ANTERO RESOURCES Corp 10-Q

Item 2. 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 unaudited condensed consolidated financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in natural gas, NGLs and oil prices, the timing of planned capital expenditures, our ability to fund our development programs, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, impacts of world health events and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements.” Also, see the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. In this section, references to “Antero,” the “Company,” “we,” “us,” and “our” refer to Antero Resources Corporation and its subsidiaries, unless otherwise indicated or the context otherwise requires. Our Company 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 September 30, 2025, we held approximately 528,000 net acres in the Appalachian Basin. Financing Highlights Credit Facility Maturity Date Extension Effective July 30, 2025, we obtained the consent of each of the lenders under our Unsecured Credit Facility to extend the Maturity Date from July 30, 2029 to July 30, 2030. The terms of the Unsecured Credit Facility otherwise remain unchanged. Under the terms of the Unsecured Credit Facility, we may request two one-year extensions of the Maturity Date, subject to the satisfaction of certain conditions. This is the first such extension. Debt Repurchase Program During the nine months ended September 30, 2025, we redeemed the remaining $97 million aggregate principal amount of our 2026 Notes at a redemption price of 102.094% of the principal amount thereof, plus accrued and unpaid interest. In addition, we repurchased $42 million aggregate principal amount of our 2029 Notes through open market transactions at a weighted average price of approximately 103% of the principal amount thereof, plus accrued and unpaid interest. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for additional information. Share Repurchase Program During 2022, our Board of Directors authorized a share repurchase program that allows us to repurchase up to $2.0 billion of outstanding common stock. Through our share repurchase program, during the three and nine months ended September 30, 2025, we repurchased and retired approximately 1.5 million and 4 million shares of our common stock, respectively, at a total cost of $51 million and $136 million, respectively. As of September 30, 2025, we have approximately $915 million of capacity remaining under our share repurchase program. 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. The timing, as well as the number and value of shares repurchased under the program, will be determined by us at our discretion and will depend on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. 35 Table of Contents Market Conditions and Business Trends Commodity Markets 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 three and nine months ended September 30, 2025 as compared to the same periods of 2024. As a result of the higher benchmark natural gas and ethane prices during the three and nine months ended September 30, 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 three and nine months ended September 30, 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 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 the unaudited condensed consolidated financial statements for additional information on our derivative instruments. The following table details the average benchmark natural gas, NGLs and oil prices: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended September 30, ​ Nine Months Ended September 30, ​ ​ 2024 2025 2024 2025 ​ Henry Hub ($/Mcf) (1) ​ $ 2.16 ​ ​ 3.07 ​ ​ 2.10 ​ ​ 3.39 ​ Mont Belvieu Ethane ($/Bbl) (2) ​ ​ 6.61 ​ ​ 9.72 ​ ​ 7.58 ​ ​ 10.43 ​ Mont Belvieu C3+ NGLs ($/Bbl) (3) ​ ​ 39.01 ​ ​ 35.76 ​ ​ 40.70 ​ ​ 39.27 ​ West Texas Intermediate ($/Bbl) (4) ​ ​ 75.09 ​ ​ 64.93 ​ ​ 77.54 ​ ​ 66.70 ​ (1) NYMEX first of month average natural gas price. (2) Intercontinental Exchange, Inc. (“ICE”) settlement ethane Oil Price Information Service (“OPIS”) futures average price for the front month contract as published on the last trading day of the month. (3) ICE settlement propane, isobutane, normal butane and natural gasoline OPIS futures average price for the front month contract as published on the last trading day of the month. Propane and isobutane reflect TET prices, and normal butane and natural gasoline reflect non-TET prices. Propane, isobutane, normal butane and natural gasoline futures prices are weighted to approximate Antero Resources’ average C3+ NGLs composition. (4) NYMEX calendar month average settled futures price. Hedge Position Antero Resources 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 three months ended September 30, 2024 and 2025, 2% and 4%, respectively, of our production was hedged through commodity derivatives. For the nine months ended September 30, 2024 and 2025, 4% of our production was hedged through commodity derivatives. Assuming our 2025 and 2026 production is the same as our production in 2024, approximately 8% and 29%, respectively, of our total production for such years is hedged through commodity derivatives. As of September 30, 2025, the estimated fair value of our commodity derivative contracts was a net liability of $7 million. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for additional information. Martica 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 September 30, 2025, Martica had no derivative instruments. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for additional information. 36 Table of Contents 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. 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 1.25% 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. 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 the outbreak of armed conflict, including in the Middle East and Iran, 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. 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. These economic variables are beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows. 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. 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 16—Reportable Segments to our unaudited condensed consolidated financial statements for additional information. ​ 37 Table of Contents Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2025 The operating results of our reportable segments were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended September 30, 2024 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream (1) Affiliate Total ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 425,802 ​ ​ — ​ ​ — ​ ​ — ​ ​ 425,802 ​ Natural gas liquids sales ​ ​ 504,200 ​ ​ — ​ ​ — ​ ​ — ​ ​ 504,200 ​ Oil sales ​ ​ 52,724 ​ ​ — ​ ​ — ​ ​ — ​ ​ 52,724 ​ Commodity derivative fair value gains ​ ​ 18,368 ​ ​ — ​ ​ — ​ ​ — ​ ​ 18,368 ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 269,870 ​ ​ (269,870) ​ ​ — ​ Marketing ​ ​ — ​ ​ 47,160 ​ ​ — ​ ​ — ​ ​ 47,160 ​ Amortization of deferred revenue, VPP ​ ​ 6,812 ​ ​ — ​ ​ — ​ ​ — ​ ​ 6,812 ​ Other revenue and income ​ ​ 854 ​ ​ — ​ ​ — ​ ​ — ​ ​ 854 ​ Total revenue ​ ​ 1,008,760 ​ ​ 47,160 ​ ​ 269,870 ​ ​ (269,870) ​ ​ 1,055,920 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 29,597 ​ ​ — ​ ​ — ​ ​ — ​ ​ 29,597 ​ Gathering and compression ​ ​ 226,224 ​ ​ — ​ ​ 24,516 ​ ​ (24,516) ​ ​ 226,224 ​ Processing ​ ​ 276,569 ​ ​ — ​ ​ — ​ ​ — ​ ​ 276,569 ​ Transportation ​ ​ 182,390 ​ ​ — ​ ​ — ​ ​ — ​ ​ 182,390 ​ Water handling ​ ​ — ​ ​ — ​ ​ 27,208 ​ ​ (27,208) ​ ​ — ​ Production and ad valorem taxes ​ ​ 47,423 ​ ​ — ​ ​ — ​ ​ — ​ ​ 47,423 ​ Marketing ​ ​ — ​ ​ 62,144 ​ ​ — ​ ​ — ​ ​ 62,144 ​ Exploration ​ ​ 671 ​ ​ — ​ ​ — ​ ​ — ​ ​ 671 ​ General and administrative (excluding equity-based compensation) ​ ​ 38,562 ​ ​ — ​ ​ 10,927 ​ ​ (10,927) ​ ​ 38,562 ​ Equity-based compensation ​ ​ 16,065 ​ ​ — ​ ​ 11,945 ​ ​ (11,945) ​ ​ 16,065 ​ Depletion, depreciation and amortization ​ ​ 189,266 ​ ​ — ​ ​ 32,534 ​ ​ (32,534) ​ ​ 189,266 ​ Impairment of property and equipment ​ ​ 13,455 ​ ​ — ​ ​ 332 ​ ​ (332) ​ ​ 13,455 ​ Accretion of asset retirement obligations ​ ​ 998 ​ ​ — ​ ​ — ​ ​ — ​ ​ 998 ​ Gain on sale of assets ​ ​ (1,297) ​ ​ — ​ ​ — ​ ​ — ​ ​ (1,297) ​ Contract termination, loss contingency, settlements and other operating expenses ​ ​ (1,175) ​ ​ — ​ ​ (19) ​ ​ 19 ​ ​ (1,175) ​ Total operating expenses ​ ​ 1,018,748 ​ ​ 62,144 ​ ​ 107,443 ​ ​ (107,443) ​ ​ 1,080,892 ​ Operating income (loss) ​ $ (9,988) ​ ​ (14,984) ​ ​ 162,427 ​ ​ (162,427) ​ ​ (24,972) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 25,634 ​ ​ — ​ ​ 27,668 ​ ​ (27,668) ​ ​ 25,634 ​ (1) Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements. ​ 38 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended September 30, 2025 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream (1) Affiliate Total ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 630,887 ​ ​ — ​ ​ — ​ ​ — ​ ​ 630,887 ​ Natural gas liquids sales ​ ​ 470,392 ​ ​ — ​ ​ — ​ ​ — ​ ​ 470,392 ​ Oil sales ​ ​ 31,351 ​ ​ — ​ ​ — ​ ​ — ​ ​ 31,351 ​ Commodity derivative fair value gains ​ ​ 39,243 ​ ​ — ​ ​ — ​ ​ — ​ ​ 39,243 ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 294,821 ​ ​ (294,821) ​ ​ — ​ Marketing ​ ​ — ​ ​ 34,902 ​ ​ — ​ ​ — ​ ​ 34,902 ​ Amortization of deferred revenue, VPP ​ ​ 6,368 ​ ​ — ​ ​ — ​ ​ — ​ ​ 6,368 ​ Other revenue and income ​ ​ 851 ​ ​ — ​ ​ — ​ ​ — ​ ​ 851 ​ Total revenue ​ ​ 1,179,092 ​ ​ 34,902 ​ ​ 294,821 ​ ​ (294,821) ​ ​ 1,213,994 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 32,415 ​ ​ — ​ ​ — ​ ​ — ​ ​ 32,415 ​ Gathering and compression ​ ​ 231,413 ​ ​ — ​ ​ 29,077 ​ ​ (29,077) ​ ​ 231,413 ​ Processing ​ ​ 289,035 ​ ​ — ​ ​ — ​ ​ — ​ ​ 289,035 ​ Transportation ​ ​ 190,555 ​ ​ — ​ ​ — ​ ​ — ​ ​ 190,555 ​ Water handling ​ ​ — ​ ​ — ​ ​ 28,809 ​ ​ (28,809) ​ ​ — ​ Production and ad valorem taxes ​ ​ 28,884 ​ ​ — ​ ​ — ​ ​ — ​ ​ 28,884 ​ Marketing ​ ​ — ​ ​ 51,068 ​ ​ — ​ ​ — ​ ​ 51,068 ​ Exploration ​ ​ 844 ​ ​ — ​ ​ — ​ ​ — ​ ​ 844 ​ General and administrative (excluding equity-based compensation) ​ ​ 41,443 ​ ​ — ​ ​ 10,290 ​ ​ (10,290) ​ ​ 41,443 ​ Equity-based compensation ​ ​ 15,501 ​ ​ — ​ ​ 11,026 ​ ​ (11,026) ​ ​ 15,501 ​ Depletion, depreciation and amortization ​ ​ 188,778 ​ ​ — ​ ​ 34,465 ​ ​ (34,465) ​ ​ 188,778 ​ Impairment of property and equipment ​ ​ 12,228 ​ ​ — ​ ​ 167 ​ ​ (167) ​ ​ 12,228 ​ Accretion of asset retirement obligations ​ ​ 946 ​ ​ — ​ ​ — ​ ​ — ​ ​ 946 ​ Loss on sale of assets ​ ​ 171 ​ ​ — ​ ​ — ​ ​ — ​ ​ 171 ​ Contract termination, loss contingency, settlements and other operating expenses ​ ​ 12,596 ​ ​ — ​ ​ 494 ​ ​ (494) ​ ​ 12,596 ​ Total operating expenses ​ ​ 1,044,809 ​ ​ 51,068 ​ ​ 114,328 ​ ​ (114,328) ​ ​ 1,095,877 ​ Operating income (loss) ​ $ 134,283 ​ ​ (16,166) ​ ​ 180,493 ​ ​ (180,493) ​ ​ 118,117 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 29,055 ​ ​ — ​ ​ 29,688 ​ ​ (29,688) ​ ​ 29,055 ​ (1) Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements. ​ 39 Table of Contents Exploration and Production Segment The following table sets forth selected operating data of the exploration and production segment: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended ​ Amount of ​ ​ ​ ​ ​ September 30, ​ Increase ​ Percent ​ ​ ​ 2024 ​ 2025 ​ (Decrease) ​ Change ​ Production data (1) (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (Bcf) ​ ​ 200 ​ ​ 202 ​ ​ 2 ​ 1 % C2 Ethane (MBbl) ​ ​ 7,302 ​ ​ 7,808 ​ ​ 506 ​ 7 % C3+ NGLs (MBbl) ​ ​ 10,793 ​ ​ 10,495 ​ ​ (298) ​ (3) % Oil (MBbl) ​ ​ 856 ​ ​ 619 ​ ​ (237) ​ (28) % Combined (Bcfe) ​ ​ 313 ​ ​ 315 ​ ​ 2 ​ 1 % Daily combined production (MMcfe/d) ​ ​ 3,406 ​ ​ 3,429 ​ ​ 23 ​ 1 % Average prices before effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 2.13 ​ ​ 3.12 ​ ​ 0.99 ​ 46 % C2 Ethane (per Bbl) (4) ​ $ 8.01 ​ ​ 11.05 ​ ​ 3.04 ​ 38 % C3+ NGLs (per Bbl) ​ $ 41.30 ​ ​ 36.60 ​ ​ (4.70) ​ (11) % Oil (per Bbl) ​ $ 61.59 ​ ​ 50.65 ​ ​ (10.94) ​ (18) % Weighted Average Combined (per Mcfe) ​ $ 3.14 ​ ​ 3.59 ​ ​ 0.45 ​ 14 % Average realized prices after effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 2.14 ​ ​ 3.12 ​ ​ 0.98 ​ 46 % C2 Ethane (per Bbl) (4) ​ $ 8.01 ​ ​ 11.05 ​ ​ 3.04 ​ 38 % C3+ NGLs (per Bbl) ​ $ 41.56 ​ ​ 36.60 ​ ​ (4.96) ​ (12) % Oil (per Bbl) ​ $ 61.46 ​ ​ 50.65 ​ ​ (10.81) ​ (18) % Weighted Average Combined (per Mcfe) ​ $ 3.15 ​ ​ 3.59 ​ ​ 0.44 ​ 14 % Average costs (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 0.09 ​ ​ 0.10 ​ ​ 0.01 ​ 11 % Gathering and compression ​ $ 0.72 ​ ​ 0.73 ​ ​ 0.01 ​ 1 % Processing ​ $ 0.88 ​ ​ 0.92 ​ ​ 0.04 ​ 5 % Transportation ​ $ 0.58 ​ ​ 0.60 ​ ​ 0.02 ​ 3 % Production and ad valorem taxes ​ $ 0.15 ​ ​ 0.09 ​ ​ (0.06) ​ (40) % Marketing expense, net ​ $ 0.05 ​ ​ 0.05 ​ ​ — ​ * ​ General and administrative (excluding equity-based compensation) ​ $ 0.12 ​ ​ 0.13 ​ ​ 0.01 ​ 8 % Depletion, depreciation, amortization and accretion ​ $ 0.61 ​ ​ 0.60 ​ ​ (0.01) ​ (2) % * Not meaningful (1) Production data excludes volumes related to the VPP. (2) Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and may not reflect their relative economic value. (3) Average prices reflect the before and after effects of our settled commodity derivatives. Our calculation of such after effects includes gains (losses) on settlements of commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. (4) The average realized price for the three months ended September 30, 2025 includes less than $1 million of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives for the three months ended September 30, 2025 would have been $11.02 per Bbl. ​ Natural gas sales . Revenues from sales of natural gas increased from $426 million for the three months ended September 30, 2024 to $631 million for the three months ended September 30, 2025, an increase of $205 million, or 48%. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended September 30, 2025 accounted for an approximate $200 million 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 $5 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 . Revenues from sales of NGLs decreased from $504 million for the three months ended September 30, 2024 to $470 million for the three months ended September 30, 2025, a decrease of $34 million, or 7%. This decrease is primarily due to lower C3+ NGLs commodity prices and production volumes, partially offset by higher ethane commodity prices and production volumes between periods. Lower C3+ NGLs commodity prices (excluding the effects of derivative settlements) during the three months ended September 30, 2025 accounted for an approximate $50 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower 40 Table of Contents C3+ NGLs production volumes accounted for an approximate $12 million decrease in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price). Higher ethane commodity prices (excluding the effects of derivative settlements) during the three months ended September 30, 2025 accounted for an approximate $24 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Higher ethane production volumes accounted for an approximate $4 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price). Oil sales . Revenues from sales of oil decreased from $53 million for the three months ended September 30, 2024 to $31 million for the three months ended September 30, 2025, a decrease of $22 million, or 41%. Lower oil production volumes during the three months ended September 30, 2025 accounted for an approximate $15 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price). Lower commodity prices (excluding the effects of derivative settlements) during the three months ended September 30, 2025 accounted for an approximate $7 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Commodity derivative fair value gains. Our commodity derivatives included fixed price swaps, collars, basis swaps, 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 unaudited condensed consolidated statements of operations and comprehensive income (loss). For the three months ended September 30, 2024 and 2025, our commodity hedges resulted in derivative fair value gains of $18 million and $39 million, respectively. For the three months ended September 30, 2024, commodity derivative fair value gains included $4 million of net cash proceeds on settled commodity derivative gains. For the three months ended September 30, 2025, commodity derivative fair value gains included $2 million of net cash payments for settled derivative losses. 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 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. We expect continued volatility in commodity prices and the related fair value of our derivative instruments in the future. Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP decreased from $7 million for the three months ended September 30, 2024 to $6 million for the three months ended September 30, 2025, a decrease of $1 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. Lease operating expense . Lease operating expense increased from $30 million, or $0.09 per Mcfe, for the three months ended September 30, 2024 to $32 million, or $0.10 per Mcfe, for the three months ended September 30, 2025, an increase of $2 million primarily due to increased produced water trucking and disposal costs as a result of our completion activity timing during the three months ended September 30, 2025, as well as higher oilfield service and workover costs between periods. Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense increased from $685 million for the three months ended September 30, 2024 to $711 million for the three months ended September 30, 2025, an increase of $26 million, or 4%. This was primarily a result of the following: ● Gathering and compression costs increased from $0.72 per Mcfe for the three months ended September 30, 2024 to $0.73 per Mcfe for the three months ended September 30, 2025, primarily due to increased fuel costs as a result of higher natural gas prices and annual CPI-based adjustments between periods. ● Processing costs increased from $0.88 per Mcfe for the three months ended September 30, 2024 to $0.92 per Mcfe for the three months ended September 30, 2025, primarily due to increased costs for NGLs processing, which includes an annual CPI-based adjustment during the first quarter of 2025 and higher NGLs transportation fees. ● Transportation costs increased from $0.58 per Mcfe for the three months ended September 30, 2024 to $0.60 per Mcfe for the three months ended September 30, 2025, primarily due to higher fuel costs as a result of higher 41 Table of Contents natural gas prices between periods and higher demand fees for certain pipelines during the three months ended September 30, 2025. Production and ad valorem tax expense. Production and ad valorem taxes decreased from $47 million for the three months ended September 30, 2024 to $29 million for the three months ended September 30, 2025, a decrease of $18 million, or 39%, primarily due to lower ad valorem taxes, partially offset by higher severance taxes as a result of increased natural gas prices during the three months ended September 30, 2025. Production and ad valorem taxes as a percentage of natural gas revenues decreased from 11% for the three months ended September 30, 2024 to 5% for the three months ended September 30, 2025, primarily as a result of lower ad valorem taxes. 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. General and administrative expense . General and administrative expense (excluding equity-based compensation expense) increased from $39 million for the three months ended September 30, 2024 to $41 million for the three months ended September 30, 2025, an increase of $2 million, or 7%, primarily due to higher professional service fees between periods. General and administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.12 per Mcfe for the three months ended September 30, 2024 to $0.13 per Mcfe for the three months ended September 30, 2025 primarily as a result of higher overall costs between periods . Equity-based compensation expense . Non-cash equity-based compensation expense remained consistent at $16 million for the three months ended September 30, 2024 and 2025. See Note 9—Equity-Based Compensation to the unaudited condensed consolidated financial statements for additional information. Depletion, depreciation and amortization expense (“DD&A expense”) . DD&A expense remained consistent at $189 million for each of the three months ended September 30, 2024 and 2025. DD&A expense per Mcfe also remained relatively consistent for the three months ended September 30, 2024 and 2025 at $0.61 and $0.60, respectively. Impairment of property and equipment . Impairment of oil and gas properties remained relatively consistent at $13 million and $12 million for the three months ended September 30, 2024 and 2025, respectively. 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, settlements and other operating expenses . Contract termination, loss contingency, settlements and other operating expenses was a gain of $1 million for the three months ended September 30, 2024 primarily due to our receipt of 0.1 million shares of Antero Midstream common stock as part of a judgment in a legal proceeding with an unaffiliated third-party. Contract termination, loss contingency, settlements and other operating expenses was a loss of $13 million for the three months ended September 30, 2025 primarily due to loss contingencies recorded during the third quarter of 2025. See Note 14—Contingencies to the unaudited condensed consolidated financial statements for additional information. Marketing Segment Where feasible, we purchase and sell third-party natural gas and NGLs and market our excess firm transportation capacity, or engage third parties to conduct these activities on our behalf, in order to optimize the revenues from these transportation agreements. We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production in order to secure guaranteed capacity to favorable markets. Net marketing expense remained relatively consistent at $15 million, or $0.05 per Mcfe, for the three months ended September 30, 2024 and $16 million, or $0.05 per Mcfe, for the three months ended September 30, 2025. Marketing revenue. Marketing revenue decreased from $47 million for the three months ended September 30, 2024 to $35 million for the three months ended September 30, 2025, a decrease of $12 million, or 26%. This fluctuation primarily resulted from the following: ● Natural gas marketing revenue decreased by $9 million between periods primarily due to lower natural gas marketing volumes, partially offset by higher natural gas prices. Lower natural gas marketing volumes accounted for an $11 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher natural gas prices accounted for a $2 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). 42 Table of Contents ● Oil marketing revenue decreased by $9 million between periods primarily due to lower oil marketing volumes and prices. Lower oil marketing volumes accounted for a $5 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower oil prices accounted for a $4 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). ● NGLs marketing revenues increased by $5 million for the three months ended September 30, 2025 primarily due to higher C3+ NGLs marketing volumes. Marketing expense. Marketing expense decreased from $62 million for the three months ended September 30, 2024 to $51 million for the three months ended September 30, 2025, a decrease of $11 million, or 18%. 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 costs of third-party natural gas and oil purchases each decreased $9 million between periods, and the cost of third-party NGLs purchases increased $4 million between periods. The total cost of third-party commodity purchases decreased primarily due to lower marketing volumes between periods, partially offset by higher natural gas prices during the three months ended September 30, 2025. Firm transportation costs increased $3 million between periods primarily due to higher fuel costs and lower pipeline utilization due to maintenance during the three months ended September 30, 2025. Antero Midstream Segment Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $270 million for the three months ended September 30, 2024 to $295 million for the three months ended September 30, 2025, an increase of $25 million. This increase is primarily due to higher gathering and processing revenues of $15 million and higher water handling revenues of $10 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 fresh water delivery volumes during the three months ended September 30, 2025, as well as increased blending volumes, increased wastewater handling costs and an increase to the fresh water delivery rate as a result of an annual CPI-based rate adjustment between periods. Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $107 million for the three months ended September 30, 2024 to $114 million for the three months ended September 30, 2025, an increase of $7 million. This increase is primarily due to higher direct operating expenses as a result of increased gathering and compression and fresh water delivery volumes between periods, as well as higher heavy maintenance expense and increased wastewater handling costs during the three months ended September 30, 2025. Items Not Allocated to Segments Interest expense. Interest expense decreased from $28 million for the three months ended September 30, 2024 to $18 million for the three months ended September 30, 2025, a decrease of $10 million, or 36%, primarily due to the redemption or repurchase of $139 million aggregate principal amount of our Senior Notes during the nine months ended September 30, 2025 and lower average Credit Facility borrowings and interest rates during the three months ended September 30, 2025. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. Loss on early extinguishment of debt. During the three months ended September 30, 2024, we recognized a loss on early debt extinguishment of $1 million related to the amendment and restatement of our senior revolving credit facility. There was no loss on early extinguishment of debt for the three months ended September 30, 2025. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. Income tax benefit (expense) . For the three months ended September 30, 2024, we recognized an income tax benefit of $3 million, with an effective tax rate of 10%, due to a loss before income taxes of $28 million. For the three months ended September 30, 2025, we recognized income tax expense of $43 million, with an effective tax rate of 34%, due to income before income taxes of $129 million. The increase in the effective tax rate between periods was primarily due to the effects of noncontrolling interests and stock compensation expense. See Note 2—Summary of Significant Accounting Policies to the unaudited condensed consolidated financial statements for additional information on the effects of the OBBB. ​ 43 Table of Contents Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2025 The operating results of our reportable segments were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nine Months Ended September 30, 2024 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream (1) Affiliate Total Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 1,274,503 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,274,503 ​ Natural gas liquids sales ​ ​ 1,511,253 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,511,253 ​ Oil sales ​ ​ 180,899 ​ ​ — ​ ​ — ​ ​ — ​ ​ 180,899 ​ Commodity derivative fair value gains ​ ​ 22,229 ​ ​ — ​ ​ — ​ ​ — ​ ​ 22,229 ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 818,716 ​ ​ (818,716) ​ ​ — ​ Marketing ​ ​ — ​ ​ 145,098 ​ ​ — ​ ​ — ​ ​ 145,098 ​ Amortization of deferred revenue, VPP ​ ​ 20,289 ​ ​ — ​ ​ — ​ ​ — ​ ​ 20,289 ​ Other revenue and income ​ ​ 2,574 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,574 ​ Total revenue ​ ​ 3,011,747 ​ ​ 145,098 ​ ​ 818,716 ​ ​ (818,716) ​ ​ 3,156,845 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 88,477 ​ ​ — ​ ​ — ​ ​ — ​ ​ 88,477 ​ Gathering and compression ​ ​ 671,893 ​ ​ — ​ ​ 76,849 ​ ​ (76,849) ​ ​ 671,893 ​ Processing ​ ​ 802,349 ​ ​ — ​ ​ — ​ ​ — ​ ​ 802,349 ​ Transportation ​ ​ 546,664 ​ ​ — ​ ​ — ​ ​ — ​ ​ 546,664 ​ Water handling ​ ​ — ​ ​ — ​ ​ 85,202 ​ ​ (85,202) ​ ​ — ​ Production and ad valorem taxes ​ ​ 147,524 ​ ​ — ​ ​ — ​ ​ — ​ ​ 147,524 ​ Marketing ​ ​ — ​ ​ 192,764 ​ ​ — ​ ​ — ​ ​ 192,764 ​ Exploration ​ ​ 1,916 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,916 ​ General and administrative (excluding equity-based compensation) ​ ​ 120,624 ​ ​ — ​ ​ 32,441 ​ ​ (32,441) ​ ​ 120,624 ​ Equity-based compensation ​ ​ 49,293 ​ ​ — ​ ​ 32,871 ​ ​ (32,871) ​ ​ 49,293 ​ Depletion, depreciation and amortization ​ ​ 568,374 ​ ​ — ​ ​ 107,205 ​ ​ (107,205) ​ ​ 568,374 ​ Impairment of property and equipment ​ ​ 18,958 ​ ​ — ​ ​ 332 ​ ​ (332) ​ ​ 18,958 ​ Accretion of asset retirement obligations ​ ​ 2,554 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,554 ​ Gain on sale of assets ​ ​ (1,127) ​ ​ — ​ ​ — ​ ​ — ​ ​ (1,127) ​ Contract termination, loss contingency, settlements and other operating expenses ​ ​ 3,901 ​ ​ — ​ ​ 2,385 ​ ​ (2,385) ​ ​ 3,901 ​ Total operating expenses ​ ​ 3,021,400 ​ ​ 192,764 ​ ​ 337,285 ​ ​ (337,285) ​ ​ 3,214,164 ​ Operating income (loss) ​ $ (9,653) ​ ​ (47,666) ​ ​ 481,431 ​ ​ (481,431) ​ ​ (57,319) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 69,862 ​ ​ — ​ ​ 82,795 ​ ​ (82,795) ​ ​ 69,862 ​ (1) Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements. 44 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nine Months Ended September 30, 2025 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream (1) Affiliate Total Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 2,099,645 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,099,645 ​ Natural gas liquids sales ​ ​ 1,512,581 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,512,581 ​ Oil sales ​ ​ 115,386 ​ ​ — ​ ​ — ​ ​ — ​ ​ 115,386 ​ Commodity derivative fair value losses ​ ​ 20,981 ​ ​ — ​ ​ — ​ ​ — ​ ​ 20,981 ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 891,422 ​ ​ (891,422) ​ ​ — ​ Marketing ​ ​ — ​ ​ 94,203 ​ ​ — ​ ​ — ​ ​ 94,203 ​ Amortization of deferred revenue, VPP ​ ​ 18,896 ​ ​ — ​ ​ — ​ ​ — ​ ​ 18,896 ​ Other revenue and income ​ ​ 2,502 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,502 ​ Total revenue ​ ​ 3,769,991 ​ ​ 94,203 ​ ​ 891,422 ​ ​ (891,422) ​ ​ 3,864,194 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 103,645 ​ ​ — ​ ​ — ​ ​ — ​ ​ 103,645 ​ Gathering and compression ​ ​ 704,377 ​ ​ — ​ ​ 80,932 ​ ​ (80,932) ​ ​ 704,377 ​ Processing ​ ​ 834,230 ​ ​ — ​ ​ — ​ ​ — ​ ​ 834,230 ​ Transportation ​ ​ 569,135 ​ ​ — ​ ​ — ​ ​ — ​ ​ 569,135 ​ Water handling ​ ​ — ​ ​ — ​ ​ 96,898 ​ ​ (96,898) ​ ​ — ​ Production and ad valorem taxes ​ ​ 119,013 ​ ​ — ​ ​ — ​ ​ — ​ ​ 119,013 ​ Marketing ​ ​ — ​ ​ 145,826 ​ ​ — ​ ​ — ​ ​ 145,826 ​ Exploration ​ ​ 2,160 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,160 ​ General and administrative (excluding equity-based compensation) ​ ​ 130,071 ​ ​ — ​ ​ 31,630 ​ ​ (31,630) ​ ​ 130,071 ​ Equity-based compensation ​ ​ 46,501 ​ ​ — ​ ​ 34,835 ​ ​ (34,835) ​ ​ 46,501 ​ Depletion, depreciation and amortization ​ ​ 562,719 ​ ​ — ​ ​ 100,577 ​ ​ (100,577) ​ ​ 562,719 ​ Impairment of property and equipment ​ ​ 24,143 ​ ​ — ​ ​ 984 ​ ​ (984) ​ ​ 24,143 ​ Accretion of asset retirement obligations ​ ​ 2,827 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,827 ​ Loss on sale of assets ​ ​ 142 ​ ​ — ​ ​ — ​ ​ — ​ ​ 142 ​ Contract termination, loss contingency, settlements and other operating expenses ​ ​ 24,933 ​ ​ — ​ ​ 1,406 ​ ​ (1,406) ​ ​ 24,933 ​ Total operating expenses ​ ​ 3,123,896 ​ ​ 145,826 ​ ​ 347,262 ​ ​ (347,262) ​ ​ 3,269,722 ​ Operating income (loss) ​ $ 646,095 ​ ​ (51,623) ​ ​ 544,160 ​ ​ (544,160) ​ ​ 594,472 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 88,279 ​ ​ — ​ ​ 87,724 ​ ​ (87,724) ​ ​ 88,279 ​ (1) Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements. ​ 45 Table of Contents Exploration and Production Segment The following table sets forth selected operating data of the exploration and production segment: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nine Months Ended ​ Amount of ​ ​ ​ ​ ​ ​ September 30, ​ Increase ​ Percent ​ ​ ​ 2024 2025 (Decrease) Change ​ ​ Production data (1) (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (Bcf) ​ ​ 597 ​ ​ 599 ​ ​ 2 ​ * ​ ​ C2 Ethane (MBbl) ​ ​ 21,873 ​ ​ 22,174 ​ ​ 301 ​ 1 % ​ C3+ NGLs (MBbl) ​ ​ 31,871 ​ ​ 31,332 ​ ​ (539) ​ (2) % ​ Oil (MBbl) ​ ​ 2,843 ​ ​ 2,143 ​ ​ (700) ​ (25) % ​ Combined (Bcfe) ​ ​ 936 ​ ​ 933 ​ ​ (3) ​ * ​ ​ Daily combined production (MMcfe/d) ​ ​ 3,417 ​ ​ 3,419 ​ ​ 2 ​ * ​ ​ Average prices before effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 2.14 ​ ​ 3.50 ​ ​ 1.36 ​ 64 % ​ C2 Ethane (per Bbl) (4) ​ $ 8.56 ​ ​ 11.69 ​ ​ 3.13 ​ 37 % ​ C3+ NGLs (per Bbl) ​ $ 41.54 ​ ​ 40.00 ​ ​ (1.54) ​ (4) % ​ Oil (per Bbl) ​ $ 63.63 ​ ​ 53.84 ​ ​ (9.79) ​ (15) % ​ Weighted Average Combined (per Mcfe) ​ $ 3.17 ​ ​ 3.99 ​ ​ 0.82 ​ 26 % ​ Average realized prices after effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 2.15 ​ ​ 3.47 ​ ​ 1.32 ​ 61 % ​ C2 Ethane (per Bbl) (4) ​ $ 8.56 ​ ​ 11.69 ​ ​ 3.13 ​ 37 % ​ C3+ NGLs (per Bbl) ​ $ 41.68 ​ ​ 40.00 ​ ​ (1.68) ​ (4) % ​ Oil (per Bbl) ​ $ 63.49 ​ ​ 53.80 ​ ​ (9.69) ​ (15) % ​ Weighted Average Combined (per Mcfe) ​ $ 3.18 ​ ​ 3.97 ​ ​ 0.79 ​ 25 % ​ Average costs (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 0.09 ​ ​ 0.11 ​ ​ 0.02 ​ 22 % ​ Gathering and compression ​ $ 0.72 ​ ​ 0.75 ​ ​ 0.03 ​ 4 % ​ Processing ​ $ 0.86 ​ ​ 0.89 ​ ​ 0.03 ​ 3 % ​ Transportation ​ $ 0.58 ​ ​ 0.61 ​ ​ 0.03 ​ 5 % ​ Production and ad valorem taxes ​ $ 0.16 ​ ​ 0.13 ​ ​ (0.03) ​ (19) % ​ Marketing expense, net ​ $ 0.05 ​ ​ 0.06 ​ ​ 0.01 ​ 20 % ​ General and administrative (excluding equity-based compensation) ​ $ 0.13 ​ ​ 0.14 ​ ​ 0.01 ​ 8 % ​ Depletion, depreciation, amortization and accretion ​ $ 0.61 ​ ​ 0.61 ​ ​ — ​ * ​ ​ * Not meaningful (1) Production data excludes volumes related to the VPP. (2) Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and may not reflect their relative economic value. (3) Average prices reflect the before and after effects of our settled commodity derivatives. Our calculation of such after effects includes gains (losses) on settlements of commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. (4) The average realized price for the nine months ended September 30, 2024 and 2025 includes $2 million and $1 million, respectively, of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives for the nine months ended September 30, 2024 and 2025 would have been $8.48 per Bbl and $11.66 per Bbl, respectively. ​ Natural gas sales . Revenues from sales of natural gas increased from $1.3 billion for the nine months ended September 30, 2024 to $2.1 billion for the nine months ended September 30, 2025, an increase of $0.8 billion, or 65%. Higher commodity prices (excluding the effects of derivative settlements) during the nine months ended September 30, 2025 accounted for an approximate $0.8 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). Natural gas production volumes remained relatively consistent between periods. NGLs sales . Revenues from sales of NGLs remained consistent at $1.5 billion for each of the nine months ended September 30, 2024 and 2025. Higher commodity prices (excluding the effects of derivative settlements) during the nine months ended September 30, 2025 accounted for an approximate $21 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower NGLs production volumes accounted for an approximate $20 million decrease in year-over-year NGLs revenues, respectively (calculated as the change in year-to-year volumes times the prior year average price). 46 Table of Contents Oil sales . Revenues from sales of oil decreased from $181 million for the nine months ended September 30, 2024 to $115 million for the nine months ended September 30, 2025, a decrease of $66 million, or 36%. Lower oil production volumes during the nine months ended September 30, 2025 accounted for an approximate $45 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, excluding the effects of derivative settlements, accounted for an approximate $21 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. Our commodity derivatives included fixed price swaps, collars, basis swaps, 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 unaudited condensed consolidated statements of operations and comprehensive income (loss). For the nine months ended September 30, 2024 and 2025, our commodity hedges resulted in derivative fair value gains of $22 million and $21 million, respectively. For the nine months ended September 30, 2024, commodity derivative fair value gains included $12 million of net cash proceeds for settled derivative gains. For the nine months ended September 30, 2025, commodity derivative fair value gains included $19 million of net cash payments for settled derivative losses. 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 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. Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP remained relatively consistent at $20 million and $19 million for the nine months ended September 30, 2024 and 2025, respectively. 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. Lease operating expense . Lease operating expense increased from $88 million, or $0.09 per Mcfe, for the nine months ended September 30, 2024 to $104 million, or $0.11 per Mcfe, for the nine months ended September 30, 2025, an increase of $16 million primarily due to higher oilfield service and workover costs between periods, as well as increased produced water trucking and disposal costs as a result of our completion activity timing during the nine months ended September 30, 2025. Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense increased from $2.0 billion for the nine months ended September 30, 2024 to $2.1 billion for the nine months ended September 30, 2025, an increase of $0.1 billion, or 4%. This fluctuation was primarily a result of the following: ● Gathering and compression costs on a per unit basis increased from $0.72 per Mcfe for the nine months ended September 30, 2024 to $0.75 per Mcfe for the nine months ended September 30, 2025, primarily due to increased fuel costs as a result of higher natural gas prices and annual CPI-based adjustments between periods. ● Processing costs on a per unit basis increased from $0.86 per Mcfe for the nine months ended September 30, 2024 to $0.89 per Mcfe for the nine months ended September 30, 2025, primarily due to increased costs for NGLs processing and transportation, which includes an annual CPI-based adjustment during the first quarter of 2025, and higher NGLs transportation fees between periods. ● Transportation costs on a per unit basis increased from $0.58 per Mcfe for the nine months ended September 30, 2024 to $0.61 per Mcfe for the nine months ended September 30, 2025, primarily due to higher fuel costs as a result of higher natural gas prices between periods and higher demand fees for certain pipelines during the nine months ended September 30, 2025. Production and ad valorem tax expense. Production and ad valorem taxes decreased from $148 million for the nine months ended September 30, 2024 to $119 million for the nine months ended September 30, 2025, a decrease of $29 million, or 19%, primarily due to lower ad valorem taxes, partially offset by higher severance taxes as a result of increased natural gas prices during the nine months ended September 30, 2025. Production and ad valorem taxes as a percentage of natural gas revenues decreased from 12% for the nine months ended September 30, 2024 to 6% for the nine months ended September 30, 2025, primarily as a result of lower ad valorem taxes. 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. 47 Table of Contents General and administrative expense . General and administrative expense (excluding equity-based compensation expense) increased from $121 million for the nine months ended September 30, 2024 to $130 million for nine months ended September 30, 2025, an increase of $9 million, or 8%, primarily due to higher professional service fees and increased salary and wage expense as a result of increased employee headcount between periods. General and administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.13 per Mcfe for the nine months ended September 30, 2024 to $0.14 per Mcfe for the nine months ended September 30, 2025 primarily as a result of higher overall costs between periods. Equity-based compensation expense . Non-cash equity-based compensation expense remained relatively consistent at $49 million and $47 million for the nine months ended September 30, 2024 and 2025, respectively. See Note 9—Equity-Based Compensation to the unaudited condensed consolidated financial statements for additional information. Depletion, depreciation and amortization expense. DD&A expense remained relatively consistent at $568 million, or $0.61 per Mcfe, and $563 million, or $0.61 per Mcfe, for the nine months ended September 30, 2024 and 2025, respectively. Impairment of property and equipment . Impairment of oil and gas properties increased from $19 million for the nine months ended September 30, 2024 to $24 million for the nine months ended September 30, 2025, primarily due to higher 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 place into service. Contract termination, loss contingency, settlements and other operating expenses . Contract termination, loss contingency, settlements and other operating expenses increased from $4 million for the nine months ended September 30, 2024 to $25 million for the nine months ended September 30, 2025, an increase of $21 million. This increase was primarily due to loss contingencies recorded during the nine months ended September 30, 2025. See Note 14—Contingencies to the unaudited condensed consolidated financial statements for additional information. Marketing Segment Where feasible, we purchase and sell third-party natural gas and NGLs and market our excess firm transportation capacity, or engage third parties to conduct these activities on our behalf, in order to optimize the revenues from these transportation agreements. We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production in order to secure guaranteed capacity to favorable markets. Net marketing expense increased from $48 million, or $0.05 per Mcfe, for the nine months ended September 30, 2024 to $52 million, or $0.06 per Mcfe, for the nine months ended September 30, 2025, primarily due to higher fuel costs and lower pipeline utilization due to maintenance between periods. M arketing revenue. Marketing revenue decreased from $145 million for the nine months ended September 30, 2024 to $94 million for the nine months ended September 30, 2025, a decrease of $51 million, or 35%. This fluctuation primarily resulted from the following: ● Natural gas marketing revenue decreased by $19 million between periods primarily due to lower natural gas marketing volumes, partially offset by higher natural gas prices. Lower natural gas marketing volumes accounted for a $23 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher natural gas prices accounted for a $4 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). ● Oil marketing revenue decreased by $44 million between periods primarily due to lower oil marketing volumes and prices. Lower oil marketing volumes accounted for a $28 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower oil prices accounted for an $16 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). ● NGLs marketing revenue increased by $7 million between periods primarily due to higher C3+ NGLs marketing volumes and higher ethane prices. Marketing expense. Marketing expense decreased from $193 million for the nine months ended September 30, 2024 to $146 million for the nine months ended September 30, 2025, a decrease of $47 million, or 24%. Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related 48 Table of Contents to current excess firm capacity. The cost of third-party natural gas and oil purchases decreased $18 million and $42 million between periods, respectively, and the cost of third-party NGLs purchases increased $6 million between periods. The total cost of third-party commodity purchases decreased primarily due to lower marketing volumes between periods, partially offset by higher natural gas prices during the nine months ended September 30, 2025. Firm transportation costs increased $7 million between periods primarily due to the increase in fuel costs and lower pipeline utilization due to maintenance during the nine months ended September 30, 2025. Antero Midstream Segment Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $819 million for the nine months ended September 30, 2024 to $891 million for the nine months ended September 30, 2025, an increase of $72 million. This increase is primarily due to higher gathering and processing revenues of $45 million and higher water handling revenues of $27 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 disposal 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 and volumes during the nine months ended September 30, 2025, as well as an increase to the fresh water delivery rate as a result of the annual CPI-based rate adjustment between periods. Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $337 million for the nine months ended September 30, 2024 to $347 million for the nine months ended September 30, 2025, an increase of $10 million. This increase is primarily due to higher direct operating expenses as a result of higher wastewater trucking and disposal costs, increased blending costs, increased fresh water delivery volumes, increased throughput, higher gathering and compression costs for assets acquired during the second quarter of 2024 and increased heavy maintenance expense during the nine months ended September 30, 2025, partially offset by lower depreciation expense associated with Antero Midstream’s program to repurpose underutilized compressor units to expand existing or construct new compressor stations between periods. Items Not Allocated to Segments Interest expense. Interest expense decreased from $91 million for the nine months ended September 30, 2024 to $62 million for the nine months ended September 30, 2025, a decrease of $29 million or 32%, primarily due to the redemption or repurchase of $139 million aggregate principal amount of our Senior Notes and lower average Credit Facility borrowings and interest rates during the nine months ended September 30, 2025. Loss on early extinguishment of debt. During the nine months ended September 30, 2024, we recognized a loss on early debt extinguishment of $1 million related to the amendment and restatement of our senior revolving credit facility. During the nine months ended September 30, 2025, we recognized a loss on early debt extinguishment of $4 million related to the redemption of the remaining $97 million aggregate principal amount of our 2026 Notes at a redemption price of 102.094% of the principal amount thereof, plus accrued and unpaid interest, and the repurchase of $42 million aggregate principal amount of our 2029 Notes through open market transactions at a weighted average price of approximately 103% of the principal amount thereof, plus accrued and unpaid interest. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. Income tax expense (benefit) . For the nine months ended September 30, 2024, we recognized an income tax benefit of $14 million, with an effective tax rate of 18%, related to our loss before income taxes of $79 million. For the nine months ended September 30, 2025, we recognized income tax expense of $146 million, with an effective tax rate of 24%, related to our income before income taxes of $618 million. The increase in the effective tax rate between periods was primarily due to the effects of noncontrolling interests and stock compensation expense. See Note 2—Summary of Significant Accounting Policies to the unaudited condensed consolidated financial statements for additional information on the effects of the OBBB. Capital Resources and Liquidity Sources and Uses of Cash 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 49 Table of Contents 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. Based on strip prices as of September 30, 2025, we believe that net cash provided by 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. Cash Flows The following table summarizes our cash flows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nine Months Ended September 30, ​ ​ ​ 2024 2025 Net cash provided by operating activities ​ $ 571,286 ​ ​ 1,260,187 ​ Net cash used in investing activities ​ ​ (588,251) ​ ​ (854,189) ​ Net cash provided by (used in) financing activities ​ ​ 16,965 ​ ​ (405,998) ​ Net increase in cash and cash equivalents ​ $ — ​ ​ — ​ ​ Operating activities. Net cash provided by operating activities was $571 million and $1.3 billion for the nine months ended September 30, 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 oil revenues between periods and higher lease operating, gathering, compression, processing and transportation expenses during the nine months ended September 30, 2025. Our net operating cash flows are sensitive to many variables, the most significant of which is the volatility of natural gas, NGLs and oil prices, as well as volatility in the cash flows attributable to settlement of our commodity derivatives. Prices for natural gas, NGLs and oil are primarily determined by prevailing market conditions. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets, storage capacity and other variables influence the market conditions for these products. These factors are beyond our control and are difficult to predict. Investing activities. Net cash used in investing activities increased from $588 million for the nine months ended September 30, 2024 to $854 million for the nine months ended September 30, 2025, primarily due to asset acquisitions during the third quarter of 2025 of $241 million and increased drilling and leasing activity of $35 million between periods, partially offset by higher proceeds from asset sales and trades of $8 million between periods primarily due to oil and gas property trades during the nine months ended September 30, 2025. Financing activities. Net cash provided by financing activities was $17 million for the nine months ended September 30, 2024. Net cash used in financing activities was $406 million for the nine months ended September 30, 2025. The increase in net cash used in financing activities between periods is primarily due to higher net repayments on our Credit Facility of $155 million, redemptions and repurchases of $142 million principal amount of our Senior Notes during the nine months ended September 30, 2025, share repurchases of $136 million during the nine months ended September 30, 2025, partially offset by lower payment of debt issuance costs for our Unsecured Credit Facility of $5 million and lower distributions to the noncontrolling interests in Martica of $5 million between periods. 2025 Capital Budget, Capital Spending and Acquisition s On February 12, 2025, we announced a net capital budget for 2025 of $725 million to $800 million that included a range of $650 million to $700 million for drilling and completion and $75 million to $100 million for leasehold expenditures. During the nine months ended September 30, 2025, we decreased our drilling and completion budget range to $650 million to $675 million to reflect our operational efficiencies, and we increased our leasehold expenditures budget range to $125 million to $150 million to expand our acreage position in the Marcellus Shale in West Virginia. Our revised net capital budget for 2025 is $775 million to $825 million. 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. For the three months ended September 30, 2025, our total consolidated capital expenditures were $217 million, including drilling and completion costs of $172 million, leasehold acquisitions of $42 million and other capital expenditures of $3 million. For the nine months ended September 30, 2025, our total consolidated capital expenditures were $604 million, including drilling and completion costs of $500 million, leasehold acquisitions of $98 million and other capital expenditures of 50 Table of Contents $6 million. In addition to our budgeted capital spending for the three and nine months ended September 30, 2025, we also acquired oil and gas properties for approximately $260 million during the third quarter of 2025. See Note 3—Transactions to the unaudited condensed consolidated financial statements for additional information. Debt Agreements See Note 7—Long Term Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q and to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the 2024 Form 10-K for information on our debt agreements. Critical Accounting Estimates The discussion and analysis of our financial condition and results of operations are based upon our unaudited condensed 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 unaudited condensed consolidated financial statements. The preparation of our unaudited condensed consolidated 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 the circumstances, the results of which form the basis for making judgments about the reported amounts in our unaudited condensed 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 unaudited condensed consolidated financial statements. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the 2024 Form 10-K for information on our critical accounting estimates. Impairment of Proved Properties We evaluate the carrying amount of our proved natural gas, NGLs and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount of our proved properties exceeds the estimated undiscounted future net cash flows (measured using futures prices at the balance sheet date), we further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeds the estimated fair value of the properties. Based on future prices as of September 30, 2025, the estimated undiscounted future net cash flows exceeded the carrying amount and no further evaluation was required. We have not recorded any impairment expenses associated with our proved properties during the nine months ended September 30, 2024 and 2025. 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. New Accounting Pronouncements See Note 2—Summary of Significant Accounting Policies to the unaudited condensed consolidated financial statements for information on new accounting pronouncements. Off-Balance Sheet Arrangements See Note 13—Commitments to the unaudited condensed consolidated financial statements for information on off balance sheet arrangements. 51 Table of Contents