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 March 31, 2026, we held approximately 855,000 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 February 3, 2026. 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 three months ended March 31, 2026 included results of operations from the assets and operations acquired in the HG Acquisition from February 3, 2026 through March 31, 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 on-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. 32 Table of Contents 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—Long-Term 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. See Note 3—Transactions and Note 7—Long-Term Debt to our unaudited condensed consolidated financial statements for additional information. Redemption of 2029 Notes During the three months ended March 31, 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—Long-Term Debt to our unaudited condensed consolidated financial statements for additional information. 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 increased significantly, while benchmark prices for ethane and C3+ NGLs decreased and benchmark prices for oil remained relatively consistent during the three months ended March 31, 2026 as compared to the same period of 2025. As a result of the higher benchmark natural gas prices during the three months ended March 31, 2026, we experienced an increase in price realization for natural gas products, partially offset by the effects of decreased benchmark ethane and C3+ NGLs prices as compared to the three months ended March 31, 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 March 31, ​ ​ ​ ​ 2025 ​ ​ 2026 ​ Henry Hub ($/Mcf) (1) ​ $ 3.65 ​ ​ 5.04 ​ Mont Belvieu Ethane ($/Bbl) (2) ​ ​ 11.46 ​ ​ 9.87 ​ Mont Belvieu C3+ NGLs ($/Bbl) (3) ​ ​ 43.99 ​ ​ 36.89 ​ West Texas Intermediate ($/Bbl) (4) ​ ​ 71.42 ​ ​ 71.93 ​ (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. 33 Table of Contents 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 March 31, 2025 and 2026, 4% and 42%, 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 months ended March 31, 2025 and 2026, zero and 12%, respectively, of our production was hedged with basis swap commodity derivatives. 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 March 31, 2026, the estimated fair value of our commodity derivative contracts was a net asset of $202 million. See Note 11—Derivative Instruments to our 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 March 31, 2026, Martica had no derivative instruments. 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, 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. ​ 34 Table of Contents Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2026 The operating results of our reportable segments were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended March 31, 2025 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream (1) Affiliate Total Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 780,005 ​ ​ — ​ ​ — ​ ​ — ​ ​ 780,005 ​ Natural gas liquids sales ​ ​ 561,432 ​ ​ — ​ ​ — ​ ​ — ​ ​ 561,432 ​ Oil sales ​ ​ 50,335 ​ ​ — ​ ​ — ​ ​ — ​ ​ 50,335 ​ Commodity derivative fair value losses ​ ​ (71,671) ​ ​ — ​ ​ — ​ ​ — ​ ​ (71,671) ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 291,129 ​ ​ (291,129) ​ ​ — ​ Marketing ​ ​ — ​ ​ 25,558 ​ ​ — ​ ​ — ​ ​ 25,558 ​ Amortization of deferred revenue, VPP ​ ​ 6,230 ​ ​ — ​ ​ — ​ ​ — ​ ​ 6,230 ​ Other revenue and income ​ ​ 818 ​ ​ — ​ ​ — ​ ​ — ​ ​ 818 ​ Total revenue ​ ​ 1,327,149 ​ ​ 25,558 ​ ​ 291,129 ​ ​ (291,129) ​ ​ 1,352,707 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 33,986 ​ ​ — ​ ​ — ​ ​ — ​ ​ 33,986 ​ Gathering and compression ​ ​ 236,134 ​ ​ — ​ ​ 26,193 ​ ​ (26,193) ​ ​ 236,134 ​ Processing ​ ​ 261,155 ​ ​ — ​ ​ — ​ ​ — ​ ​ 261,155 ​ Transportation ​ ​ 197,728 ​ ​ — ​ ​ — ​ ​ — ​ ​ 197,728 ​ Water handling ​ ​ — ​ ​ — ​ ​ 30,637 ​ ​ (30,637) ​ ​ — ​ Production and ad valorem taxes ​ ​ 55,299 ​ ​ — ​ ​ — ​ ​ — ​ ​ 55,299 ​ Marketing ​ ​ — ​ ​ 42,770 ​ ​ — ​ ​ — ​ ​ 42,770 ​ Exploration ​ ​ 668 ​ ​ — ​ ​ — ​ ​ — ​ ​ 668 ​ General and administrative (excluding equity-based compensation) ​ ​ 47,300 ​ ​ — ​ ​ 10,622 ​ ​ (10,622) ​ ​ 47,300 ​ Equity-based compensation ​ ​ 15,145 ​ ​ — ​ ​ 12,402 ​ ​ (12,402) ​ ​ 15,145 ​ Depletion, depreciation and amortization ​ ​ 186,352 ​ ​ — ​ ​ 32,748 ​ ​ (32,748) ​ ​ 186,352 ​ Impairment of property and equipment ​ ​ 5,618 ​ ​ — ​ ​ 817 ​ ​ (817) ​ ​ 5,618 ​ Accretion of asset retirement obligations ​ ​ 939 ​ ​ — ​ ​ — ​ ​ — ​ ​ 939 ​ Gain on sale of assets ​ ​ (575) ​ ​ — ​ ​ — ​ ​ — ​ ​ (575) ​ Contract termination, loss contingency, settlements and other operating expenses ​ ​ (1,284) ​ ​ — ​ ​ 487 ​ ​ (487) ​ ​ (1,284) ​ Total operating expenses ​ ​ 1,038,465 ​ ​ 42,770 ​ ​ 113,906 ​ ​ (113,906) ​ ​ 1,081,235 ​ Operating income (loss) ​ $ 288,684 ​ ​ (17,212) ​ ​ 177,223 ​ ​ (177,223) ​ ​ 271,472 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 28,661 ​ ​ — ​ ​ 28,020 ​ ​ (28,020) ​ ​ 28,661 ​ (1) Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements. 35 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended March 31, 2026 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream (1) Affiliate Total Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 1,311,476 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,311,476 ​ Natural gas liquids sales ​ ​ 503,649 ​ ​ — ​ ​ — ​ ​ — ​ ​ 503,649 ​ Oil sales ​ ​ 46,695 ​ ​ — ​ ​ — ​ ​ — ​ ​ 46,695 ​ Commodity derivative fair value gains ​ ​ 35,023 ​ ​ — ​ ​ — ​ ​ — ​ ​ 35,023 ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 314,211 ​ ​ (314,211) ​ ​ — ​ Marketing ​ ​ — ​ ​ 41,661 ​ ​ — ​ ​ — ​ ​ 41,661 ​ Amortization of deferred revenue, VPP ​ ​ 5,795 ​ ​ — ​ ​ — ​ ​ — ​ ​ 5,795 ​ Other revenue and income ​ ​ 827 ​ ​ — ​ ​ — ​ ​ — ​ ​ 827 ​ Total revenue ​ ​ 1,903,465 ​ ​ 41,661 ​ ​ 314,211 ​ ​ (314,211) ​ ​ 1,945,126 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 44,529 ​ ​ — ​ ​ — ​ ​ — ​ ​ 44,529 ​ Gathering and compression ​ ​ 269,113 ​ ​ — ​ ​ 30,030 ​ ​ (30,030) ​ ​ 269,113 ​ Processing ​ ​ 287,768 ​ ​ — ​ ​ — ​ ​ — ​ ​ 287,768 ​ Transportation ​ ​ 232,225 ​ ​ — ​ ​ — ​ ​ — ​ ​ 232,225 ​ Water handling ​ ​ — ​ ​ — ​ ​ 40,667 ​ ​ (40,667) ​ ​ — ​ Production and ad valorem taxes ​ ​ 80,997 ​ ​ — ​ ​ — ​ ​ — ​ ​ 80,997 ​ Marketing ​ ​ — ​ ​ 62,553 ​ ​ — ​ ​ — ​ ​ 62,553 ​ Exploration ​ ​ 792 ​ ​ — ​ ​ — ​ ​ — ​ ​ 792 ​ General and administrative (excluding equity-based compensation) ​ ​ 51,607 ​ ​ — ​ ​ 11,768 ​ ​ (11,768) ​ ​ 51,607 ​ Equity-based compensation ​ ​ 11,733 ​ ​ — ​ ​ 10,579 ​ ​ (10,579) ​ ​ 11,733 ​ Depletion, depreciation and amortization ​ ​ 206,239 ​ ​ — ​ ​ 34,635 ​ ​ (34,635) ​ ​ 206,239 ​ Impairment of property and equipment ​ ​ 948 ​ ​ — ​ ​ — ​ ​ — ​ ​ 948 ​ Accretion of asset retirement obligations ​ ​ 1,063 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,063 ​ Gain on sale of assets ​ ​ (45,950) ​ ​ — ​ ​ (2,658) ​ ​ 2,658 ​ ​ (45,950) ​ Contract termination, loss contingency, settlements and other operating expenses ​ ​ 12,057 ​ ​ — ​ ​ 579 ​ ​ (579) ​ ​ 12,057 ​ Total operating expenses ​ ​ 1,153,121 ​ ​ 62,553 ​ ​ 125,600 ​ ​ (125,600) ​ ​ 1,215,674 ​ Operating income (loss) ​ $ 750,344 ​ ​ (20,892) ​ ​ 188,611 ​ ​ (188,611) ​ ​ 729,452 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 30,118 ​ ​ — ​ ​ 30,012 ​ ​ (30,012) ​ ​ 30,118 ​ (1) Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements. ​ 36 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 ​ ​ ​ ​ ​ ​ March 31, ​ Increase ​ Percent ​ ​ ​ ​ ​ 2025 ​ ​ 2026 ​ ​ (Decrease) ​ ​ Change ​ ​ Production data (1) (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (Bcf) ​ ​ 195 ​ ​ 236 ​ ​ 41 ​ 21 % ​ C2 Ethane (MBbl) ​ ​ 7,442 ​ ​ 6,836 ​ ​ (606) ​ (8) % ​ C3+ NGLs (MBbl) ​ ​ 10,229 ​ ​ 10,872 ​ ​ 643 ​ 6 % ​ Oil (MBbl) ​ ​ 852 ​ ​ 816 ​ ​ (36) ​ (4) % ​ Combined (Bcfe) ​ ​ 306 ​ ​ 347 ​ ​ 41 ​ 13 % ​ Daily combined production (MMcfe/d) ​ ​ 3,397 ​ ​ 3,852 ​ ​ 455 ​ 13 % ​ Average prices before effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 4.01 ​ ​ 5.57 ​ ​ 1.56 ​ 39 % ​ C2 Ethane (per Bbl) ​ $ 12.70 ​ ​ 13.51 ​ ​ 0.81 ​ 6 % ​ C3+ NGLs (per Bbl) ​ $ 45.65 ​ ​ 37.83 ​ ​ (7.82) ​ (17) % ​ Oil (per Bbl) ​ $ 59.08 ​ ​ 57.22 ​ ​ (1.86) ​ (3) % ​ Weighted Average Combined (per Mcfe) ​ $ 4.55 ​ ​ 5.37 ​ ​ 0.82 ​ 18 % ​ Average realized prices after effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 3.95 ​ ​ 4.86 ​ ​ 0.91 ​ 23 % ​ C2 Ethane (per Bbl) ​ $ 12.70 ​ ​ 13.51 ​ ​ 0.81 ​ 6 % ​ C3+ NGLs (per Bbl) ​ $ 45.65 ​ ​ 37.90 ​ ​ (7.75) ​ (17) % ​ Oil (per Bbl) ​ $ 58.97 ​ ​ 57.22 ​ ​ (1.75) ​ (3) % ​ Weighted Average Combined (per Mcfe) ​ $ 4.52 ​ ​ 4.89 ​ ​ 0.37 ​ 8 % ​ Average costs (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 0.11 ​ ​ 0.13 ​ ​ 0.02 ​ 18 % ​ Gathering and compression ​ $ 0.77 ​ ​ 0.78 ​ ​ 0.01 ​ 1 % ​ Processing ​ $ 0.85 ​ ​ 0.83 ​ ​ (0.02) ​ (2) % ​ Transportation ​ $ 0.65 ​ ​ 0.67 ​ ​ 0.02 ​ 3 % ​ Production and ad valorem taxes ​ $ 0.18 ​ ​ 0.23 ​ ​ 0.05 ​ 28 % ​ Marketing expense, net ​ $ 0.06 ​ ​ 0.06 ​ ​ — ​ * ​ ​ General and administrative (excluding equity-based compensation) ​ $ 0.15 ​ ​ 0.15 ​ ​ — ​ * ​ ​ 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. ​ Natural gas sales . Revenues from sales of natural gas increased from $0.8 billion for the three months ended March 31, 2025 to $1.3 billion for the three months ended March 31, 2026, an increase of $0.5 billion, or 68%, primarily due to an additional $178 million of natural gas revenue attributable to the HG Acquisition properties, as well as higher commodity prices and natural gas production volumes between periods. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended March 31, 2026 accounted for an approximate $367 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 $164 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 $561 million for the three months ended March 31, 2025 to $504 million for the three months ended March 31, 2026, a decrease of $57 million, or 10%, primarily due to lower commodity prices, partially offset by higher production volumes between periods and $16 million of NGLs revenue attributable to the HG Acquisition properties. Lower commodity prices (excluding the effects of derivative settlements) during the three months ended March 31, 2026 accounted for an approximate $79 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Higher C3+ production 37 Table of Contents volumes accounted for an approximate $22 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 $50 million for the three months ended March 31, 2025 to $47 million for the three months ended March 31, 2026, a decrease of $3 million, or 7%, primarily due to lower oil prices and production volumes, partially offset by $3 million of oil revenue attributable to the HG Acquisition properties. Lower oil prices, excluding the effects of derivative settlements, accounted for an approximate $2 million decrease in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower oil production volumes accounted for an approximate $1 million decrease 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 three months ended March 31, 2025 and 2026, our commodity hedges resulted in derivative fair value losses of $72 million and fair value gains of $35 million, respectively. For the three months ended March 31, 2025, commodity derivative fair value losses included $11 million of net cash payments for settled derivative losses. For the three months ended March 31, 2026, commodity derivative fair value gains included $165 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 $6 million for the three months ended March 31, 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 increased from $34 million, or $0.11 per Mcfe, for the three months ended March 31, 2025 to $45 million, or $0.13 per Mcfe, for the three months ended March 31, 2026, an increase of $11 million primarily due to incremental lease operating expense of $6 million related to the HG Acquisition properties and higher wastewater trucking and disposal costs due to the timing of well completions activity between periods. Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense increased from $695 million, or $2.27 per Mcfe, for the three months ended March 31, 2025 to $789 million, or $2.28 per Mcfe, for the three months ended March 31, 2026, an increase of $94 million primarily due to higher production volumes between periods and incremental gathering, compression, processing and transportation expense of $39 million related to the HG Acquisition properties. 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 increased from $0.77 per Mcfe for the three months ended March 31, 2025 to $0.78 per Mcfe for the three months ended March 31, 2026, primarily due to increased fuel costs as a result of higher natural gas prices and annual CPI-based adjustments between periods, partially offset by lower gathering and compression expense on a per unit basis for the HG Acquisition properties. ● Processing costs on a per unit basis decreased from $0.85 per Mcfe for the three months ended March 31, 2025 to $0.83 per Mcfe for the three months ended March 31, 2026, primarily due to lower NGLs transportation fees related to the HG Acquisition properties between periods. ● Transportation costs on a per unit basis increased from $0.65 per Mcfe for the three months ended March 31, 2025 to $0.67 per Mcfe for the three months ended March 31, 2026, 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 three months ended March 31, 2026, partially offset by lower transportation expense on a per unit basis for the HG Acquisition properties. Production and ad valorem tax expense. Production and ad valorem taxes increased from $55 million for the three months ended March 31, 2025 to $81 million for the three months ended March 31, 2026, an increase of $26 million, or 46%, 38 Table of Contents primarily due to higher severance taxes as a result of increased natural gas prices during the three months ended March 31, 2026. Production and ad valorem taxes as a percentage of natural gas revenues remained relatively consistent at 7% and 6% for the three months ended March 31, 2025 and 2026, respectively. General and administrative expense . General and administrative expense (excluding equity-based compensation expense) increased from $47 million for the three months ended March 31, 2025 to $52 million for the three months ended March 31, 2026, an increase of $5 million, or 9%, primarily due to higher salary and wage expense, software license costs and professional service fees between periods. General and administrative expense on a per unit basis (excluding equity-based compensation) remained consistent at $0.15 per Mcfe for the three months ended March 31, 2025 and 2026. Equity-based compensation expense . Non-cash equity-based compensation expense decreased from $15 million for the three months ended March 31, 2025 to $12 million for the three months ended March 31, 2026, a decrease of $3 million or 23%. This decrease was primarily due to lower RSU award expense of $3 million 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 increased from $186 million for the three months ended March 31, 2025 to $206 million for the three months ended March 31, 2026, an increase of $20 million, or 11%, primarily due to higher production volumes between periods related to our HG Acquisition properties. On a per-unit basis, DD&A expense remained relatively consistent at $0.61 per Mcfe and $0.60 per Mcfe for the three months ended March 31, 2025 and 2026, respectively. Impairment of property and equipment . Impairment of oil and gas properties decreased from $6 million for the three months ended March 31, 2025 to $1 million for the three months ended March 31, 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 and settlements was a gain of $1 million for the three months ended March 31, 2025. Contract termination, loss contingency and settlements was a loss of $12 million for the three months ended March 31, 2026 primarily due to loss contingencies and settlements recorded during the first quarter of 2026. See Note 14—Contingencies to the unaudited condensed consolidated financial statements for additional information. Gain on sale of assets. Gain on sale of assets was less than $1 million for the three months ended March 31, 2025. Gain on sale of assets was $46 million for the three months ended March 31, 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 increased from $17 million, or $0.06 per Mcfe, for the three months ended March 31, 2025 to $21 million, or $0.06 per Mcfe, for the three months ended March 31, 2026, primarily due to higher demand fees on certain pipelines and lower pipeline utilization due to maintenance between periods. M arketing revenue. Marketing revenue increased from $26 million for the three months ended March 31, 2025 to $42 million for the three months ended March 31, 2026, an increase of $16 million, or 63%. This fluctuation primarily resulted from the following: ● Natural gas marketing revenue remained consistent at $1 million for the three months ended March 31, 2025 and 2026. ● Oil marketing revenue increased by $14 million between periods primarily due to higher oil marketing volumes and prices. Higher oil marketing volumes accounted for a $12 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 $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). 39 Table of Contents ● NGLs marketing revenue increased by $2 million between periods primarily due to higher ethane marketing volumes and prices for the three months ended March 31, 2026. Marketing expense. Marketing expense increased from $43 million for the three months ended March 31, 2025 to $63 million for the three months ended March 31, 2026, an increase of $20 million, or 46%. 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 oil purchases increased $11 million between periods, primarily due to higher oil marketing volumes during the three months ended March 31, 2026. Firm transportation costs increased $9 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 three months ended March 31, 2026. Antero Midstream Segment Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $291 million for the three months ended March 31, 2025 to $314 million for the three months ended March 31, 2026, an increase of $23 million. This increase is primarily due to higher gathering and processing revenues of $21 million and higher water handling revenues of $2 million. The increased gathering and processing revenues between periods is primarily due to the HG Acquisition and increased gathering rates as a result of annual CPI-based adjustments. The increased water handling revenues between periods is primarily due to higher blending cost of service fees, increased volumes and costs for wastewater trucking and disposal volumes, a higher fresh water delivery fee as a result of an annual CPI-based adjustment and fresh water delivery volumes for our acreage acquired in the HG Acquisition that are charged at cost plus 3% during the three months ended March 31, 2026, partially offset by decreased fresh water delivery volumes between periods due to the timing and location of our completions activity. Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $114 million for the three months ended March 31, 2025 to $126 million for the three months ended March 31, 2026, an increase of $12 million. This increase is primarily due to higher direct operating expenses as a result of increased gathering volumes between periods related to the HG Acquisition and fresh water delivery services on our acreage acquired in the HG Acquisition, as well as increased wastewater trucking and disposal volumes and higher blending costs between periods. Items Not Allocated to Segments Interest expense, net. Interest expense, net increased from $23 million for the three months ended March 31, 2025 to $37 million for the three months ended March 31, 2026, an increase of $14 million or 58%, primarily due to borrowings under the Term Loan and issuance of the 2036 Notes during the three months ended March 31, 2026, partially offset by the redemption of the 2029 Notes. See Note 7—Long-Term Debt to our unaudited condensed consolidated financial statements for more information. Loss on early extinguishment of debt. During the three months ended March 31, 2025, we recognized a loss on early debt extinguishment of $3 million primarily 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. During the three months ended March 31, 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—Long-Term Debt to our unaudited condensed consolidated financial statements for more information. Transaction expense . There were no transaction expenses incurred during the three months ended March 31, 2025. During the three months ended March 31, 2026, we incurred $22 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 . For the three months ended March 31, 2025, we recognized an income tax expense of $54 million, with an effective tax rate of 20%, related to our income before income taxes of $274 million. For the three months ended March 31, 2026, we recognized income tax expense of $146 million, with an effective tax rate of 21%, related to our income before income taxes of $694 million. 40 Table of Contents 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 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 March 31, 2026, 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): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended March 31, ​ ​ ​ 2025 ​ 2026 ​ Net cash provided by operating activities ​ $ 457,739 ​ ​ 859,058 ​ Net cash used in investing activities ​ ​ (207,891) ​ ​ (2,283,486) ​ Net cash provided by (used in) financing activities ​ ​ (249,848) ​ ​ 1,214,428 ​ Net decrease in cash, cash equivalents and restricted cash ​ $ — ​ ​ (210,000) ​ ​ Operating activities. Net cash provided by operating activities was $458 million and $859 million for the three months ended March 31, 2025 and 2026, respectively. Net cash provided by operating activities increased between periods primarily due to higher natural gas revenues and changes in working capital, partially offset by lower NGLs and oil revenues, higher lease operating, gathering, compression, processing, transportation and marketing and production and ad valorem taxes between periods. 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 $208 million for the three months ended March 31, 2025 to $2.3 billion for the three months ended March 31, 2026, primarily due to cash paid for our HG Acquisition of $2.8 billion during the three months ended March 31, 2026, increased drilling activity of $9 million between periods and acquisitions of oil and gas properties during the three months ended March 31, 2026 of $8 million, partially offset by proceeds from the Utica Shale Divestiture of $737 million during the three months ended March 31, 2026 and decreased oil and gas leasing activity of $13 million between periods. Financing activities. Net cash used in financing activities was $250 million for the three months ended March 31, 2025. Net cash provided by financing activities was $1.2 billion for the three months ended March 31, 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 and the issuance of our 2036 Notes of $750 million, partially offset by higher net repayments on our Credit Facility of $277 million between periods, repayments on the Term Loan of $236 million for the three months ended March 31, 2026, higher repayments and redemptions of our senior notes of $252 million between periods, and increased payments of employee tax withholdings for the settlement of equity-based compensation awards of $18 million between periods. 2026 Capital Budget, Capital Spending and Acquisition s 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 41 Table of Contents capital that is dependent on commodity prices. Our capital budget reflects the closing of the HG Acquisition on February 3, 2026 and 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 March 31, 2026, our total consolidated capital expenditures were $252 million, including drilling and completion costs of $222 million, leasehold acquisitions of $25 million, and other capital expenditures of $5 million. 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 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 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. 42 Table of Contents Based on future prices as of March 31, 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 three months ended March 31, 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.