2025, we held approximately 537,000 net acres in the Appalachian Basin. In addition, we estimate that approximately 168,000 net acres of our leasehold may be prospective for the slightly shallower Upper Devonian Shale.

Previous wording

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. These reserve estimates have been prepared by our internal reserve engineers and management and audited by our independent reserve engineers. As of December 31, 2024, we had 1,137 potential horizontal well locations on our existing leasehold acreage that were classified as proved, probable and possible and excludes 339 locations based on such locations being uneconomic at the SEC reserves prices for the year ended December 31, 2024.

Current wording

As of December 31, 2025, our estimated proved reserves were 19.1 Tcfe, consisting of 11.8 Tcf of natural gas, 679 MMBbl of assumed recovered ethane, 529 MMBbl of C3+ NGLs and 23 MMBbl of oil. These reserve estimates have been prepared by our internal reserve engineers and management and audited by our independent reserve engineers. As of December 31, 2025, we had 1,279 potential horizontal well locations on our existing leasehold acreage that were classified as proved, probable and possible.

Previous wording

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.

Current wording

We have three reportable segments: exploration and production, our equity method investment in Antero Midstream and marketing. All of our operations are conducted in the United States. See Note 17—Reportable Segments to our consolidated financial statements for additional information.

Previous wording

Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Benchmark prices for natural gas and ethane decreased significantly, while benchmark prices for oil remained consistent and benchmark prices for C3+ NGLs increased during the year ended December 31, 2024 as compared to the year ended December 31, 2023. As a result of the lower benchmark natural gas and ethane prices and higher benchmark C3+ NGLs prices during the year ended December 31, 2024, we experienced a decrease in price realizations for natural gas and ethane products and an increase in price realization for C3+ NGLs products during the same period. We monitor the economic factors that impact natural gas, NGLs and oil prices, including domestic and foreign supply and demand indicators, domestic and foreign commodity inventories, the actions of Organization of Petroleum Exporting Countries and other large producing nations and the current conflicts in Ukraine and in the Middle East, among others. In the current economic environment, we expect that commodity prices for some or all of the commodities we produce could remain volatile. This volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.

Current wording

Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Benchmark prices for natural gas and ethane increased significantly, while benchmark prices for C3+ NGLs and oil decreased, during the year ended December 31, 2025 as compared to the year ended December 31, 2024. As a result of the higher benchmark natural gas and ethane prices during the year ended December 31, 2025, we experienced an increase in price realization for natural gas and ethane products, partially offset by the effects of decreased benchmark NGLs and oil prices as compared to the year ended December 31, 2024. We monitor the economic factors that impact natural gas, NGLs and oil prices, including domestic and foreign supply and demand indicators, domestic and foreign commodity inventories, the actions of Organization of Petroleum Exporting Countries and other large producing nations and the current conflicts in Ukraine, Venezuela and in the Middle East, among others. In the current economic environment, we expect that commodity prices for some or all of the commodities we produce could remain volatile. This volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows. However, we use derivative instruments when circumstances warrant to manage our exposure to commodity price risk. See “—Hedge Position” and Note 11—Derivative Instruments to our consolidated financial statements for additional information on our derivative instruments.

Previous wording

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. 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. Assuming our 2025 production is the same as our production in 2024, approximately 3% of our total production for 2025 is hedged through fixed price commodity swaps. As of December 31, 2024, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of $45 million. See Note 11—Derivative Instruments to our consolidated financial statements for additional information.

Current wording

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. In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. For the years ended December 31, 2024 and 2025, 4% and 8%, respectively, of our production was hedged through commodity derivatives. Assuming our 2026 production is the same as our production in 2025, approximately 42% of our total production is hedged through commodity derivatives. In addition, we also have derivative contracts in place for a portion of our 2027 production. As of December 31, 2025, the estimated fair value of our commodity derivative contracts was a net asset of $81 million. See Note 11—Derivative Instruments to our consolidated financial statements for additional information.

Previous wording

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. As of December 31, 2024, the estimated fair value of Martica’s commodity derivative contracts was a net liability of $2 million. See Note 11—Derivative Instruments to our consolidated financial statements for additional information.

Current wording

Our consolidated VIE, Martica, previously maintained 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 were fully attributable to the noncontrolling interests in Martica. During the three months ended March 31, 2025, all of Martica’s derivative contracts expired. As of December 31, 2025, Martica had no derivative instruments. See Note 11—Derivative Instruments to our consolidated financial statements for additional information.

Previous wording

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. For example, CPI for all urban consumers increased 4.1% from December 2022 to December 2023 and an additional 2.9% from December 2023 to December 2024. In order to manage the inflation risk present in the United States’ economy, the Federal Reserve utilized monetary policy in the form of interest rate increases beginning in March 2022 in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis. Between March 2022 and July 2023, the Federal Reserve increased the federal funds interest rate by 5.25%. During the second half of 2024, inflation rates began to approach the Federal Reserve’s stated goal of 2%, and the Federal Reserve decreased the federal funds rate by 1.0% between September and December 2024. While inflationary pressures in the United States’ economy have begun to subside, we continue to be impacted by the increased federal funds interest rate. See “—Results of Operations” for additional information.

Current wording

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. In order to manage the inflation risk present in the United States’ economy, the Federal Reserve utilized monetary policy in the form of interest rate increases beginning in 2022 in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis. Between 2022 and 2023, the Federal Reserve increased the federal funds interest rate by 5.25%. During the second half of 2024, inflation rates began to approach the Federal Reserve’s stated goal of 2%, and the Federal Reserve decreased the federal funds rate by 1.75% in 2024 and 2025. While inflationary pressures in the United States’ economy have begun to subside, it is uncertain what impact recent tariff activity by the United States and foreign governments will have on inflation. See “—Results of Operations” for additional information.

Previous wording

The economy also continues to be impacted by the effects of global events. These events have often caused global supply chain disruptions with additional pressure due to trade sanctions on Russia and other global trade restrictions, among others. However, our supply chain has not experienced any significant interruptions as a result of such events.

Current wording

The economy also continues to be impacted by the effects of global events. These events have often caused global supply chain disruptions with additional pressure due to trade sanctions, tariffs, other global trade restrictions and conflicts, including those in the Middle East, Iran and Venezuela, among others. While our supply chain has not experienced any significant interruptions as a result of such events, there can be no assurance that we will not experience interruptions in the future.

Previous wording

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. Revenues from Antero Midstream’s operations were primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream. All intersegment transactions were eliminated upon consolidation, including revenues from water handling services provided by Antero Midstream, which we capitalized as proved property development costs. 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.

Current wording

We have three reportable segments: exploration and production, our equity method investment in Antero Midstream and marketing. Revenues from Antero Midstream’s operations were primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream. All intersegment transactions were eliminated upon consolidation, including revenues from water handling services provided by Antero Midstream, which we capitalized as proved property development costs. 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.

Previous wording

Natural gas sales. 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%. 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). 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).

Current wording

Natural gas sales. Revenues from sales of natural gas increased from $1.8 billion for the year ended December 31, 2024 to $2.9 billion for the year ended December 31, 2025, an increase of $1.1 billion, or 58%. Higher commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2025 accounted for an approximate $1.0 billion increase in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes). Higher natural gas production volumes accounted for an approximate $34 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).

Previous wording

NGLs sales. Revenues from sales of NGLs increased from $1.8 billion for the year ended December 31, 2023 to $2.1 billion for the year ended December 31, 2024, an increase of $0.3 billion, or 13%. 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). 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).

Current wording

NGLs sales. Revenues from sales of NGLs decreased from $2.1 billion for the year ended December 31, 2024 to $2.0 billion for the year ended December 31, 2025, a decrease of $0.1 billion, or 4%. Lower C3+ NGLs commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2025 accounted for an approximate $143 million decrease in year-over-year NGLs revenues (calculated as the change in the year-to-year average price times current year production volumes), partially offset by higher ethane commodity prices during the year ended December 31, 2025 that accounted for an approximate $85 million increase in year-over-year NGLs revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower NGLs production volumes during the year ended December 31, 2025 accounted for an approximate $23 million decrease in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price).

Previous wording

Oil sales. 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%. Lower oil production volumes during the year ended December 31, 2024 accounted for an approximate $11 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price). 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).

Current wording

Oil sales. Revenues from sale of oil decreased from $230 million for the year ended December 31, 2024 to $150 million for the year ended December 31, 2025, a decrease of $80 million, or 35%. Lower oil production volumes during the year ended December 31, 2025 accounted for an approximate $50 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price). Lower oil prices for the year ended December 31, 2025 (excluding the effects of derivative settlements) accounted for an approximate $30 million decrease in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes).

Previous wording

Commodity derivative fair value gains. Our commodity derivatives included fixed price swap contracts, swaptions, basis swap contracts, call options and embedded put options. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, 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. For the years ended December 31, 2023 and 2024, our commodity hedges resulted in derivative fair value gains of $166 million and $1 million, respectively. 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. For the year ended December 31, 2024, commodity derivative fair value gains included $10 million of net cash proceeds for settled derivative gains.

Current wording

Commodity derivative fair value gains. Our commodity derivatives included fixed price swap contracts, swaptions, basis swap contracts, call options and embedded put options. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, 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. For the years ended December 31, 2024 and 2025, our commodity hedges resulted in derivative fair value gains of $1 million and $111 million, respectively. For the year ended December 31, 2024, commodity derivative fair value gains included $10 million of net cash proceeds for settled derivative gains. For the year ended December 31, 2025, commodity derivative fair value gains included $17 million of net cash payments for settled derivative losses.

Previous wording

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. Derivative asset or liability positions at the end of any accounting period may reverse to the extent future commodity prices increase or decrease from their levels at the end of the accounting period, or as gains or losses are realized through settlement. 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.

Current wording

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. Derivative asset or liability positions at the end of any accounting period may reverse to the extent future commodity prices increase or decrease from their levels at the end of the accounting period, or as gains or losses are realized through settlement.

Previous wording

Amortization of deferred revenue, VPP. 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. Amortization of the deferred revenues associated with the VPP are recognized as the production volumes are delivered at $1.61 per MMBtu over the contractual term.

Current wording

Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP decreased from $27 million for the year ended December 31, 2024 to $25 million for the year ended December 31, 2025, a decrease of $2 million or 7%, primarily due to lower production volumes attributable to the VPP properties between periods. Amortization of the deferred revenues associated with the VPP are recognized as the production volumes are delivered at $1.61 per MMBtu over the contractual term.

Previous wording

Gathering, compression, processing and transportation expense. 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. This was primarily a result of the following:

Current wording

Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense increased from $2.7 billion for the year ended December 31, 2024 to $2.9 billion for the year ended December 31, 2025, an increase of $0.2 billion, or 6%. This fluctuation was primarily a result of the following:

Previous wording

Production and ad valorem tax expense. Production and ad valorem taxes increased from $159 million for the year ended December 31, 2023 to $208 million for the year ended December 31, 2024, an increase of $49 million or 31%, primarily due to higher ad valorem taxes, partially offset by lower natural gas and oil prices during the year ended December 31, 2024. Production and ad valorem taxes as a percentage of natural gas revenues increased from 7% for the year ended December 31, 2023 to 11% for the year ended December 31, 2024, primarily as a result of higher ad valorem taxes, which 2024 West Virginia ad valorem taxes are based on commodity prices during 2022.

Current wording

Production and ad valorem tax expense. Production and ad valorem taxes decreased from $208 million for the year ended December 31, 2024 to $163 million for the year ended December 31, 2025, a decrease of $45 million or 21%, primarily due to lower ad valorem taxes of $115 million between periods, partially offset by higher severance taxes of $70 million as a result of increased natural gas prices during the year ended December 31, 2025. Production and ad valorem taxes as a percentage of natural gas revenues decreased from 11% for the year ended December 31, 2024 to 6% for the year ended December 31, 2025, primarily as a result of lower ad valorem taxes between periods. West Virginia ad valorem taxes in 2024 were based on commodity prices during 2022, and West Virginia ad valorem taxes in 2025 are based on commodity prices during 2023.

Previous wording

*General and administrative expense.*General and administrative expense (excluding equity-based compensation expense) remained relatively consistent at $165 million, or $0.13 per Mcfe and $163 million, or $0.13 per Mcfe, for the years ended December 31, 2023 and 2024, respectively.

Current wording

*General and administrative expense.*General and administrative expense (excluding equity-based compensation expense) increased from $163 million for the year ended December 31, 2024 to $172 million for the year ended December 31, 2025, an increase of $9 million, or 5%, primarily due to higher professional service fees and increased salary and wage expense as a result of increased employee headcount between periods. We had 616 and 632 employees as of December 31, 2024 and 2025, respectively. General and administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.13 per Mcfe for the year ended December 31, 2024 to $0.14 per Mcfe for the year ended December 31, 2025 primarily as a result of higher overall costs between periods.

Previous wording

Equity-based compensation expense. Non-cash equity-based compensation expense increased from $60 million for the year ended December 31, 2023 to $66 million for the year ended December 31, 2024, an increase of $6 million or 12%. This increase was primarily due to higher restricted stock unit (“RSU”) award expense of $9 million between periods, partially offset by lower performance share unit (“PSU”) award expense of $3 million between periods. See Note 9—Equity-Based Compensation to our consolidated financial statements for additional information.

Current wording

Equity-based compensation expense. Non-cash equity-based compensation expense decreased from $66 million for the year ended December 31, 2024 to $61 million for the year ended December 31, 2025, a decrease of $5 million or 9%. This decrease was primarily due to lower performance share unit (“PSU”) award grants between periods. See Note 9—Equity-Based Compensation to our consolidated financial statements for additional information.

Previous wording

Depletion, depreciation and amortization expense. DD&A expense increased from $747 million for the year ended December 31, 2023 to $762 million for the year ended December 31, 2024, an increase of $15 million or 2%, primarily due to higher production volumes between periods. On a per-unit basis, DD&A expense remained consistent at $0.61 per Mcfe for the years ended December 31, 2023 and 2024.

Current wording

Depletion, depreciation and amortization expense. DD&A expense decreased from $762 million for the year ended December 31, 2024 to $750 million for the year ended December 31, 2025, a decrease of $12 million or 2%, primarily as a result of increased proved reserve volumes due to higher commodity prices. DD&A expense per Mcfe remained relatively consistent for the years ended December 31, 2024 and 2025 at $0.61 and $0.60, respectively.

Previous wording

Impairment of property and equipment. Impairment of property and equipment decreased from $51 million for the year ended December 31, 2023 to $47 million for the year ended December 31, 2024, a decrease of $4 million, or 8%, primarily due to lower impairments of expiring leases between periods. 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.

Current wording

Impairment of property and equipment. Impairment of property and equipment decreased from $47 million for the year ended December 31, 2024 to $29 million for the year ended December 31, 2025, a decrease of $18 million, or 38%, primarily due to lower impairments of expiring leases between periods as a result of our maintenance capital program. 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.

Previous wording

Contract termination, loss contingency, settlements and other operating expenses. Contract termination, loss contingency, settlements and other operating expenses attributable to our exploration and production segment decreased from $29 million for the year ended December 31, 2023 to $5 million for the year ended December 31, 2024. This decrease was primarily due to a loss contingency recorded during the year ended December 31, 2023 and lower expense associated with the early termination of certain drilling and completion contracts between periods.

Current wording

Contract termination, loss contingency, settlements and other operating expenses. Contract termination, loss contingency, settlements and other operating expenses attributable to our exploration and production segment increased from $5 million for the year ended December 31, 2024 to $28 million for the year ended December 31, 2025, an increase of $23 million. This increase was primarily due to loss contingencies recorded during the year ended December 31, 2025. See Note 15—Contingencies to our consolidated financial statements for additional information.

Previous wording

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.

Current wording

Net marketing expense remained relatively consistent at $66 million, or $0.05 per Mcfe, for the year ended December 31, 2024 and $64 million, or $0.05 per Mcfe, for the year ended December 31, 2025.

Previous wording

Marketing revenue. 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:

Current wording

Marketing revenue. Marketing revenue decreased from $179 million for the year ended December 31, 2024 to $126 million for the year ended December 31, 2025, a decrease of $53 million, or 30%. This fluctuation primarily resulted from the following:

Previous wording

Marketing expense. Marketing expense decreased from $285 million for the year ended December 31, 2023 to $245 million for the year ended December 31, 2024, a decrease of $40 million, or 14%. Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related to current excess firm capacity. The cost of third-party natural gas purchases decreased $62 million between periods, partially offset by increased oil and NGLs purchases of $37 million and $4 million, respectively. The total cost of third-party commodity purchases decreased primarily due to lower natural gas marketing volumes and prices between periods, partially offset by higher oil and NGLs marketing volumes during the year ended December 31, 2024. 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.

Current wording

Marketing expense. Marketing expense decreased from $245 million for the year ended December 31, 2024 to $190 million for the year ended December 31, 2025, a decrease of $55 million, or 22%. Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related to current excess firm capacity. The cost of third-party commodity purchases decreased by $60 million between periods primarily due to lower marketing volumes and oil prices between periods, partially offset by higher natural gas prices during the year ended December 31, 2025. Firm transportation costs increased $5 million between periods primarily due to the increase in fuel costs and lower pipeline utilization due to maintenance during the year ended December 31, 2025.

Previous wording

Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $1.0 billion for the year ended December 31, 2023 to $1.1 billion for the year ended December 31, 2024, an increase of $0.1 billion, or 6%. This increase is primarily due to higher gathering and compression revenues of $84 million, partially offset by lower water handling revenues of $20 million. The increased gathering and compression revenues between periods is primarily a result of the expiration of the growth incentive fee rebate program on December 31, 2023, increased throughput and annual CPI-based gathering and compression rate adjustments between periods. The decreased water handling revenues between periods is primarily due to lower fresh water delivery and other fluid handling volumes, partially offset by an increased fresh water delivery rate due to an annual CPI-based adjustment during the year ended December 31, 2024.

Current wording

Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $1.1 billion for the year ended December 31, 2024 to $1.2 billion for the year ended December 31, 2025, an increase of $0.1 billion. This increase is primarily due to higher gathering and processing revenues of $61 million and higher water handling revenues of $21 million. The increased gathering and processing revenues between periods is primarily a result of increased throughput and annual CPI-based gathering and compression rate adjustments between periods. The increased water handling revenues between periods is primarily due to higher wastewater trucking and blending volumes, increased wastewater trucking and disposal costs that are billed at cost plus 3% higher fresh water delivery volumes and increased blending cost of service fees during the year ended December 31, 2025, as well as an increase to the fresh water delivery rate as a result of the annual CPI-based rate adjustment between periods.

Previous wording

Income tax (expense) benefit. For the year ended December 31, 2023, we had income tax expense of $64 million, with an effective tax rate of 17.6%, due to income before income taxes of $361 million. 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. For the year ended December 31, 2024, we had an income tax benefit of $118 million primarily due to R&D tax credits of $95 million, loss before income taxes of $24 million and a reduction to our state NOL carryforward valuation allowance of $12 million. See Note 13—Income Taxes to our consolidated financial statements for additional information.

Current wording

Income tax (expense) benefit. For the year ended December 31, 2024, we recognized an income tax benefit of $118 million primarily due to R&D tax credits of $95 million, loss before income taxes of $24 million and a reduction to our state NOL carryforward valuation allowance of $12 million. For the year ended December 31, 2025, we recognized income tax expense of $216 million, with an effective tax rate of 24%, related to our income before income taxes of $890 million. Our effective tax rate for the year ended December 31, 2025 was different than the federal statutory rate of 21% primarily due to the effects of state income taxes, equity-based compensation expenses, dividends received deduction and noncontrolling interests. See Note 13—Income Taxes to our consolidated financial statements for additional information.

Previous wording

As of December 31, 2024, we had U.S. federal and state NOL carryforwards of $0.6 billion and $1.9 billion, respectively. Many of these NOL carryforwards expire at various dates between 2025 and 2044 while others have no expiration date. Potential future legislation or the imposition of new or increased taxes may have a significant effect on our future taxable position. The impact of any such change would be recorded in the period in which such interpretation is received or legislation is enacted.

Current wording

As of December 31, 2025, we had U.S. federal and state NOL carryforwards of approximately $960 million and $1.9 billion, respectively. Many of these NOL carryforwards expire at various dates between 2026 and 2044 while others have no expiration date. Potential future legislation or the imposition of new or increased taxes may have a significant effect on our future taxable position. The impact of any such change would be recorded in the period in which such interpretation is received or legislation is enacted.

Previous wording

Our primary sources of liquidity have been through net cash provided by operating activities, borrowings under our Credit Facility, issuances of debt and equity securities and additional contributions from our asset sales, including our drilling partnerships. Our primary use of cash has been for the exploration, development and acquisition of oil and natural gas properties. As we develop our reserves, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future success in developing our proved reserves and production will be highly dependent on net cash provided by operating activities and the capital resources available to us.

Current wording

Our primary sources of liquidity have been through net cash provided by operating activities, borrowings under our Credit Facility, our Term Loan A Facility, issuances of debt and equity securities and additional contributions from our asset sales, including our drilling partnerships. Our primary use of cash has been for the exploration, development and acquisition of oil and natural gas properties. As we develop our reserves, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future success in developing our proved reserves and production will be highly dependent on net cash provided by operating activities and the capital resources available to us.

Previous wording

Our commodity hedge position can provide us with liquidity for the portion of our production that is hedged because it provides us with the relative certainty of our future expected revenues for such production despite potential declines in the price of natural gas. However, due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased. Assuming our 2025 production is the same as our production in 2024, approximately 3% of our total production for 2025 is hedged through fixed price commodity swaps. 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. We believe that the participants in the syndicate have the capability to fund up to their current commitment. If one or more banks should not be able to do so, we may not have the full availability of the Credit Facility.

Current wording

Our commodity hedge position can provide us with liquidity for the portion of our production that is hedged because it provides us with the relative certainty of our future expected revenues for such production despite potential declines in the price of natural gas. Assuming our 2026 production is the same as our production in 2025, approximately 42% of our total production for 2026 is hedged through commodity derivatives. Our ability to make significant acquisitions for cash would require us to utilize borrowings under 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. We believe that the participants in the syndicate have the capability to fund up to their current commitment. If one or more banks should not be able to do so, we may not have the full availability of the Credit Facility.

Previous wording

For the year ended December 31, 2024, our total consolidated capital expenditures were $721 million, including drilling and completion expenditures of $620 million, leasehold additions of $91 million and other capital expenditures of $10 million. We completed 41 net horizontal wells during the year ended December 31, 2024. 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. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices.

Current wording

For the year ended December 31, 2025, our total consolidated capital expenditures were $797 million, including drilling and completion expenditures of $658 million, leasehold additions of $131 million and other capital expenditures of $8 million. We completed 61 net horizontal wells during the year ended December 31, 2025. Our capital budget for 2026 is $1.1 billion to $1.3 billion and includes: $1.0 billion for drilling and completions, $100 million for leasehold expenditures and up to $200 million for discretionary growth capital that is dependent on commodity prices. Our capital budget reflects the closing of the HG Acquisition on February 3, 2026 and assumes the closing of the Utica Shale Divestiture during February 2026. We do not budget for acquisitions. During 2026, we plan to complete 70 to 80 net horizontal wells in the Appalachian Basin. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, acquisition opportunities and commodity prices.

Previous wording

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. For more information on our outstanding indebtedness, see Note 7—Long-Term Debt to our consolidated financial statements.

Current wording

Based on strip prices as of December 31, 2025, we believe that net cash provided from operating activities and available borrowings under the Credit Facility, the net proceeds of the offering of the 2036 Notes, borrowings under the Term Loan A Facility and net proceeds from the Utica Shale Divestiture 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. For more information on our outstanding indebtedness, see Note 7—Long-Term Debt to our consolidated financial statements.

Previous wording

Operating activities. Net cash provided by operating activities was $995 million and $849 million for the years ended December 31, 2023 and 2024, respectively. Net cash provided by operating activities decreased primarily due to lower natural gas prices and changes in working capital, partially offset by increased NGLs revenue due to higher C3+ NGLs prices, lower contract termination, loss contingency and settlements expense and lower net marketing expense between periods and a $202 million payment for early settlement of our swaption agreement in the year ended December 31, 2023.

Current wording

Operating activities. Net cash provided by operating activities was $0.8 billion and $1.6 billion for the years ended December 31, 2024 and 2025, respectively. Net cash provided by operating activities increased between periods primarily due to higher natural gas revenues, lower ad valorem taxes, lower interest expense and changes in working capital, partially offset by lower NGLs and oil revenues, higher lease operating expense and higher gathering, compression, processing and transportation expense during the year ended December 31, 2025.

Previous wording

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in Note 2—Summary of Significant Accounting Policies to our consolidated financial statements. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingent liabilities. Accounting estimates and assumptions are considered to be critical if there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under

Current wording

affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingent liabilities. Accounting estimates and assumptions are considered to be critical if there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. 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. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements.

Previous wording

Unproved properties with significant acquisition costs are assessed for impairment on a property by property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks and future plans to develop acreage. 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.

Current wording

Unproved properties with significant acquisition costs are assessed for impairment on a property by property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks and future plans to develop acreage. Impairment of oil and gas properties related to unproved properties for leases that have expired, or are expected to expire, was $51 million, $47 million and $29 million for the years ended December 31, 2023, 2024 and 2025, respectively.

Previous wording

reporting period, which would require us to further evaluate if an impairment charge would be 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. 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.

Current wording

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. 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. For our Utica and Marcellus properties, strip pricing would have to decline by more than 6% and 20%, respectively, from year end 2025 levels before further evaluation of those properties would be required in order to determine if an impairment charge is necessary. If future prices decline from December 31, 2025, 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.

Previous wording

We believe that the estimates and assumptions related to our undiscounted future net cash flows and the fair value of our proved properties is critical because different natural gas, NGLs and oil pricing, cost assumptions or discount rates, as applicable, may affect the recognition, timing and amount of an impairment and, if changed, could have a material effect on the Company's financial position and results of operations.

Current wording

We believe that the estimates and assumptions related to our undiscounted future net cash flows and the fair value of our proved properties are critical because different natural gas, NGLs and oil pricing, cost assumptions or discount rates, as applicable, may affect the recognition, timing and amount of an impairment and, if changed, could have a material effect on the Company's financial position and results of operations.

Previous wording

Income taxes are accounted for using the asset and liability approach. Under this approach, deferred income tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. We record 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. We are subject to state and federal income taxes, but are currently not in a cash tax paying position with respect to federal income taxes.

Current wording

Income taxes are accounted for using the asset and liability approach. Under this approach, deferred income tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. We record 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. We are subject to state and U.S. federal income taxes, but are currently not in a cash tax paying position with respect to U.S. federal income taxes.

Previous wording

We record a valuation allowance or reserve for an uncertain tax position 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. 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. Management considers the scheduled reversal of deferred income tax liabilities, projected future taxable income and tax planning strategies in making this assessment, estimates of which may be imprecise due to unforeseen future events or conditions outside of our control, including changes in commodity prices or changes to tax laws and regulations. The amount of deferred income tax assets considered realizable could change based upon the amounts of taxable income actually generated, or as estimates of future taxable income change. 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. In addition, as of December 31, 2024, we have recorded a reserve for uncertain tax positions of $54 million related to our R&D tax credits.

Current wording

We record a valuation allowance or reserve for an uncertain tax position 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. 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. Management considers the scheduled reversal of deferred income tax liabilities, projected future taxable income and tax planning strategies in making this assessment, estimates of which may be imprecise due to unforeseen future events or conditions outside of our control, including changes in commodity prices or changes to tax laws and regulations. The amount of deferred income tax assets considered realizable could change based upon the amounts of taxable income actually generated, or as estimates of future taxable income change. As of December 31, 2025, we have recognized a valuation allowance of $39 million related to Colorado and Oklahoma state NOL carryforwards that we do not expect to realize due to expected future reduced income tax apportionment in those states. In addition, as of December 31, 2025, we have recorded a reserve for uncertain tax positions of $51 million related to our R&D tax credits.