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 June 30, 2026, we held approximately 858,000 net acres in the Appalachian Basin. HG Acquisition On December 5, 2025, we entered into a definitive agreement to acquire 100% of the issued and outstanding equity interests of HG Production for total cash consideration of $2.8 billion, subject to the terms and conditions thereof. The HG Acquisition included approximately 385,000 net acres in the core of the Marcellus Shale in West Virginia. This acquisition closed on the Closing Date. The HG Acquisition was funded with borrowings under the Term Loan, net proceeds of the 2036 Notes, borrowings under the Credit Facility and restricted cash. See Note 3—Transactions to our unaudited condensed consolidated financial statements for additional information. The Company’s condensed consolidated statement of operations for the six months ended June 30, 2026 included results of operations from the assets and operations acquired in the HG Acquisition from the Closing Date through June 30, 2026. In light of the nature and location of the assets and operations acquired in the HG Acquisition, we and Antero Midstream agreed in principle to certain updates to, and intend to modify, our existing commercial arrangements to provide for well pad compression with respect to certain wells and to provide certain water services. See Note 15—Related Parties to our unaudited condensed consolidated financial statements for additional information. Utica Shale Divestiture On December 5, 2025, we entered into a purchase and sale agreement with the Buyer Parties to sell our Utica Shale Properties for aggregate cash consideration of $800 million, subject to the terms and conditions thereof. The Utica Shale Properties included approximately 80,000 gross (70,000 net) acres located in Ohio and proved reserves of approximately 600 Bcfe as of December 31, 2025. The Utica Shale Divestiture closed on February 23, 2026, with an effective date of July 1, 2025. The net proceeds from the Utica Shale Divestiture were used for the repayment of long-term debt. See Note 3—Transactions to our unaudited condensed consolidated financial statements for additional information. ​ 35 Table of Contents Martica Hurdle Achievement and Dissolution On May 1, 2026, Sixth Street achieved its Hurdle for Martica. As such, beginning May 1, 2026, 85% of the distributions in respect of the ORRIs to which Sixth Street was entitled immediately prior to the Hurdle being achieved reverted to us. On June 30, 2026, we elected to dissolve Martica and make in-kind liquidating distributions to Sixth Street and ourselves, which included conveyance of the ORRIs to Sixth Street and Antero Resources after giving effect to the Reversion, after which Martica was deconsolidated for our condensed consolidated financial statements. On July 1, 2026, after the deconsolidation of Martica, our condensed consolidated financial statements will reflect the ORRIs conveyed to us by Martica after giving effect to the Reversion, including the related earnings and cash flows. See Note 2—Summary of Significant Accounting Policies for additional information. Financing Highlights Issuance of 2036 Notes On January 28, 2026, we issued $750 million of 5.400% senior notes due February 1, 2036 at a price of 99.869% of par. The 2036 Notes are unsecured and rank pari passu to our Credit Facility, Term Loan and other outstanding senior notes. The 2036 Notes are not guaranteed by any of our subsidiaries. The net proceeds from this offering were used to partially fund the HG Acquisition. See Note 3—Transactions and Note 7—Debt to our unaudited condensed consolidated financial statements for additional information. Term Loan On February 3, 2026, substantially concurrently with the consummation of the HG Acquisition, we entered into an unsecured three year term loan facility in an aggregate principal amount of $1.5 billion with the lenders party thereto and Royal Bank of Canada, as administrative agent. Borrowings are unsecured and are not guaranteed by any of our subsidiaries. On February 3, 2026, we borrowed $1.5 billion in a single borrowing to partially fund the HG Acquisition. The Term Loan is scheduled to mature on February 3, 2029. As of June 30, 2026, we have $1.1 billion outstanding on the Term Loan. See Note 3—Transactions and Note 7—Debt to our unaudited condensed consolidated financial statements for additional information. Redemption of 2029 Notes On February 24, 2026, we redeemed the remaining $365 million principal amount of the 2029 Notes at 101.271% of the principal amount thereof, plus accrued and unpaid interest, and the 2029 Notes were fully retired on such date. See Note 7—Debt to our unaudited condensed consolidated financial statements for additional information. Commercial Paper Program On June 16, 2026, we established the Commercial Paper Program pursuant to which we may issue short-term, unsecured commercial paper notes. The Commercial Paper may be issued and redeemed from time to time, with the aggregate face or principal amount of the notes outstanding under the Commercial Paper Program at any time not to exceed $1.65 billion. Our Credit Facility will serve as a liquidity backstop for any issuances under the Commercial Paper Program, and we intend to maintain available capacity under the Credit Facility in an amount at least equal to the aggregate outstanding borrowings under the Commercial Paper Program. See Note 7—Debt to our 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. During the three and six months ended June 30, 2026, we repurchased approximately 1.1 million shares of our common stock at a total cost of $38 million through our share repurchase program. As of June 30, 2026, we have approximately $877 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. 36 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 C3+ NGLs and oil increased significantly, while benchmark prices for natural gas and ethane decreased during the three months ended June 30, 2026 as compared to the same period of 2025. Benchmark prices for natural gas and oil increased significantly, while benchmark prices for ethane decreased and C3+ NGLs remained consistent during the six months ended June 30, 2026 as compared to the same period of 2025. 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 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 June 30, ​ Six Months Ended June 30, ​ ​ ​ ​ 2025 ​ ​ 2026 ​ ​ 2025 ​ ​ 2026 ​ Henry Hub ($/Mcf) (1) ​ $ 3.44 ​ ​ 2.90 ​ $ 3.55 ​ ​ 3.97 ​ Mont Belvieu Ethane ($/Bbl) (2) ​ ​ 10.11 ​ ​ 8.96 ​ ​ 10.78 ​ ​ 9.41 ​ Mont Belvieu C3+ NGLs ($/Bbl) (3) ​ ​ 38.07 ​ ​ 45.26 ​ ​ 41.03 ​ ​ 41.07 ​ West Texas Intermediate ($/Bbl) (4) ​ ​ 63.74 ​ ​ 93.00 ​ ​ 67.58 ​ ​ 82.46 ​ (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 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 June 30, 2025 and 2026, 4% and 47%, respectively, of our production was hedged through commodity derivatives, excluding basis swaps. For the six months ended June 30, 2025 and 2026, 4% and 44%, respectively, of our production was hedged through commodity derivatives, excluding basis swaps. Assuming our 2026 production is the same as our production in 2025, approximately 54% of our total production for 2026 is hedged through commodity derivatives, excluding basis swaps. In addition, for the three and six months ended June 30, 2026, 18% and 15%, respectively, of our production was hedged with basis swap commodity derivatives. We did not have any basis swap commodity derivatives for the three and six months ended June 30, 2025. Assuming our 2026 production is the same as our production in 2025, approximately 20% of our total production for 2026 is hedged with basis swap commodity derivatives. As of June 30, 2026, the estimated fair value of our commodity derivative contracts was a net asset of $228 million. See Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements for additional information. ​ Economic Indicators The economy experienced elevated inflation levels as a result of global supply and demand imbalances, where global demand outpaced supplies beginning in 2021 and continuing through 2026. 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. Annual inflation rates have remained generally consistent at approximately 3% since 2023. 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, 37 Table of Contents including those in the Middle East 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. 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: 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 16—Reportable Segments to our unaudited condensed consolidated financial statements for additional information. Three Months Ended June 30, 2025 Compared to Three Months Ended June 30, 2026 The operating results of our reportable segments were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended June 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 ​ $ 688,753 ​ ​ — ​ ​ — ​ ​ — ​ ​ 688,753 ​ Natural gas liquids sales ​ ​ 480,757 ​ ​ — ​ ​ — ​ ​ — ​ ​ 480,757 ​ Oil sales ​ ​ 33,700 ​ ​ — ​ ​ — ​ ​ — ​ ​ 33,700 ​ Commodity derivative fair value gains ​ ​ 53,409 ​ ​ — ​ ​ — ​ ​ — ​ ​ 53,409 ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 305,472 ​ ​ (305,472) ​ ​ — ​ Marketing ​ ​ — ​ ​ 33,743 ​ ​ — ​ ​ — ​ ​ 33,743 ​ Amortization of deferred revenue, VPP ​ ​ 6,298 ​ ​ — ​ ​ — ​ ​ — ​ ​ 6,298 ​ Other revenue and income ​ ​ 833 ​ ​ — ​ ​ — ​ ​ — ​ ​ 833 ​ Total revenue ​ ​ 1,263,750 ​ ​ 33,743 ​ ​ 305,472 ​ ​ (305,472) ​ ​ 1,297,493 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 37,244 ​ ​ — ​ ​ — ​ ​ — ​ ​ 37,244 ​ Gathering and compression ​ ​ 236,830 ​ ​ — ​ ​ 25,662 ​ ​ (25,662) ​ ​ 236,830 ​ Processing ​ ​ 284,040 ​ ​ — ​ ​ — ​ ​ — ​ ​ 284,040 ​ Transportation ​ ​ 180,852 ​ ​ — ​ ​ — ​ ​ — ​ ​ 180,852 ​ Water handling ​ ​ — ​ ​ — ​ ​ 37,452 ​ ​ (37,452) ​ ​ — ​ Production and ad valorem taxes ​ ​ 34,830 ​ ​ — ​ ​ — ​ ​ — ​ ​ 34,830 ​ Marketing ​ ​ — ​ ​ 51,988 ​ ​ — ​ ​ — ​ ​ 51,988 ​ Exploration ​ ​ 648 ​ ​ — ​ ​ — ​ ​ — ​ ​ 648 ​ General and administrative (excluding equity-based compensation) ​ ​ 41,328 ​ ​ — ​ ​ 10,718 ​ ​ (10,718) ​ ​ 41,328 ​ Equity-based compensation ​ ​ 15,855 ​ ​ — ​ ​ 11,407 ​ ​ (11,407) ​ ​ 15,855 ​ Depletion, depreciation and amortization ​ ​ 187,589 ​ ​ — ​ ​ 33,364 ​ ​ (33,364) ​ ​ 187,589 ​ Impairment of property and equipment ​ ​ 6,297 ​ ​ — ​ ​ — ​ ​ — ​ ​ 6,297 ​ Accretion of asset retirement obligations ​ ​ 942 ​ ​ — ​ ​ — ​ ​ — ​ ​ 942 ​ Loss on sale of assets ​ ​ 546 ​ ​ — ​ ​ — ​ ​ — ​ ​ 546 ​ Contract termination, loss contingency, settlements and other operating expenses ​ ​ 13,621 ​ ​ — ​ ​ 425 ​ ​ (425) ​ ​ 13,621 ​ Total operating expenses ​ ​ 1,040,622 ​ ​ 51,988 ​ ​ 119,028 ​ ​ (119,028) ​ ​ 1,092,610 ​ Operating income (loss) ​ $ 223,128 ​ ​ (18,245) ​ ​ 186,444 ​ ​ (186,444) ​ ​ 204,883 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 30,563 ​ ​ — ​ ​ 30,016 ​ ​ (30,016) ​ ​ 30,563 ​ (1) Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements. 38 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended June 30, 2026 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream (1) Affiliate Total ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 688,478 ​ ​ — ​ ​ — ​ ​ — ​ ​ 688,478 ​ Natural gas liquids sales ​ ​ 587,714 ​ ​ — ​ ​ — ​ ​ — ​ ​ 587,714 ​ Oil sales ​ ​ 59,579 ​ ​ — ​ ​ — ​ ​ — ​ ​ 59,579 ​ Commodity derivative fair value gains ​ ​ 160,633 ​ ​ — ​ ​ — ​ ​ — ​ ​ 160,633 ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 327,244 ​ ​ (327,244) ​ ​ — ​ Marketing ​ ​ — ​ ​ 56,066 ​ ​ — ​ ​ — ​ ​ 56,066 ​ Amortization of deferred revenue, VPP ​ ​ 5,860 ​ ​ — ​ ​ — ​ ​ — ​ ​ 5,860 ​ Other revenue and income ​ ​ 1,512 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,512 ​ Total revenue ​ ​ 1,503,776 ​ ​ 56,066 ​ ​ 327,244 ​ ​ (327,244) ​ ​ 1,559,842 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 48,148 ​ ​ — ​ ​ — ​ ​ — ​ ​ 48,148 ​ Gathering and compression ​ ​ 270,225 ​ ​ — ​ ​ 36,533 ​ ​ (36,533) ​ ​ 270,225 ​ Processing ​ ​ 292,745 ​ ​ — ​ ​ — ​ ​ — ​ ​ 292,745 ​ Transportation ​ ​ 185,211 ​ ​ — ​ ​ — ​ ​ — ​ ​ 185,211 ​ Water handling ​ ​ — ​ ​ — ​ ​ 47,993 ​ ​ (47,993) ​ ​ — ​ Production and ad valorem taxes ​ ​ 37,535 ​ ​ — ​ ​ — ​ ​ — ​ ​ 37,535 ​ Marketing ​ ​ — ​ ​ 72,059 ​ ​ — ​ ​ — ​ ​ 72,059 ​ Exploration ​ ​ 904 ​ ​ — ​ ​ — ​ ​ — ​ ​ 904 ​ General and administrative (excluding equity-based compensation) ​ ​ 44,529 ​ ​ — ​ ​ 11,729 ​ ​ (11,729) ​ ​ 44,529 ​ Equity-based compensation ​ ​ 13,266 ​ ​ — ​ ​ 10,828 ​ ​ (10,828) ​ ​ 13,266 ​ Depletion, depreciation and amortization ​ ​ 227,254 ​ ​ — ​ ​ 37,378 ​ ​ (37,378) ​ ​ 227,254 ​ Impairment of property and equipment ​ ​ 4,455 ​ ​ — ​ ​ 133 ​ ​ (133) ​ ​ 4,455 ​ Accretion of asset retirement obligations ​ ​ 983 ​ ​ — ​ ​ — ​ ​ — ​ ​ 983 ​ Gain on sale of assets ​ ​ (14,616) ​ ​ — ​ ​ — ​ ​ — ​ ​ (14,616) ​ Contract termination, loss contingency, settlements and other operating expenses ​ ​ 1,685 ​ ​ — ​ ​ 741 ​ ​ (741) ​ ​ 1,685 ​ Total operating expenses ​ ​ 1,112,324 ​ ​ 72,059 ​ ​ 145,335 ​ ​ (145,335) ​ ​ 1,184,383 ​ Operating income (loss) ​ $ 391,452 ​ ​ (15,993) ​ ​ 181,909 ​ ​ (181,909) ​ ​ 375,459 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 29,379 ​ ​ — ​ ​ 28,525 ​ ​ (28,525) ​ ​ 29,379 ​ (1) Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements. ​ 39 Table of Contents The following table sets forth selected operating data of the exploration and production and marketing segments: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended ​ Amount of ​ ​ ​ ​ ​ June 30, ​ Increase ​ Percent ​ ​ ​ 2025 ​ 2026 ​ (Decrease) ​ Change ​ Production data (1) (2): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (Bcf) ​ ​ 203 ​ ​ 259 ​ ​ 56 ​ 28 % C2 Ethane (MBbl) ​ ​ 6,924 ​ ​ 7,896 ​ ​ 972 ​ 14 % C3+ NGLs (MBbl) ​ ​ 10,608 ​ ​ 11,023 ​ ​ 415 ​ 4 % Oil (MBbl) ​ ​ 672 ​ ​ 758 ​ ​ 86 ​ 13 % Combined (Bcfe) ​ ​ 312 ​ ​ 377 ​ ​ 65 ​ 21 % Daily combined production (MMcfe/d) ​ ​ 3,430 ​ ​ 4,144 ​ ​ 714 ​ 21 % Average prices before effects of derivative settlements (3): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 3.39 ​ ​ 2.66 ​ ​ (0.73) ​ (22) % C2 Ethane (per Bbl) (4) ​ $ 11.34 ​ ​ 12.54 ​ ​ 1.20 ​ 11 % C3+ NGLs (per Bbl) ​ $ 37.92 ​ ​ 44.33 ​ ​ 6.41 ​ 17 % Oil (per Bbl) ​ $ 50.15 ​ ​ 78.60 ​ ​ 28.45 ​ 57 % Weighted Average Combined (per Mcfe) ​ $ 3.85 ​ ​ 3.54 ​ ​ (0.31) ​ (8) % Average realized prices after effects of derivative settlements (3): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 3.36 ​ ​ 3.18 ​ ​ (0.18) ​ (5) % C2 Ethane (per Bbl) (4) ​ $ 11.34 ​ ​ 12.54 ​ ​ 1.20 ​ 11 % C3+ NGLs (per Bbl) ​ $ 37.92 ​ ​ 44.32 ​ ​ 6.40 ​ 17 % Oil (per Bbl) ​ $ 50.15 ​ ​ 78.60 ​ ​ 28.45 ​ 57 % Weighted Average Combined (per Mcfe) ​ $ 3.83 ​ ​ 3.90 ​ ​ 0.07 ​ 2 % Average costs (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 0.12 ​ ​ 0.13 ​ ​ 0.01 ​ 8 % Gathering and compression ​ $ 0.76 ​ ​ 0.72 ​ ​ (0.04) ​ (5) % Processing ​ $ 0.91 ​ ​ 0.78 ​ ​ (0.13) ​ (14) % Transportation ​ $ 0.58 ​ ​ 0.49 ​ ​ (0.09) ​ (16) % Production and ad valorem taxes ​ $ 0.11 ​ ​ 0.10 ​ ​ (0.01) ​ (9) % Marketing expense, net ​ $ 0.06 ​ ​ 0.04 ​ ​ (0.02) ​ (33) % General and administrative (excluding equity-based compensation) ​ $ 0.13 ​ ​ 0.12 ​ ​ (0.01) ​ (8) % Depletion, depreciation, amortization and accretion ​ $ 0.60 ​ ​ 0.61 ​ ​ 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 June 30, 2025 includes $0.5 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 June 30, 2025 would have been $11.27 per Bbl. 40 Table of Contents Exploration and Production Segment Natural gas sales. Revenues from sales of natural gas remained relatively consistent at $689 million and $688 million for the three months ended June 30, 2025 and 2026, respectively, primarily due to $143 million of natural gas sales revenue attributable to the HG Acquisition properties and higher natural gas production volumes between periods, partially offset by the Utica Shale Divestiture and lower natural gas commodity prices between periods. Higher natural gas production volumes accounted for an approximate $190 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). Lower commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2026 accounted for an approximate $189 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). NGLs sales. Revenues from sales of NGLs increased from $481 million for the three months ended June 30, 2025 to $588 million for the three months ended June 30, 2026, an increase of $107 million, or 22%, primarily due to an additional $38 million of NGLs revenue attributable to the HG Acquisition properties and higher NGLs commodity prices and production volumes between periods, partially offset by the Utica Shale Divestiture. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2026 accounted for an approximate $80 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 accounted for an approximate $27 million increase in year-over-year revenues (calculated as the change in year-to-year volumes times the prior year average price). Oil sales. Revenues from sales of oil increased from $34 million for the three months ended June 30, 2025 to $60 million for the three months ended June 30, 2026, an increase of $26 million, or 77%, primarily due to an additional $10 million of oil revenue attributable to the HG Acquisition properties and higher oil commodity prices between periods, partially offset by the Utica Shale Divestiture. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2026 accounted for an approximate $22 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Higher oil production volumes during the three months ended June 30, 2026 accounted for an approximate $4 million increase in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price). Commodity derivative fair value gains. Our commodity derivatives included fixed price swaps, collars, basis swaps and three-way collars, among others. 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. For the three months ended June 30, 2025 and 2026, our commodity hedges resulted in derivative fair value gains of $53 million and $161 million, respectively. For the three months ended June 30, 2025, commodity derivative fair value gains included $6 million of net cash payments for settled commodity derivative losses. For the three months ended June 30, 2026, commodity derivative fair value gains included $134 million of net cash proceeds for settled derivative gains. Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled 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 remained consistent at $6 million for the three months ended June 30, 2025 and 2026. 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 per Mcfe increased 8% from $0.12 per Mcfe for the three months ended June 30, 2025 to $0.13 per Mcfe for the three months ended June 30, 2026 primarily due to higher wastewater trucking and disposal costs due to the timing of well completions activity between periods. Lease operating expense increased from $37 million for the three months ended June 30, 2025 to $48 million for the three months ended June 30, 2026, an increase of $11 million, or 29%, primarily due to incremental expense of $8 million related to the HG Acquisition properties and higher wastewater trucking and disposal costs due to the timing of well completions activity between periods, partially offset by the Utica Shale Divestiture. 41 Table of Contents Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense per Mcfe decreased 12% from $2.25 per Mcfe for the three months ended June 30, 2025 to $1.99 per Mcfe, for the three months ended June 30, 2026 primarily due to the HG Acquisition properties that have a lower compression, processing and transportation costs. Gathering, compression, processing and transportation expense increased from $702 million for the three months ended June 30, 2025 to $748 million for the three months ended June 30, 2026, an increase of $46 million, or 7%, primarily due to incremental expense of $70 million related to the HG Acquisition properties and higher production volumes between periods, partially offset the Utica Shale Divestiture. The fluctuation of our gathering, compression, processing and transportation expense on a per unit basis was primarily a result of the following: ● Gathering and compression costs decreased from $0.76 per Mcfe for the three months ended June 30, 2025 to $0.72 per Mcfe for the three months ended June 30, 2026, primarily due to lower gathering and compression expense on a per unit basis for the HG Acquisition properties and decreased fuel costs as a result of lower natural gas prices, partially offset by annual CPI-based adjustments between periods. ● Processing costs decreased from $0.91 per Mcfe for the three months ended June 30, 2025 to $0.78 per Mcfe for the three months ended June 30, 2026, primarily due to lower NGLs transportation fees related to the HG Acquisition properties between periods. ● Transportation costs decreased from $0.58 per Mcfe for the three months ended June 30, 2025 to $0.49 per Mcfe for the three months ended June 30, 2026, primarily due to lower fuel costs as a result of lower natural gas prices between periods and lower demand fees for certain pipelines during the three months ended June 30, 2026. Production and ad valorem tax expense. Production and ad valorem taxes as a percentage of natural gas revenues remained consistent at 5% for the three months ended June 30, 2025 and 2026. Production and ad valorem taxes increased from $35 million for the three months ended June 30, 2025 to $38 million for the three months ended June 30, 2026, an increase of $3 million, or 8%, primarily due to incremental expense of $6 million related to the HG Acquisition properties and higher production volumes between periods, partially offset by the Utica Shale Divestiture and lower natural gas prices during the three months ended June 30, 2026. General and administrative expense. General and administrative expense (excluding equity-based compensation expense) per Mcfe decreased 8% from $0.13 per Mcfe for the three months ended June 30, 2025 to $0.12 per Mcfe for the three months ended June 30, 2026 primarily due to higher production volumes from our HG Acquisition, partially offset by higher overall general and administrative costs between periods. General and administrative expense (excluding equity-based compensation expense) increased from $41 million for the three months ended June 30, 2025 to $45 million for the three months ended June 30, 2026, an increase of $4 million, or 8%, primarily due to higher salary and wage expense, software license costs and professional service fees between periods. Equity-based compensation expense. Non-cash equity-based compensation expense decreased from $16 million for the three months ended June 30, 2025 to $13 million for the three months ended June 30, 2026, a decrease of $3 million or 16%. This decrease was primarily due to lower RSU and PSU award expense of $2 million and $1 million, respectively, between periods. 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 per Mcfe remained relatively consistent at $0.60 per Mcfe and $0.61 per Mcfe for the three months ended June 30, 2025 and 2026, respectively. DD&A expense increased from $188 million for the three months ended June 30, 2025 to $227 million for the three months ended June 30, 2026, an increase of $39 million, or 21%, primarily due to higher production volumes between periods related to our HG Acquisition properties, partially offset by the Utica Shale Divestiture. Impairment of property and equipment. Impairment of oil and gas properties decreased from $6 million for the three months ended June 30, 2025 to $4 million for the three months ended June 30, 2026, 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 place into service. Contract termination, loss contingency and settlements. Contract termination, loss contingency and settlements decreased from $14 million for the three months ended June 30, 2025 to $2 million for the three months ended June 30, 2026, a decrease of $12 million. This decrease was primarily due to lower loss contingencies recorded. See Note 14—Contingencies to the unaudited condensed consolidated financial statements for additional information. 42 Table of Contents Loss (gain) on sale of assets. Loss on sale of assets was less than $1 million for the three months ended June 30, 2025. Gain on sale of assets was $15 million for the three months ended June 30, 2026 primarily due to the release of certain proceeds from the Utica Shale Divestiture that were held in escrow at closing. See Note 3—Transactions 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 decreased from $0.06 per Mcfe, or $18 million, for the three months ended June 30, 2025 to $0.04 per Mcfe, or $16 million, for the three months ended June 30, 2026, primarily due to higher pipeline utilization and lower fuel costs between periods, partially offset by higher demand fees on certain pipelines. Marketing revenue. Marketing revenue increased from $34 million for the three months ended June 30, 2025 to $56 million for the three months ended June 30, 2026, an increase of $22 million, or 66%. This fluctuation primarily resulted from the following: ● Natural gas marketing revenue decreased by $5 million between periods primarily due to lower natural gas marketing volumes. ● Oil marketing revenue increased by $28 million between periods primarily due to higher oil prices and marketing volumes. Higher oil prices accounted for a $17 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes), and higher oil marketing volumes accounted for an $11 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price). ● NGLs marketing revenues increased by $3 million for the three months ended June 30, 2026 primarily due to higher C3+ NGLs marketing volumes. Marketing expense. Marketing expense increased from $52 million for the three months ended June 30, 2025 to $72 million for the three months ended June 30, 2026, an increase of $20 million, or 39%. 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 purchases increased $23 million between periods primarily due to higher oil marketing prices and volumes during the three months ended June 30, 2026, partially offset by lower natural gas marketing volumes during the three months ended June 30, 2026. Firm transportation costs decreased $3 million between periods primarily due to higher pipeline utilization between periods and lower fuel costs during the three months ended June 30, 2026. Antero Midstream Segment Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $305 million for the three months ended June 30, 2025 to $327 million for the three months ended June 30, 2026, an increase of $22 million. This increase is primarily due to higher gathering and processing revenues of $18 million and higher water handling revenues of $4 million. The increased gathering and processing revenues between periods is primarily due to higher low pressure gathering and compression volumes from the HG Acquisition and 80 wells connected to their system between periods and increased gathering and centralized compression rates as a result of annual CPI-based adjustments, partially offset by the Utica Shale Divestiture and natural production decline of the wells connected to their system between periods. The increased water handling revenues between periods is primarily due to fresh water delivery volumes for our acreage acquired in the HG Acquisition that are charged at cost plus 3% during the three months ended June 30, 2026, as well as higher blending cost of service fees, increased costs for wastewater trucking and disposal volumes and an increase to the fresh water delivery rate as a result of an annual CPI-based rate adjustment between periods. 43 Table of Contents Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $119 million for the three months ended June 30, 2025 to $145 million for the three months ended June 30, 2026, an increase of $26 million. This increase is primarily due to higher direct operating expenses as a result of gathering and well pad compression costs related to assets acquired with the HG Acquisition during the three months ended June 30, 2026, as well as increased fresh water delivery services on our acreage acquired in the HG Acquisition during the three month ended June 30, 2026, increased wastewater trucking and disposal volumes between periods and increased blending volumes and costs between periods, partially offset by the Utica Shale Divestiture. Items Not Allocated to Segments Interest expense. Interest expense increased from $20 million for the three months ended June 30, 2025 to $38 million for the three months ended June 30, 2026, an increase of $18 million, or 88%, primarily due to borrowings to fund our HG Acquisition under the Term Loan and issuance of the 2036 Notes during the first quarter of 2026, partially offset by the redemption of the 2029 Notes on February 24, 2026 and lower Credit Facility borrowings and rates between periods. See Note 7—Debt to the unaudited condensed consolidated financial statements for more information. Loss on early extinguishment of debt. During the three months ended June 30, 2025, we repurchased $23 million aggregate principal amount of our 2029 Notes through open market transactions at a weighted average premium of approximately 102% of the principal amount thereof, plus accrued and unpaid interest, and recognized a loss on early debt extinguishment of $1 million. There was no loss on early extinguishment of debt for the three months ended June 30, 2026. See Note 7—Debt to the unaudited condensed consolidated financial statements for more information. Income tax expense. Income tax expense increased from $48 million, with an effective tax rate of 22%, for the three months ended June 30, 2025 to $79 million, with an effective tax rate of 22%, for the three months ended June 30, 2026 primarily due to the increase in income before income taxes between periods. ​ 44 Table of Contents Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2026 The operating results of our reportable segments were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Six Months Ended June 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 ​ $ 1,468,758 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,468,758 ​ Natural gas liquids sales ​ ​ 1,042,189 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,042,189 ​ Oil sales ​ ​ 84,035 ​ ​ — ​ ​ — ​ ​ — ​ ​ 84,035 ​ Commodity derivative fair value losses ​ ​ (18,262) ​ ​ — ​ ​ — ​ ​ — ​ ​ (18,262) ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 596,601 ​ ​ (596,601) ​ ​ — ​ Marketing ​ ​ — ​ ​ 59,301 ​ ​ — ​ ​ — ​ ​ 59,301 ​ Amortization of deferred revenue, VPP ​ ​ 12,528 ​ ​ — ​ ​ — ​ ​ — ​ ​ 12,528 ​ Other revenue and income ​ ​ 1,651 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,651 ​ Total revenue ​ ​ 2,590,899 ​ ​ 59,301 ​ ​ 596,601 ​ ​ (596,601) ​ ​ 2,650,200 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 71,230 ​ ​ — ​ ​ — ​ ​ — ​ ​ 71,230 ​ Gathering and compression ​ ​ 472,964 ​ ​ — ​ ​ 51,855 ​ ​ (51,855) ​ ​ 472,964 ​ Processing ​ ​ 545,195 ​ ​ — ​ ​ — ​ ​ — ​ ​ 545,195 ​ Transportation ​ ​ 378,580 ​ ​ — ​ ​ — ​ ​ — ​ ​ 378,580 ​ Water handling ​ ​ — ​ ​ — ​ ​ 68,089 ​ ​ (68,089) ​ ​ — ​ Production and ad valorem taxes ​ ​ 90,129 ​ ​ — ​ ​ — ​ ​ — ​ ​ 90,129 ​ Marketing ​ ​ — ​ ​ 94,758 ​ ​ — ​ ​ — ​ ​ 94,758 ​ Exploration ​ ​ 1,316 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,316 ​ General and administrative (excluding equity-based compensation) ​ ​ 88,628 ​ ​ — ​ ​ 21,340 ​ ​ (21,340) ​ ​ 88,628 ​ Equity-based compensation ​ ​ 31,000 ​ ​ — ​ ​ 23,809 ​ ​ (23,809) ​ ​ 31,000 ​ Depletion, depreciation and amortization ​ ​ 373,941 ​ ​ — ​ ​ 66,112 ​ ​ (66,112) ​ ​ 373,941 ​ Impairment of property and equipment ​ ​ 11,915 ​ ​ — ​ ​ 817 ​ ​ (817) ​ ​ 11,915 ​ Accretion of asset retirement obligations ​ ​ 1,881 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,881 ​ Gain on sale of assets ​ ​ (29) ​ ​ — ​ ​ — ​ ​ — ​ ​ (29) ​ Contract termination, loss contingency, settlements and other operating expenses ​ ​ 12,337 ​ ​ — ​ ​ 912 ​ ​ (912) ​ ​ 12,337 ​ Total operating expenses ​ ​ 2,079,087 ​ ​ 94,758 ​ ​ 232,934 ​ ​ (232,934) ​ ​ 2,173,845 ​ Operating income (loss) ​ $ 511,812 ​ ​ (35,457) ​ ​ 363,667 ​ ​ (363,667) ​ ​ 476,355 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 59,224 ​ ​ — ​ ​ 58,036 ​ ​ (58,036) ​ ​ 59,224 ​ (1) Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements. 45 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Six Months Ended June 30, 2026 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream (1) Affiliate Total Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 1,999,954 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,999,954 ​ Natural gas liquids sales ​ ​ 1,091,363 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,091,363 ​ Oil sales ​ ​ 106,274 ​ ​ — ​ ​ — ​ ​ — ​ ​ 106,274 ​ Commodity derivative fair value gains ​ ​ 195,656 ​ ​ — ​ ​ — ​ ​ — ​ ​ 195,656 ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 641,455 ​ ​ (641,455) ​ ​ — ​ Marketing ​ ​ — ​ ​ 97,727 ​ ​ — ​ ​ — ​ ​ 97,727 ​ Amortization of deferred revenue, VPP ​ ​ 11,655 ​ ​ — ​ ​ — ​ ​ — ​ ​ 11,655 ​ Other revenue and income ​ ​ 2,339 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,339 ​ Total revenue ​ ​ 3,407,241 ​ ​ 97,727 ​ ​ 641,455 ​ ​ (641,455) ​ ​ 3,504,968 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 92,677 ​ ​ — ​ ​ — ​ ​ — ​ ​ 92,677 ​ Gathering and compression ​ ​ 539,338 ​ ​ — ​ ​ 66,563 ​ ​ (66,563) ​ ​ 539,338 ​ Processing ​ ​ 580,513 ​ ​ — ​ ​ — ​ ​ — ​ ​ 580,513 ​ Transportation ​ ​ 417,436 ​ ​ — ​ ​ — ​ ​ — ​ ​ 417,436 ​ Water handling ​ ​ — ​ ​ — ​ ​ 88,660 ​ ​ (88,660) ​ ​ — ​ Production and ad valorem taxes ​ ​ 118,532 ​ ​ — ​ ​ — ​ ​ — ​ ​ 118,532 ​ Marketing ​ ​ — ​ ​ 134,612 ​ ​ — ​ ​ — ​ ​ 134,612 ​ Exploration ​ ​ 1,696 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,696 ​ General and administrative (excluding equity-based compensation) ​ ​ 96,136 ​ ​ — ​ ​ 23,497 ​ ​ (23,497) ​ ​ 96,136 ​ Equity-based compensation ​ ​ 24,999 ​ ​ — ​ ​ 21,407 ​ ​ (21,407) ​ ​ 24,999 ​ Depletion, depreciation and amortization ​ ​ 433,493 ​ ​ — ​ ​ 72,013 ​ ​ (72,013) ​ ​ 433,493 ​ Impairment of property and equipment ​ ​ 5,403 ​ ​ — ​ ​ 133 ​ ​ (133) ​ ​ 5,403 ​ Accretion of asset retirement obligations ​ ​ 2,046 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,046 ​ Gain on sale of assets ​ ​ (60,566) ​ ​ — ​ ​ (2,658) ​ ​ 2,658 ​ ​ (60,566) ​ Contract termination, loss contingency, settlements and other operating expenses ​ ​ 13,742 ​ ​ — ​ ​ 1,320 ​ ​ (1,320) ​ ​ 13,742 ​ Total operating expenses ​ ​ 2,265,445 ​ ​ 134,612 ​ ​ 270,935 ​ ​ (270,935) ​ ​ 2,400,057 ​ Operating income (loss) ​ $ 1,141,796 ​ ​ (36,885) ​ ​ 370,520 ​ ​ (370,520) ​ ​ 1,104,911 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 59,497 ​ ​ — ​ ​ 58,537 ​ ​ (58,537) ​ ​ 59,497 ​ (1) Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements. 46 Table of Contents The following table sets forth selected operating data of the exploration and production and marketing segments: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Six Months Ended ​ Amount of ​ ​ ​ ​ ​ ​ June 30, ​ Increase ​ Percent ​ ​ ​ ​ ​ 2025 ​ ​ 2026 ​ ​ (Decrease) ​ ​ Change ​ ​ Production data (1) (2): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (Bcf) ​ ​ 398 ​ ​ 495 ​ ​ 97 ​ 24 % ​ C2 Ethane (MBbl) ​ ​ 14,366 ​ ​ 14,732 ​ ​ 366 ​ 3 % ​ C3+ NGLs (MBbl) ​ ​ 20,837 ​ ​ 21,895 ​ ​ 1,058 ​ 5 % ​ Oil (MBbl) ​ ​ 1,524 ​ ​ 1,574 ​ ​ 50 ​ 3 % ​ Combined (Bcfe) ​ ​ 618 ​ ​ 724 ​ ​ 106 ​ 17 % ​ Daily combined production (MMcfe/d) ​ ​ 3,414 ​ ​ 3,999 ​ ​ 585 ​ 17 % ​ Average prices before effects of derivative settlements (3): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 3.69 ​ ​ 4.04 ​ ​ 0.35 ​ 9 % ​ C2 Ethane (per Bbl) (4) ​ $ 12.04 ​ ​ 12.99 ​ ​ 0.95 ​ 8 % ​ C3+ NGLs (per Bbl) ​ $ 41.71 ​ ​ 41.10 ​ ​ (0.61) ​ (1) % ​ Oil (per Bbl) ​ $ 55.14 ​ ​ 67.52 ​ ​ 12.38 ​ 22 % ​ Weighted Average Combined (per Mcfe) ​ $ 4.20 ​ ​ 4.42 ​ ​ 0.22 ​ 5 % ​ Average realized prices after effects of derivative settlements (3): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 3.65 ​ ​ 3.98 ​ ​ 0.33 ​ 9 % ​ C2 Ethane (per Bbl) (4) ​ $ 12.04 ​ ​ 12.99 ​ ​ 0.95 ​ 8 % ​ C3+ NGLs (per Bbl) ​ $ 41.71 ​ ​ 41.13 ​ ​ (0.58) ​ (1) % ​ Oil (per Bbl) ​ $ 55.08 ​ ​ 67.52 ​ ​ 12.44 ​ 23 % ​ Weighted Average Combined (per Mcfe) ​ $ 4.17 ​ ​ 4.38 ​ ​ 0.21 ​ 5 % ​ Average costs (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 0.12 ​ ​ 0.13 ​ ​ 0.01 ​ 8 % ​ Gathering and compression ​ $ 0.77 ​ ​ 0.75 ​ ​ (0.02) ​ (3) % ​ Processing ​ $ 0.88 ​ ​ 0.80 ​ ​ (0.08) ​ (9) % ​ Transportation ​ $ 0.61 ​ ​ 0.58 ​ ​ (0.03) ​ (5) % ​ Production and ad valorem taxes ​ $ 0.15 ​ ​ 0.16 ​ ​ 0.01 ​ 7 % ​ Marketing expense, net ​ $ 0.06 ​ ​ 0.05 ​ ​ (0.01) ​ (17) % ​ General and administrative (excluding equity-based compensation) ​ $ 0.14 ​ ​ 0.13 ​ ​ (0.01) ​ (7) % ​ 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 or 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 six months ended June 30, 2025 includes $0.5 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 six months ended June 30, 2025 would have been $12.01 per Bbl. ​ ​ 47 Table of Contents Exploration and Production Segment Natural gas sales. Revenues from sales of natural gas increased from $1.5 billion for the six months ended June 30, 2025 to $2.0 billion for the six months ended June 30, 2026, an increase of $0.5 billion, or 36%, primarily due to an additional $321 million of natural gas revenue attributable to the HG Acquisition properties and higher natural gas production volumes and commodity prices between periods, partially offset by the Utica Shale Divestiture. Higher natural gas production volumes accounted for an approximate $358 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). Higher commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, 2026 accounted for an approximate $173 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). NGLs sales. Revenues from sales of NGLs increased from $1.0 billion for the six months ended June 30, 2025 to $1.1 billion for the six months ended June 30, 2026, an increase of $0.1 billion, or 5%, primarily due to an additional $54 million of NGLs revenue attributable to the HG Acquisition properties, higher NGLs production volumes and higher ethane commodity prices between periods, partially offset by the Utica Shale Divestiture and lower C3+ NGLs commodity prices during the six months ended June 30, 2026. Higher NGLs production volumes during the six months ended June 30, 2026 accounted for an approximate $49 million increase 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 six months ended June 30, 2026 accounted for an approximate $14 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower C3+ NGLs commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, 2026 accounted for an approximate $13 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Oil sales. Revenues from sales of oil increased from $84 million for the six months ended June 30, 2025 to $106 million for the six months ended June 30, 2026, an increase of $22 million, or 26%, primarily due to an additional $12 million of oil revenue attributable to the HG Acquisition properties and higher oil prices between periods, partially offset by the Utica Shale Divestiture. Higher oil prices (excluding the effects of derivative settlements) accounted for an approximate $19 million increase in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes). Higher oil production volumes accounted for an approximate $3 million increase in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price). Commodity derivative fair value gains (losses). Our commodity derivatives included fixed price swaps, collars, basis swaps and three-way collars, among others. 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. For the six months ended June 30, 2025 and 2026, our commodity hedges resulted in derivative fair value losses of $18 million and fair value gains of $196 million, respectively. For the six months ended June 30, 2025, commodity derivative fair value losses included $17 million of net cash payments for settled derivative losses. For the six months ended June 30, 2026, commodity derivative fair value gains included $31 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 $13 million and $12 million for the six months ended June 30, 2025 and 2026, 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 per Mcfe increased 8% from $0.12 per Mcfe for the six months ended June 30, 2025 to $0.13 per Mcfe for the six months ended June 30, 2026 primarily due to higher wastewater trucking and disposal costs due to the timing of well completions activity between periods. Lease operating expense increased from $71 million for the six months ended June 30, 2025 to $93 million for the six months ended June 30, 2026, an increase of $22 million, or 30%, primarily due to incremental expense of $14 million related to the HG Acquisition properties and higher wastewater trucking and disposal costs due to the timing of well completions activity between periods, partially offset by the Utica Shale Divestiture. 48 Table of Contents Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense per Mcfe decreased 6% from $2.26 per Mcfe for the six months ended June 30, 2025 to $2.13 per Mcfe for the six months ended June 30, 2026 primarily due to the HG Acquisition properties that have a lower compression, processing and transportation costs. Gathering, compression, processing and transportation expense increased from $1.4 billion for the six months ended June 30, 2025 to $1.5 billion for the six months ended June 30, 2026, an increase of $0.1 billion, or 10%, primarily due to incremental expense of $109 million related to the HG Acquisition properties and higher production volumes between periods, partially offset the Utica Shale Divestiture. The fluctuation of our gathering, compression, processing and transportation expense on a per unit basis was primarily a result of the following: ● Gathering and compression costs on a per unit basis decreased from $0.77 per Mcfe for the six months ended June 30, 2025 to $0.75 per Mcfe for the six months ended June 30, 2026, primarily due to lower gathering and compression expense on a per unit basis for the HG Acquisition properties, partially offset by 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 decreased from $0.88 per Mcfe for the six months ended June 30, 2025 to $0.80 per Mcfe for the six months ended June 30, 2026, primarily due to lower NGLs transportation fees related to the HG Acquisition properties between periods. ● Transportation costs on a per unit basis decreased from $0.61 per Mcfe for the six months ended June 30, 2025 to $0.58 per Mcfe for the six months ended June 30, 2026, primarily due to lower transportation expense on a per unit basis for the HG Acquisition properties, partially offset by increased fuel costs as a result of higher natural gas prices between periods. Production and ad valorem tax expense. Production and ad valorem taxes as a percentage of natural gas revenues remained consistent at 6% for each of the six months ended June 30, 2025 and 2026. Production and ad valorem taxes increased from $90 million for the six months ended June 30, 2025 to $119 million for the six months ended June 30, 2026, an increase of $29 million, or 32%, primarily due to higher natural gas prices between periods and incremental expense of $15 million related to the HG Acquisition properties, partially offset by the Utica Shale Divestiture. General and administrative expense. General and administrative expense (excluding equity-based compensation) per Mcfe decreased 7% from $0.14 per Mcfe for the six months ended June 30, 2025 to $0.13 per Mcfe for the six months ended June 30, 2026 primarily due to increased production volumes related to our HG Acquisition, partially offset by higher overall general and administrative costs between periods. General and administrative expense (excluding equity-based compensation expense) increased from $89 million for the six months ended June 30, 2025 to $96 million for the six months ended June 30, 2026, an increase of $7 million, or 8%, primarily due to higher salary and wage expense, software license costs and professional service fees between periods. Equity-based compensation expense. Non-cash equity-based compensation expense decreased from $31 million for the six months ended June 30, 2025 to $25 million for the six months ended June 30, 2026, a decrease of $6 million or 19%. This decrease was primarily due to lower RSU and PSU award expense of $5 million and $1 million, respectively, between periods. See Note 9—Equity-Based Compensation to the unaudited condensed consolidated financial statements for additional information. Depletion, depreciation and amortization expense. DD&A expense per Mcfe remained relatively consistent at $0.61 per Mcfe and $0.60 per Mcfe for the six months ended June 30, 2025 and 2026, respectively. DD&A expense increased from $374 million for the six months ended June 30, 2025 to $433 million for the six months ended June 30, 2026, an increase of $59 million, or 16%, primarily due to higher production volumes between periods related to our HG Acquisition properties, partially offset by the Utica Shale Divestiture. Impairment of property and equipment. Impairment of oil and gas properties decreased from $12 million for the six months ended June 30, 2025 to $5 million for the six months ended June 30, 2026, 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. Contract termination, loss contingency and settlements. Contract termination, loss contingency, settlements and other operating expenses increased from $12 million for the six months ended June 30, 2025 to $14 million for the six months ended June 30, 2026, an increase of $2 million. This increase was primarily due to contract termination expense related to certain HG Acquisition contracts during the six months ended June 30, 2026. See Note 14—Contingencies to the unaudited condensed consolidated financial statements for additional information. 49 Table of Contents Gain on sale of assets. Gain on sale of assets was less than $1 million for the six months ended June 30, 2025. Gain on sale of assets was $61 million for the six months ended June 30, 2026 primarily due to the Utica Shale Divestiture that closed on February 23, 2026. See Note 3—Transactions 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 decreased from $0.06 per Mcfe for the six months ended June 30, 2025 to $0.05 per Mcfe for the six months ended June 30, 2026, primarily due higher production volumes from our HG Acquisition, partially offset by higher net marketing expense between periods. Net marketing expense increased from $35 million for the six months ended June 30, 2025 to $37 million for the six months ended June 30, 2026 primarily due to higher demand fees on certain pipelines and lower pipeline utilization due to maintenance between periods. Marketing revenue. Marketing revenue increased from $59 million for the six months ended June 30, 2025 to $98 million for the six months ended June 30, 2026, an increase of $39 million, or 65%. This fluctuation primarily resulted from the following: ● Natural gas marketing revenue decreased by $5 million between periods primarily due to lower natural gas marketing volumes. ● Oil marketing revenue increased by $42 million between periods primarily due to higher oil marketing volumes and prices. Higher oil marketing volumes accounted for a $23 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher oil prices accounted for a $19 million increase 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 $4 million between periods primarily due to higher ethane marketing volumes and prices for the six months ended June 30, 2026. Marketing expense. Marketing expense increased from $95 million for the six months ended June 30, 2025 to $135 million for the six months ended June 30, 2026, an increase of $40 million, or 42%. 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 purchases increased $34 million between periods primarily due to higher oil marketing prices and volumes during the six months ended June 30, 2026, partially offset by lower natural gas marketing volumes during the six months ended June 30, 2026. Firm transportation costs increased $7 million between periods primarily due to lower pipeline utilization as a result of higher pricing in the Appalachian Basin and a pipeline force majeure during the six months ended June 30, 2026. Antero Midstream Segment Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $597 million for the six months ended June 30, 2025 to $641 million for the six months ended June 30, 2026, an increase of $44 million. This increase is primarily due to higher gathering and processing revenues of $39 million and higher water handling revenues of $5 million. The increased gathering and processing revenues between periods is primarily due to higher low pressure gathering and compression volumes from the HG Acquisition and 80 wells connected to their system between periods and increased gathering and centralized compression rates as a result of annual CPI-based adjustments, partially offset by the Utica Shale Divestiture and natural production decline of wells connected to their system between periods. The increased water handling revenues between periods is primarily due to fresh water delivery volumes for our acreage acquired in the HG Acquisition that are charged at cost plus 3% during the six months ended June 30, 2026, higher blending cost of service fees, increased wastewater trucking and disposal volumes and costs and a higher fresh water delivery fee as a result of an annual CPI-based adjustment, partially offset by decreased fresh water delivery volumes between periods due to the timing and location of our completions activity. 50 Table of Contents Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $233 million for the six months ended June 30, 2025 to $271 million for the six months ended June 30, 2026, an increase of $38 million. This increase is primarily due to higher direct operating expenses as a result of increased gathering and well pad compression costs between periods related to assets acquired with the HG Acquisition, fresh water delivery services on our acreage acquired in the HG Acquisition and increased wastewater trucking and disposal volumes and higher blending costs between periods, partially offset by the Utica Shale Divestiture. Items Not Allocated to Segments Interest expense, net. Interest expense, net increased from $43 million for the six months ended June 30, 2025 to $74 million for the six months ended June 30, 2026, an increase of $31 million or 72%, primarily due to borrowings to fund our HG Acquisition under the Term Loan and issuance of the 2036 Notes during the first quarter of 2026, partially offset by the redemption of the 2029 Notes on February 24, 2026 and lower Credit Facility borrowings and rates between periods. See Note 7—Debt to our unaudited condensed consolidated financial statements for more information. Loss on early extinguishment of debt. During the six months ended June 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. During the six months ended June 30, 2026, we recognized a loss on early debt extinguishment of $7 million related to the redemption of the remaining $365 million principal amount of our 2029 Notes at 101.271% of the principal amount thereof, plus accrued and unpaid interest. See Note 7—Debt to our unaudited condensed consolidated financial statements for more information. Transaction expense. There were no transaction expenses incurred during the six months ended June 30, 2025. During the six months ended June 30, 2026, we incurred $24 million of transaction expense related to the HG Acquisition. See Note 3—Transactions to our unaudited condensed consolidated financial statements for more information. Income tax expense. Income tax expense increased from $103 million, with an effective tax rate of 21%, for the six months ended June 30, 2025 to $225 million, with an effective tax rate of 21%, for the six months ended June 30, 2026 primarily due to the increase in income before income taxes between periods. 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 and Term Loan, issuances of debt and equity securities, including issuances of notes under our Commercial Paper Program, 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. Based on strip prices as of June 30, 2026, we believe that net cash provided by operating activities, issuances of notes under our Commercial Paper Program 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): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Six Months Ended June 30, ​ ​ ​ 2025 ​ 2026 ​ Net cash provided by operating activities ​ $ 950,097 ​ ​ 1,297,907 ​ Net cash used in investing activities ​ ​ (405,380) ​ ​ (2,624,723) ​ Net cash provided by (used in) financing activities ​ ​ (544,717) ​ ​ 1,116,816 ​ Net decrease in cash, cash equivalents and restricted cash ​ $ — ​ ​ (210,000) ​ 51 Table of Contents Operating activities. Net cash provided by operating activities was $950 million and $1.3 billion for the six months ended June 30, 2025 and 2026, respectively. Net cash provided by operating activities increased between periods primarily due to higher natural gas, NGLs and oil revenues for our HG Acquisition properties, lower lease operating, gathering, compression, processing, transportation, production and ad valorem taxes for the Utica Shale Divestiture and changes in working capital, partially offset by higher lease operating, gathering, compression, processing, transportation and production and ad valorem taxes for our HG Acquisition properties, lower natural gas, NGLs and oil revenues for the Utica Shale Divestiture and higher marketing and interest expense during the six months ended June 30, 2026. 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 $405 million for the six months ended June 30, 2025 to $2.6 billion for the six months ended June 30, 2026, primarily due to cash paid for our HG Acquisition of $2.8 billion during the six months ended June 30, 2026, increased drilling and completions activity of $136 million between periods and acquisitions of oil and gas properties during the six months ended June 30, 2026 of $8 million, partially offset by proceeds from the Utica Shale Divestiture of $757 million during the six months ended June 30, 2026 and decreased oil and gas leasing activity of $11 million between periods. Financing activities. Net cash used in financing activities was $545 million for the six months ended June 30, 2025. Net cash provided by financing activities was $1.1 billion for the six months ended June 30, 2026. The increase in net cash provided by financing activities between periods is primarily due to borrowings to fund our HG Acquisition on the Term Loan of $1.5 billion, the issuance of our 2036 Notes of $750 million and net borrowings on our Commercial Paper Program of $182 million during the six months ended June 30, 2026, partially offset by higher net repayments on our Credit Facility of $183 million between periods, repayments on the Term Loan of $400 million during the six months ended June 30, 2026, higher repayments and redemptions of our senior notes of $228 million between periods and increased payments of employee tax withholdings for the settlement of equity-based compensation awards of $8 million between periods. 2026 Capital Budget, Capital Spending and Acquisitions On February 11, 2026, we announced 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 the Closing Date and the closing of the Utica Shale Divestiture on February 23, 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, leasehold acquisition opportunities and commodity prices. For the three months ended June 30, 2026, our total consolidated capital expenditures were $332 million, including drilling and completion costs of $297 million, leasehold acquisitions of $29 million, and other capital expenditures of $6 million. For the six months ended June 30, 2026, our total consolidated capital expenditures were $584 million, including drilling and completion costs of $518 million, leasehold acquisitions of $54 million, and other capital expenditures of $12 million. Debt Agreements See Note 7—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 2025 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 52 Table of Contents 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 2025 Form 10-K for information on our critical accounting estimates. Business Combinations We recognize and measure the assets acquired and liabilities assumed in a business combination based on their estimated fair values at the acquisition date, with any remaining difference recorded as goodwill. For acquisitions, management engages an independent valuation specialist to assist with the determination of fair value of the assets acquired, liabilities assumed, and goodwill, based on recognized valuation methodologies, including but not limited to income and cost approaches as circumstances warrant. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later than one year from the Closing Date, we will record any material adjustments to the initial estimate based on new information obtained that would have existed as of the Closing Date. An adjustment that arises from information obtained that did not exist as of the date of the acquisition will be recorded in the period of the adjustment. The valuation of the assets acquired and liabilities assumed in a business combination requires significant judgement about commodity prices, projected reserve quantities, estimated future rates of production, projected reserve recovery factors, development plans (including timing and amount of development), future development costs, operating costs, among others, and such fair value approaches may rely on significant inputs that are not observable in the market. These assumptions affect the fair value of assets acquired and liabilities assumed and, if changed, could have a material effect on the Company’s financial position or results of operations. See Note 3—Transactions and Note 10—Fair Value Measurement to our unaudited condensed consolidated financial statements for more information. 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 June 30, 2026, 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 six months ended June 30, 2025 and 2026. 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 our unaudited condensed consolidated financial statements for information on new accounting pronouncements. Off-Balance Sheet Arrangements See Note 13—Commitments to our unaudited condensed consolidated financial statements for information on off balance sheet arrangements. 53 Table of Contents