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 are an independent oil and natural gas company engaged in the development, production, exploration and acquisition of natural gas, NGLs and oil properties located in the Appalachian Basin. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to develop our reserves and production, primarily on our existing multi-year inventory of drilling locations. We have assembled a portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and repeatability. Our drilling opportunities are focused in the Appalachian Basin. As of September 30, 2024, we held approximately 519,000 net acres in the Appalachian Basin. Financing Highlights Unsecured Credit Facility During the second quarter of 2024, we achieved an investment grade credit rating from S&P Global Inc. As a result of this investment grade credit rating, on July 30, 2024, we entered into an amended and restated senior revolving credit facility with lender commitments of $1.65 billion that matures on July 30, 2029, subject to certain extension terms and conditions. Borrowings under the amended and restated facility are unsecured and are not guaranteed by any of our subsidiaries. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. Market Conditions and Business Trends Commodity Markets Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Benchmark prices for natural gas decreased significantly, while benchmark prices for oil remained consistent and benchmark prices for NGLs increased during the nine months ended September 30, 2024 as compared to the same period of 2023. As a result of the lower benchmark natural gas prices and higher benchmark NGLs prices in 2024, we experienced a decrease in price realizations for natural gas and ethane products and an increase in price realization for NGLs products during the three and nine months ended September 30, 2024. We monitor the economic factors that impact natural gas, NGLs and oil prices, including domestic and foreign supply and demand indicators, domestic and foreign commodity inventories, the actions of Organization of Petroleum Exporting Countries and other large producing nations and the current conflicts in Ukraine and in the Middle East, among others. In the current economic environment, we expect that commodity prices for some or all of the commodities we produce could remain volatile. This volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows. 33 Table of Contents The following table details the average benchmark natural gas, NGLs and oil prices: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended September 30, ​ Nine Months Ended September 30, ​ ​ 2023 2024 2023 2024 ​ Henry Hub ($/Mcf) (1) ​ $ 2.55 ​ ​ 2.16 ​ ​ 2.69 ​ ​ 2.10 ​ Mont Belvieu Ethane ($/Bbl) (2) ​ ​ 12.38 ​ ​ 6.61 ​ ​ 10.58 ​ ​ 7.58 ​ Mont Belvieu C3+ NGLs ($/Bbl) (3) ​ ​ 37.07 ​ ​ 39.01 ​ ​ 38.67 ​ ​ 40.70 ​ West Texas Intermediate ($/Bbl) (4) ​ ​ 82.26 ​ ​ 75.09 ​ ​ 77.39 ​ ​ 77.54 ​ (1) NYMEX first of month average natural gas price. (2) Intercontinental Exchange, Inc. (“ICE”) settlement ethane Oil Price Information Service (“OPIS”) futures average price for the front month contract as published on the last trading day of the month. (3) ICE settlement propane, isobutane, normal butane and natural gasoline OPIS futures average price for the front month contract as published on the last trading day of the month. Propane and isobutane reflect TET prices, and normal butane and natural gasoline reflect non-TET prices. Propane, isobutane, normal butane and natural gasoline futures prices are weighted to approximate Antero Resources’ average C3+ NGLs composition. (4) NYMEX calendar month average settled futures price. Hedge Position Antero Resources (Excluding Martica) We are exposed to certain commodity price risks relating to our ongoing business operations, and we use derivative instruments when circumstances warrant to manage such risks. In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased. For the three and nine months ended September 30, 2023 and 2024, substantially all of our production was unhedged. The tables and narrative below exclude derivative instruments attributable to Martica, our consolidated VIE, since all gains or losses from such contracts are fully attributable to the noncontrolling interests in Martica. As of September 30, 2024, our fixed price NGLs swap positions excluding Martica were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Commodity / Settlement Period Index Contracted Volume Price ​ Propane ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ October-December 2024 ​ Mont Belvieu Propane-OPIS TET ​ 920 MBbl ​ $ 33.67 /Bbl ​ ​ As of September 30, 2024, our natural gas basis swap positions settle on the pricing index to basis differential of the Columbia Gas Transmission pipeline (“TCO”) to the NYMEX Henry Hub natural gas price were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted Average ​ Commodity / Settlement Period ​ Index to Basis Differential Contracted Volume Hedged Differential ​ Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ October-December 2024 ​ NYMEX to TCO ​ 5 Bcf ​ $ 0.530 /MMBtu ​ ​ We have a call option and an embedded put option tied to NYMEX pricing for the production volumes associated with the Company’s retained interest in the VPP properties. As of September 30, 2024, our call option and embedded put option arrangements were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Embedded ​ ​ ​ ​ ​ ​ ​ ​ Call Option ​ Put Option ​ Commodity / Settlement Period Index Contracted Volume Strike Price Strike Price Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ October-December 2024 ​ Henry Hub ​ 5 Bcf ​ $ 2.477 /MMBtu ​ $ 2.477 /MMBtu ​ January-December 2025 ​ Henry Hub ​ 16 Bcf ​ ​ 2.564 /MMBtu ​ ​ 2.564 /MMBtu ​ January-December 2026 ​ Henry Hub ​ 12 Bcf ​ ​ 2.629 /MMBtu ​ ​ 2.629 /MMBtu ​ ​ ​ ​ ​ 33 Bcf ​ ​ 2.574 /MMBtu ​ ​ 2.574 /MMBtu ​ 34 Table of Contents ​ As of September 30, 2024, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of $24 million. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information. Martica Our consolidated VIE, Martica, also maintains a portfolio of fixed swap natural gas, NGLs and oil derivatives for the benefit of the noncontrolling interests in Martica. As such, all gains and losses attributable to Martica’s derivative portfolio are fully attributable to the noncontrolling interests in Martica. As of September 30, 2024, Martica’s fixed price natural gas and oil swap positions were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Commodity / Settlement Period Index Contracted Volume Price ​ Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ October-December 2024 ​ Henry Hub ​ 3 Bcf ​ $ 2.33 /MMBtu ​ January-March 2025 ​ Henry Hub ​ 1 Bcf ​ ​ 2.53 /MMBtu ​ ​ ​ ​ ​ 4 Bcf ​ ​ 2.42 /MMBtu ​ Oil ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ October-December 2024 ​ West Texas Intermediate ​ 3 MBbl ​ $ 44.02 /Bbl ​ January-March 2025 ​ West Texas Intermediate ​ 4 MBbl ​ ​ 45.06 /Bbl ​ ​ ​ ​ ​ 7 MBbl ​ ​ 44.54 /Bbl ​ ​ As of September 30, 2024, the estimated fair value of Martica’s commodity derivative contracts was a net liability of $3 million. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information. Economic Indicators The economy experienced elevated inflation levels as a result of global supply and demand imbalances, where global demand outpaced supplies beginning in 2021 and continuing through the third quarter of 2024. For example, the Consumer Price Index (“CPI”) for all urban consumers increased 3.7% from September 2022 to September 2023 and an additional 2.4% from September 2023 to September 2024 as compared to the Federal Reserve’s stated goal of 2%. In order to manage the inflation risk present in the United States’ economy, the Federal Reserve utilized monetary policy in the form of interest rate increases beginning in March 2022 in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis. Between March 2022 and July 2023, the Federal Reserve increased the federal funds interest rate by 5.25%. During the three months ended September 30, 2024, inflation rates began to approach the Federal Reserve’s stated goal of 2%, and the Federal Reserve decreased the federal funds rate by 0.5% in September 2024. While inflationary pressures in the United States’ economy have begun to subside, we continue to be impacted by the increased federal funds interest rate. See “— Results of Operations” for more information. The economy also continues to be impacted by the effects of global events. These events have often caused global supply chain disruptions with additional pressure due to trade sanctions on Russia and other global trade restrictions, among others. However, our supply chain has not experienced any significant interruptions as a result of such events. 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. ​ 35 Table of Contents Results of Operations We have three operating segments: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing and utilization of excess firm transportation capacity; and (iii) midstream services through our equity method investment in Antero Midstream. 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 the unaudited condensed consolidated financial statements for more information. Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2024 The operating results of our reportable segments were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended September 30, 2023 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliate Total ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 516,214 ​ ​ — ​ ​ — ​ ​ — ​ ​ 516,214 ​ Natural gas liquids sales ​ ​ 482,570 ​ ​ — ​ ​ — ​ ​ — ​ ​ 482,570 ​ Oil sales ​ ​ 62,629 ​ ​ — ​ ​ — ​ ​ — ​ ​ 62,629 ​ Commodity derivative fair value gains ​ ​ 3,448 ​ ​ — ​ ​ — ​ ​ — ​ ​ 3,448 ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 263,839 ​ ​ (263,839) ​ ​ — ​ Marketing ​ ​ — ​ ​ 53,068 ​ ​ — ​ ​ — ​ ​ 53,068 ​ Amortization of deferred revenue, VPP ​ ​ 7,701 ​ ​ — ​ ​ — ​ ​ — ​ ​ 7,701 ​ Other revenue and income ​ ​ 546 ​ ​ — ​ ​ — ​ ​ — ​ ​ 546 ​ Total revenue ​ ​ 1,073,108 ​ ​ 53,068 ​ ​ 263,839 ​ ​ (263,839) ​ ​ 1,126,176 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 33,484 ​ ​ — ​ ​ — ​ ​ — ​ ​ 33,484 ​ Gathering and compression ​ ​ 216,435 ​ ​ — ​ ​ 23,547 ​ ​ (23,547) ​ ​ 216,435 ​ Processing ​ ​ 264,391 ​ ​ — ​ ​ — ​ ​ — ​ ​ 264,391 ​ Transportation ​ ​ 191,060 ​ ​ — ​ ​ — ​ ​ — ​ ​ 191,060 ​ Water handling ​ ​ — ​ ​ — ​ ​ 28,367 ​ ​ (28,367) ​ ​ — ​ Production and ad valorem taxes ​ ​ 32,258 ​ ​ — ​ ​ — ​ ​ — ​ ​ 32,258 ​ Marketing ​ ​ — ​ ​ 69,542 ​ ​ — ​ ​ — ​ ​ 69,542 ​ Exploration and mine expenses ​ ​ 591 ​ ​ — ​ ​ — ​ ​ — ​ ​ 591 ​ General and administrative (excluding equity-based compensation) ​ ​ 39,967 ​ ​ — ​ ​ 9,284 ​ ​ (9,284) ​ ​ 39,967 ​ Equity-based compensation ​ ​ 18,458 ​ ​ — ​ ​ 8,349 ​ ​ (8,349) ​ ​ 18,458 ​ Depletion, depreciation and amortization ​ ​ 176,259 ​ ​ — ​ ​ 30,745 ​ ​ (30,745) ​ ​ 176,259 ​ Impairment of property and equipment ​ ​ 13,476 ​ ​ — ​ ​ — ​ ​ — ​ ​ 13,476 ​ Accretion of asset retirement obligations ​ ​ 889 ​ ​ — ​ ​ 45 ​ ​ (45) ​ ​ 889 ​ Contract termination, loss contingency, settlements and other operating expenses ​ ​ 13,770 ​ ​ — ​ ​ 722 ​ ​ (722) ​ ​ 13,770 ​ Loss (gain) on sale of assets ​ ​ (136) ​ ​ — ​ ​ 467 ​ ​ (467) ​ ​ (136) ​ Total operating expenses ​ ​ 1,000,902 ​ ​ 69,542 ​ ​ 101,526 ​ ​ (101,526) ​ ​ 1,070,444 ​ Operating income (loss) ​ $ 72,206 ​ ​ (16,474) ​ ​ 162,313 ​ ​ (162,313) ​ ​ 55,732 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 22,207 ​ ​ — ​ ​ 27,397 ​ ​ (27,397) ​ ​ 22,207 ​ ​ ​ 36 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended September 30, 2024 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliate Total ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 425,802 ​ ​ — ​ ​ — ​ ​ — ​ ​ 425,802 ​ Natural gas liquids sales ​ ​ 504,200 ​ ​ — ​ ​ — ​ ​ — ​ ​ 504,200 ​ Oil sales ​ ​ 52,724 ​ ​ — ​ ​ — ​ ​ — ​ ​ 52,724 ​ Commodity derivative fair value gains ​ ​ 18,368 ​ ​ — ​ ​ — ​ ​ — ​ ​ 18,368 ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 269,870 ​ ​ (269,870) ​ ​ — ​ Marketing ​ ​ — ​ ​ 47,160 ​ ​ — ​ ​ — ​ ​ 47,160 ​ Amortization of deferred revenue, VPP ​ ​ 6,812 ​ ​ — ​ ​ — ​ ​ — ​ ​ 6,812 ​ Other revenue and income ​ ​ 854 ​ ​ — ​ ​ — ​ ​ — ​ ​ 854 ​ Total revenue ​ ​ 1,008,760 ​ ​ 47,160 ​ ​ 269,870 ​ ​ (269,870) ​ ​ 1,055,920 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 29,597 ​ ​ — ​ ​ — ​ ​ — ​ ​ 29,597 ​ Gathering and compression ​ ​ 226,224 ​ ​ — ​ ​ 24,516 ​ ​ (24,516) ​ ​ 226,224 ​ Processing ​ ​ 276,569 ​ ​ — ​ ​ — ​ ​ — ​ ​ 276,569 ​ Transportation ​ ​ 182,390 ​ ​ — ​ ​ — ​ ​ — ​ ​ 182,390 ​ Water handling ​ ​ — ​ ​ — ​ ​ 27,208 ​ ​ (27,208) ​ ​ — ​ Production and ad valorem taxes ​ ​ 47,423 ​ ​ — ​ ​ — ​ ​ — ​ ​ 47,423 ​ Marketing ​ ​ — ​ ​ 62,144 ​ ​ — ​ ​ — ​ ​ 62,144 ​ Exploration ​ ​ 671 ​ ​ — ​ ​ — ​ ​ — ​ ​ 671 ​ General and administrative (excluding equity-based compensation) ​ ​ 38,562 ​ ​ — ​ ​ 10,927 ​ ​ (10,927) ​ ​ 38,562 ​ Equity-based compensation ​ ​ 16,065 ​ ​ — ​ ​ 11,945 ​ ​ (11,945) ​ ​ 16,065 ​ Depletion, depreciation and amortization ​ ​ 170,197 ​ ​ — ​ ​ 32,534 ​ ​ (32,534) ​ ​ 170,197 ​ Impairment of property and equipment ​ ​ 13,455 ​ ​ — ​ ​ 332 ​ ​ (332) ​ ​ 13,455 ​ Accretion of asset retirement obligations ​ ​ 998 ​ ​ — ​ ​ 49 ​ ​ (49) ​ ​ 998 ​ Gain on sale of assets ​ ​ (1,297) ​ ​ — ​ ​ (473) ​ ​ 473 ​ ​ (1,297) ​ Contract termination, loss contingency, settlements and other operating expenses ​ ​ (1,175) ​ ​ — ​ ​ 405 ​ ​ (405) ​ ​ (1,175) ​ Total operating expenses ​ ​ 999,679 ​ ​ 62,144 ​ ​ 107,443 ​ ​ (107,443) ​ ​ 1,061,823 ​ Operating income (loss) ​ $ 9,081 ​ ​ (14,984) ​ ​ 162,427 ​ ​ (162,427) ​ ​ (5,903) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 25,634 ​ ​ — ​ ​ 27,668 ​ ​ (27,668) ​ ​ 25,634 ​ ​ ​ 37 Table of Contents Exploration and Production Segment The following table sets forth selected operating data of the exploration and production segment: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended ​ Amount of ​ ​ ​ ​ ​ September 30, ​ Increase ​ Percent ​ ​ ​ 2023 ​ 2024 ​ (Decrease) ​ Change ​ Production data (1) (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (Bcf) ​ ​ 208 ​ ​ 200 ​ ​ (8) ​ (4) % C2 Ethane (MBbl) ​ ​ 6,696 ​ ​ 7,302 ​ ​ 606 ​ 9 % C3+ NGLs (MBbl) ​ ​ 10,977 ​ ​ 10,793 ​ ​ (184) ​ (2) % Oil (MBbl) ​ ​ 918 ​ ​ 856 ​ ​ (62) ​ (7) % Combined (Bcfe) ​ ​ 320 ​ ​ 313 ​ ​ (7) ​ (2) % Daily combined production (MMcfe/d) ​ ​ 3,474 ​ ​ 3,406 ​ ​ (68) ​ (2) % Average prices before effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 2.48 ​ ​ 2.13 ​ ​ (0.35) ​ (14) % C2 Ethane (per Bbl) (4) ​ $ 11.73 ​ ​ 8.01 ​ ​ (3.72) ​ (32) % C3+ NGLs (per Bbl) ​ $ 36.81 ​ ​ 41.30 ​ ​ 4.49 ​ 12 % Oil (per Bbl) ​ $ 68.22 ​ ​ 61.59 ​ ​ (6.63) ​ (10) % Weighted Average Combined (per Mcfe) ​ $ 3.32 ​ ​ 3.14 ​ ​ (0.18) ​ (5) % Average realized prices after effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 2.46 ​ ​ 2.14 ​ ​ (0.32) ​ (13) % C2 Ethane (per Bbl) (4) ​ $ 11.73 ​ ​ 8.01 ​ ​ (3.72) ​ (32) % C3+ NGLs (per Bbl) ​ $ 36.76 ​ ​ 41.56 ​ ​ 4.80 ​ 13 % Oil (per Bbl) ​ $ 67.91 ​ ​ 61.46 ​ ​ (6.45) ​ (9) % Weighted Average Combined (per Mcfe) ​ $ 3.30 ​ ​ 3.15 ​ ​ (0.15) ​ (5) % Average costs (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 0.10 ​ ​ 0.09 ​ ​ (0.01) ​ (10) % Gathering and compression ​ $ 0.68 ​ ​ 0.72 ​ ​ 0.04 ​ 6 % Processing ​ $ 0.83 ​ ​ 0.88 ​ ​ 0.05 ​ 6 % Transportation ​ $ 0.60 ​ ​ 0.58 ​ ​ (0.02) ​ (3) % Production and ad valorem taxes ​ $ 0.10 ​ ​ 0.15 ​ ​ 0.05 ​ 50 % Marketing expense, net ​ $ 0.05 ​ ​ 0.05 ​ ​ — ​ * ​ General and administrative (excluding equity-based compensation) ​ $ 0.13 ​ ​ 0.12 ​ ​ (0.01) ​ (8) % Depletion, depreciation, amortization and accretion ​ $ 0.55 ​ ​ 0.55 ​ ​ — ​ * ​ * Not meaningful (1) Production data excludes volumes related to the VPP. (2) Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and may not reflect their relative economic value. (3) Average prices reflect the before and after effects of our settled commodity derivatives. Our calculation of such after effects includes gains (losses) on settlements of commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. (4) The average realized price for the three months ended September 30, 2023 includes $6 million of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives for the three months ended September 30, 2023 would have been $10.88 per Bbl. ​ Natural gas sales . Revenues from sales of natural gas decreased from $516 million for the three months ended September 30, 2023 to $426 million for the three months ended September 30, 2024, a decrease of $90 million, or 18%. Lower commodity prices (excluding the effects of derivative settlements) during the three months ended September 30, 2024 accounted for an approximate $69 million decrease in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes). Lower natural gas production volumes accounted for an approximate $21 million decrease in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price). NGLs sales . Revenues from sales of NGLs increased from $483 million for the three months ended September 30, 2023 to $504 million for the three months ended September 30, 2024, an increase of $21 million, or 4%. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended September 30, 2024 accounted for an approximate $21 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). 38 Table of Contents Oil sales . Revenues from sales of oil decreased from $63 million for the three months ended September 30, 2023 to $53 million for the three months ended September 30, 2024, a decrease of $10 million, or 16%. Lower commodity prices (excluding the effects of derivative settlements) during the three months ended September 30, 2024 accounted for an approximate $6 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower oil production volumes during the three months ended September 30, 2024 accounted for an approximate $4 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. Our commodity derivatives included fixed price swap contracts, basis swap contracts, call options and embedded put options. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations and comprehensive income. For the three months ended September 30, 2023 and 2024, our commodity hedges resulted in derivative fair value gains of $3 million and $18 million, respectively. For the three months ended September 30, 2023, commodity derivative fair value gains included $6 million of cash payments on settled commodity derivative losses. For the three months ended September 30, 2024, commodity derivative fair value gains included $4 million of net cash proceeds on settled commodity derivatives 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 decreased from $8 million for the three months ended September 30, 2023 to $7 million for the three months ended September 30, 2024, a decrease of $1 million, or 12%, primarily due to lower production volumes attributable to the VPP properties between periods. Amortization of the deferred revenues associated with the VPP are recognized as the production volumes are delivered at $1.61 per MMBtu over the contractual term. Lease operating expense . Lease operating expense decreased from $33 million, or $0.10 per Mcfe, for the three months ended September 30, 2023 to $30 million, or $0.09 per Mcfe, for the three months ended September 30, 2024, a decrease of $3 million primarily due to lower water disposal costs and workover expense between periods. Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense increased from $672 million for the three months ended September 30, 2023 to $685 million for the three months ended September 30, 2024, an increase of $13 million, or 2%. This was primarily a result of the following: ● Gathering and compression costs increased from $0.68 per Mcfe for the three months ended September 30, 2023 to $0.72 per Mcfe for the three months ended September 30, 2024, primarily due to the expiration of the growth incentive fee rebate program on December 31, 2023 and annual CPI-based adjustments between periods. During the three months ended September 30, 2023, we earned a fee rebate of $12 million under this program. ● Processing costs increased from $0.83 per Mcfe for the three months ended September 30, 2023 to $0.88 per Mcfe for the three months ended September 30, 2024, primarily due to increased costs for NGLs processing, which includes an annual CPI-based adjustment during the first quarter of 2024 and higher NGLs transportation fees. ● Transportation costs decreased from $0.60 per Mcfe for the three months ended September 30, 2023 to $0.58 per Mcfe for the three months ended September 30, 2024 primarily due to lower demand fees, as well as lower fuel costs as a result of lower natural gas prices between periods. Production and ad valorem tax expense. Production and ad valorem taxes increased from $32 million for the three months ended September 30, 2023 to $47 million for the three months ended September 30, 2024, an increase of $15 million, or 47%, primarily due to higher ad valorem taxes, partially offset by lower natural gas prices during the three months ended September 30, 2024. Production and ad valorem taxes as a percentage of natural gas revenues increased from 6% for the three months ended September 30, 2023 to 11% for the three months ended September 30, 2024, primarily as a result of higher ad valorem taxes, which 2024 ad valorem taxes are based on commodity prices during 2022. 39 Table of Contents General and administrative expense . General and administrative expense (excluding equity-based compensation expense) decreased slightly from $40 million, or $0.13 per Mcfe, for the three months ended September 30, 2023 to $39 million, or $0.12 per Mcfe for the three months ended September 30, 2024 primarily as a result of lower pipeline bond and leased vehicle costs between periods . Equity-based compensation expense . Non-cash equity-based compensation expense decreased from $18 million for the three months ended September 30, 2023 to $16 million for the three months ended September 30, 2024, a decrease of $2 million, or 13%. This decrease was primarily due to lower PSU award expense between periods, partially offset by increased RSU award expense attributable to awards granted in the first quarter of 2024. See Note 9—Equity-Based Compensation to the unaudited condensed consolidated financial statements for more information. Depletion, depreciation, and amortization expense (“DD&A expense”) . DD&A expense decreased from $176 million, or $0.55 per Mcfe, for the three months ended September 30, 2023 to $170 million, or $0.55 per Mcfe, for the three months ended September 30 2024, a decrease of $6 million, or 3%. The decrease in total DD&A expense is primarily due to lower production volumes between periods. Impairment of property and equipment . Impairment of oil and gas properties remained consistent at $13 million for the three months ended September 30, 2023 and 2024. During both periods, we recognized impairments primarily related to expiring leases as well as design and initial costs related to pads we no longer plan to place into service. Contract termination, loss contingency, settlements and other operating expenses . Contract termination, loss contingency, settlements and other operating expenses was a loss of $14 million for the three months ended September 30, 2023 primarily due to a loss contingency. Contract termination, loss contingency, settlements and other operating expenses was a gain of $1 million for the three months ended September 30, 2024 primarily due to our receipt of 0.1 million shares of Antero Midstream common stock as part of a judgment in a legal proceeding with an unaffiliated third-party. 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 for the three months ended September 30, 2023 and 2024 remained relatively consistent at $17 million and $15 million, respectively, or $0.05 per Mcfe. Marketing revenue. Marketing revenue decreased from $53 million for the three months ended September 30, 2023 to $47 million for the three months ended September 30, 2024, a decrease of $6 million, or 11%. This fluctuation primarily resulted from the following: ● Natural gas marketing revenue decreased by $14 million between periods primarily due to lower natural gas marketing volumes and prices between periods. Lower natural gas marketing volumes accounted for an $11 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower natural gas prices accounted for a $3 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). ● Oil marketing revenue increased by $8 million between periods primarily due to higher oil marketing volumes, partially offset by lower oil prices. Higher oil marketing volumes accounted for a $10 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower oil prices accounted for a $2 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). Marketing expense. Marketing expense decreased from $70 million for the three months ended September 30, 2023 to $62 million for the three months ended September 30, 2024, a decrease of $8 million, or 11%. Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related to current excess firm capacity. The cost of third-party natural gas, oil and NGLs purchases remained consistent at $43 million for the three months ended September 30, 2023 and 2024. Firm transportation costs were $26 million for the three months ended September 30, 2023 and $18 million for the three months ended September 30, 2024, a decrease of $8 million due to the reduction in firm transportation commitments and higher third-party marketing volumes between periods. 40 Table of Contents Antero Midstream Segment Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $264 million for the three months ended September 30, 2023 to $270 million for the three months ended September 30, 2024, an increase of $6 million. This increase is primarily due to higher gathering and processing revenues of $20 million, partially offset by lower water handling revenues of $14 million. The increased gathering and processing revenues between periods is primarily a result of the expiration of the growth incentive fee rebate program on December 31, 2023, annual CPI-based gathering and compression rate adjustments and increased high pressure gathering throughput between periods. The decreased water handling revenues between periods was primarily due to lower fresh water delivery and other fluid handling volumes, partially offset by an increased fresh water delivery rate due to an annual CPI-based adjustment during the first quarter of 2024. Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $102 million for the three months ended September 30, 2023 to $107 million for the three months ended September 30, 2024, an increase of $5 million. This increase is primarily due to higher general and administrative expense, including equity-based compensation expense, and depreciation expense between periods. Discussion of Items Not Allocated to Segments Interest expense. Interest expense decreased from $32 million for the three months ended September 30, 2023 to $28 million for the three months ended September 30, 2024, a decrease of $4 million, or 11%, primarily due to the conversion of $26 million aggregate principal amount of our 2026 Convertible Notes during the first quarter of 2024 and lower benchmark interest rates during the three months ended September 30, 2024, partially offset by higher average Credit Facility borrowings between periods. Income tax expense . For the three months ended September 30, 2023, we had an income tax expense of $14 million, with an effective tax rate of 30%, due to income before income taxes of $46 million. For the three months ended September 30, 2024, we had an income tax expense of $1 million from a loss before income taxes of $9 million primarily due to the net loss before income taxes during the third quarter of 2024, which when taken together with the net loss before taxes during the six months ended June 30, 2024, resulted in a 9% effective tax rate for the nine months ended September 30, 2024. 41 Table of Contents Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2024 The operating results of our reportable segments were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nine Months Ended September 30, 2023 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliate Total Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 1,621,659 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,621,659 ​ Natural gas liquids sales ​ ​ 1,375,738 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,375,738 ​ Oil sales ​ ​ 172,402 ​ ​ — ​ ​ — ​ ​ — ​ ​ 172,402 ​ Commodity derivative fair value gains ​ ​ 137,924 ​ ​ — ​ ​ — ​ ​ — ​ ​ 137,924 ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 781,601 ​ ​ (781,601) ​ ​ — ​ Marketing ​ ​ — ​ ​ 155,390 ​ ​ — ​ ​ — ​ ​ 155,390 ​ Amortization of deferred revenue, VPP ​ ​ 22,852 ​ ​ — ​ ​ — ​ ​ — ​ ​ 22,852 ​ Other revenue and income ​ ​ 1,864 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,864 ​ Total revenue ​ ​ 3,332,439 ​ ​ 155,390 ​ ​ 781,601 ​ ​ (781,601) ​ ​ 3,487,829 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 91,553 ​ ​ — ​ ​ — ​ ​ — ​ ​ 91,553 ​ Gathering and compression ​ ​ 640,730 ​ ​ — ​ ​ 72,819 ​ ​ (72,819) ​ ​ 640,730 ​ Processing ​ ​ 764,301 ​ ​ — ​ ​ — ​ ​ — ​ ​ 764,301 ​ Transportation ​ ​ 576,002 ​ ​ — ​ ​ — ​ ​ — ​ ​ 576,002 ​ Water handling ​ ​ — ​ ​ — ​ ​ 89,563 ​ ​ (89,563) ​ ​ — ​ Production and ad valorem taxes ​ ​ 117,692 ​ ​ — ​ ​ — ​ ​ — ​ ​ 117,692 ​ Marketing ​ ​ — ​ ​ 217,078 ​ ​ — ​ ​ — ​ ​ 217,078 ​ Exploration and mine expenses ​ ​ 2,097 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,097 ​ General and administrative (excluding equity-based compensation) ​ ​ 124,599 ​ ​ — ​ ​ 29,967 ​ ​ (29,967) ​ ​ 124,599 ​ Equity-based compensation ​ ​ 44,988 ​ ​ — ​ ​ 23,175 ​ ​ (23,175) ​ ​ 44,988 ​ Depletion, depreciation and amortization ​ ​ 515,247 ​ ​ — ​ ​ 101,174 ​ ​ (101,174) ​ ​ 515,247 ​ Impairment of property and equipment ​ ​ 44,746 ​ ​ — ​ ​ — ​ ​ — ​ ​ 44,746 ​ Accretion of asset retirement obligations ​ ​ 2,971 ​ ​ — ​ ​ 133 ​ ​ (133) ​ ​ 2,971 ​ Contract termination, loss contingency, settlements and other operating expenses ​ ​ 24,223 ​ ​ 23,763 ​ ​ 2,553 ​ ​ (2,553) ​ ​ 47,986 ​ Loss (gain) on sale of assets ​ ​ (447) ​ ​ — ​ ​ 6,036 ​ ​ (6,036) ​ ​ (447) ​ Total operating expenses ​ ​ 2,948,702 ​ ​ 240,841 ​ ​ 325,420 ​ ​ (325,420) ​ ​ 3,189,543 ​ Operating income (loss) ​ $ 383,737 ​ ​ (85,451) ​ ​ 456,181 ​ ​ (456,181) ​ ​ 298,286 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 58,986 ​ ​ — ​ ​ 77,825 ​ ​ (77,825) ​ ​ 58,986 ​ ​ 42 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nine Months Ended September 30, 2024 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliate Total Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 1,274,503 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,274,503 ​ Natural gas liquids sales ​ ​ 1,511,253 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,511,253 ​ Oil sales ​ ​ 180,899 ​ ​ — ​ ​ — ​ ​ — ​ ​ 180,899 ​ Commodity derivative fair value gains ​ ​ 22,229 ​ ​ — ​ ​ — ​ ​ — ​ ​ 22,229 ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 818,716 ​ ​ (818,716) ​ ​ — ​ Marketing ​ ​ — ​ ​ 145,098 ​ ​ — ​ ​ — ​ ​ 145,098 ​ Amortization of deferred revenue, VPP ​ ​ 20,289 ​ ​ — ​ ​ — ​ ​ — ​ ​ 20,289 ​ Other revenue and income ​ ​ 2,574 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,574 ​ Total revenue ​ ​ 3,011,747 ​ ​ 145,098 ​ ​ 818,716 ​ ​ (818,716) ​ ​ 3,156,845 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 88,477 ​ ​ — ​ ​ — ​ ​ — ​ ​ 88,477 ​ Gathering and compression ​ ​ 671,893 ​ ​ — ​ ​ 76,849 ​ ​ (76,849) ​ ​ 671,893 ​ Processing ​ ​ 802,349 ​ ​ — ​ ​ — ​ ​ — ​ ​ 802,349 ​ Transportation ​ ​ 546,664 ​ ​ — ​ ​ — ​ ​ — ​ ​ 546,664 ​ Water handling ​ ​ — ​ ​ — ​ ​ 85,202 ​ ​ (85,202) ​ ​ — ​ Production and ad valorem taxes ​ ​ 147,524 ​ ​ — ​ ​ — ​ ​ — ​ ​ 147,524 ​ Marketing ​ ​ — ​ ​ 192,764 ​ ​ — ​ ​ — ​ ​ 192,764 ​ Exploration ​ ​ 1,916 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,916 ​ General and administrative (excluding equity-based compensation) ​ ​ 120,624 ​ ​ — ​ ​ 32,441 ​ ​ (32,441) ​ ​ 120,624 ​ Equity-based compensation ​ ​ 49,293 ​ ​ — ​ ​ 32,871 ​ ​ (32,871) ​ ​ 49,293 ​ Depletion, depreciation and amortization ​ ​ 513,787 ​ ​ — ​ ​ 107,205 ​ ​ (107,205) ​ ​ 513,787 ​ Impairment of property and equipment ​ ​ 18,958 ​ ​ — ​ ​ 332 ​ ​ (332) ​ ​ 18,958 ​ Accretion of asset retirement obligations ​ ​ 2,554 ​ ​ — ​ ​ 140 ​ ​ (140) ​ ​ 2,554 ​ Loss (gain) on sale of assets ​ ​ (1,127) ​ ​ — ​ ​ 906 ​ ​ (906) ​ ​ (1,127) ​ Contract termination, loss contingency, settlements and other operating expenses ​ ​ 3,901 ​ ​ — ​ ​ 1,339 ​ ​ (1,339) ​ ​ 3,901 ​ Total operating expenses ​ ​ 2,966,813 ​ ​ 192,764 ​ ​ 337,285 ​ ​ (337,285) ​ ​ 3,159,577 ​ Operating income (loss) ​ $ 44,934 ​ ​ (47,666) ​ ​ 481,431 ​ ​ (481,431) ​ ​ (2,732) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 69,862 ​ ​ — ​ ​ 82,795 ​ ​ (82,795) ​ ​ 69,862 ​ ​ 43 Table of Contents Exploration and Production Segment The following table sets forth selected operating data of the exploration and production segment: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nine Months Ended ​ Amount of ​ ​ ​ ​ ​ ​ September 30, ​ Increase ​ Percent ​ ​ ​ 2023 2024 (Decrease) Change ​ ​ Production data (1) (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (Bcf) ​ ​ 606 ​ ​ 597 ​ ​ (9) ​ (1) % ​ C2 Ethane (MBbl) ​ ​ 19,251 ​ ​ 21,873 ​ ​ 2,622 ​ 14 % ​ C3+ NGLs (MBbl) ​ ​ 31,009 ​ ​ 31,871 ​ ​ 862 ​ 3 % ​ Oil (MBbl) ​ ​ 2,720 ​ ​ 2,843 ​ ​ 123 ​ 5 % ​ Combined (Bcfe) ​ ​ 924 ​ ​ 936 ​ ​ 12 ​ 1 % ​ Daily combined production (MMcfe/d) ​ ​ 3,383 ​ ​ 3,417 ​ ​ 34 ​ 1 % ​ Average prices before effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 2.68 ​ ​ 2.14 ​ ​ (0.54) ​ (20) % ​ C2 Ethane (per Bbl) (4) ​ $ 10.43 ​ ​ 8.56 ​ ​ (1.87) ​ (18) % ​ C3+ NGLs (per Bbl) ​ $ 37.89 ​ ​ 41.54 ​ ​ 3.65 ​ 10 % ​ Oil (per Bbl) ​ $ 63.38 ​ ​ 63.63 ​ ​ 0.25 ​ * ​ ​ Weighted Average Combined (per Mcfe) ​ $ 3.43 ​ ​ 3.17 ​ ​ (0.26) ​ (8) % ​ Average realized prices after effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 2.65 ​ ​ 2.15 ​ ​ (0.50) ​ (19) % ​ C2 Ethane (per Bbl) (4) ​ $ 10.43 ​ ​ 8.56 ​ ​ (1.87) ​ (18) % ​ C3+ NGLs (per Bbl) ​ $ 37.84 ​ ​ 41.68 ​ ​ 3.84 ​ 10 % ​ Oil (per Bbl) ​ $ 63.04 ​ ​ 63.49 ​ ​ 0.45 ​ 1 % ​ Weighted Average Combined (per Mcfe) ​ $ 3.41 ​ ​ 3.18 ​ ​ (0.23) ​ (7) % ​ Average costs (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 0.10 ​ ​ 0.09 ​ ​ (0.01) ​ (10) % ​ Gathering and compression ​ $ 0.69 ​ ​ 0.72 ​ ​ 0.03 ​ 4 % ​ Processing ​ $ 0.83 ​ ​ 0.86 ​ ​ 0.03 ​ 4 % ​ Transportation ​ $ 0.62 ​ ​ 0.58 ​ ​ (0.04) ​ (6) % ​ Production and ad valorem taxes ​ $ 0.13 ​ ​ 0.16 ​ ​ 0.03 ​ 23 % ​ Marketing expense, net ​ $ 0.07 ​ ​ 0.05 ​ ​ (0.02) ​ (29) % ​ General and administrative (excluding equity-based compensation) ​ $ 0.13 ​ ​ 0.13 ​ ​ — ​ * ​ ​ Depletion, depreciation, amortization and accretion ​ $ 0.56 ​ ​ 0.55 ​ ​ (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 (but do not include payments from the derivative monetizations in 2023), which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. (4) The average realized price for the nine months ended September 30, 2023 and 2024 includes $13 million and $2 million, respectively, of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives for the nine months ended September 30, 2023 and 2024 would have been $9.77 per Bbl and $8.48 per Bbl, respectively. ​ Natural gas sales . Revenues from sales of natural gas decreased from $1.6 billion for the nine months ended September 30, 2023 to $1.3 billion for the nine months ended September 30, 2024, a decrease of $0.3 billion, or 21%. Lower commodity prices (excluding the effects of derivative settlements) during the nine months ended September 30, 2024 accounted for an approximate $323 million decrease in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes). Lower natural gas production volumes accounted for an approximate $24 million decrease in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price). NGLs sales . Revenues from sales of NGLs increased from $1.4 billion for the nine months ended September 30, 2023 to $1.5 billion for the nine months ended September 30, 2024, an increase of $0.1 billion, or 10%. Higher commodity prices (excluding the effects of derivative settlements) during the nine months ended September 30, 2024 accounted for an approximate $76 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 $60 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price). 44 Table of Contents Oil sales . Revenues from sales of oil increased from $172 million for the nine months ended September 30, 2023 to $181 million for the nine months ended September 30, 2024, an increase of $9 million, or 5%. Higher oil prices, excluding the effects of derivative settlements, accounted for an approximate $1 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 during the nine months ended September 30, 2024 accounted for an approximate $8 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 variable price swap contracts, swaptions, basis swap contracts, call options and embedded put options. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations. For the nine months ended September 30, 2023 and 2024, our commodity hedges resulted in derivative fair value gains of $138 million and $22 million, respectively. For the nine months ended September 30, 2023, commodity derivative fair value gains included $17 million of cash payments on settled commodity derivative losses and a $202 million cash payment for the early settlement of our swaption. For the nine months ended September 30, 2024, commodity derivative fair value gains included $12 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. Additionally, substantially all of our production is currently unhedged for 2024 and beyond, which limits our exposure to volatility in the fair value of our derivative instruments related to commodity price changes in the future. Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP decreased from $23 million for the nine months ended September 30, 2023 to $20 million for the nine months ended September 30, 2024, a decrease of $3 million or 11%, primarily due to lower production volumes attributable to the VPP properties between periods. Amortization of the deferred revenues associated with the VPP are recognized as the production volumes are delivered at $1.61 per MMBtu over the contractual term. Lease operating expense . Lease operating expense decreased from $92 million, or $0.10 per Mcfe, for the nine months ended September 30, 2023 to $88 million, or $0.09 per Mcfe, for the nine months ended September 30, 2024, primarily due to lower water disposal costs and workover expense during the nine months ended September 30, 2024, partially offset by higher oilfield service costs between periods. Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense remained consistent at $2.0 billion for the nine months ended September 30, 2023 and 2024. This was primarily a result of the following: ● Gathering and compression costs on a per unit basis increased from $0.69 per Mcfe for the nine months ended September 30, 2023 to $0.72 per Mcfe for the nine months ended September 30, 2024, primarily due to the expiration of the growth incentive fee rebate program on December 31, 2023 and annual CPI-based adjustments between periods. During the nine months ended September 30, 2023, we earned fee rebates of $36 million under this program. ● Processing costs on a per unit basis increased from $0.83 per Mcfe for the nine months ended September 30, 2023 to $0.86 per Mcfe for the nine months ended September 30, 2024, primarily due to increased costs for NGLs processing and transportation, which includes an annual CPI-based adjustment during the first quarter of 2024 and higher NGLs transportation fees. ● Transportation costs on a per unit basis decreased from $0.62 per Mcfe for the nine months ended September 30, 2023 to $0.58 per Mcfe for the nine months ended September 30, 2024 primarily due to lower demand fees and lower fuel costs as a result of lower natural gas prices between periods. Production and ad valorem tax expense. Production and ad valorem taxes increased from $118 million for the nine months ended September 30, 2023 to $148 million for the nine months ended September 30, 2024, an increase of $30 million, or 25%, primarily due to higher ad valorem taxes and production volumes between periods, partially offset by lower natural gas prices during the nine months ended September 30, 2024. Production and ad valorem taxes as a percentage of natural gas revenues increased from 7% for the nine months ended September 30, 2023 to 12% for the nine months ended September 30, 45 Table of Contents 2024, primarily as a result of higher ad valorem taxes, which 2024 West Virginia ad valorem taxes are based on commodity prices during 2022. General and administrative expense . General and administrative expense (excluding equity-based compensation expense) decreased from $125 million for the nine months ended September 30, 2023 to $121 million for nine months ended September 30, 2024, a decrease of $4 million, or 3%, primarily due to lower professional service fees between periods. General and administrative expense on a per unit basis (excluding equity-based compensation) remained consistent at $0.13 per Mcfe for the nine months ended September 30, 2023 and 2024. Equity-based compensation expense . Non-cash equity-based compensation expense increased from $45 million for the nine months ended September 30, 2023 to $49 million for the nine months ended September 30, 2024, an increase of $4 million, or 10%. This increase was primarily due to RSU award expense attributable to awards granted in the fourth quarter of 2023 and first quarter of 2024, partially offset by lower PSU award expense between periods and equity-based awards granted in prior years that were fully vested between periods. See Note 9—Equity-Based Compensation to the unaudited condensed consolidated financial statements for more information. Depletion, depreciation and amortization expense. DD&A expense remained relatively consistent at $515 million, or $0.56 per Mcfe, and $514 million, or $0.55 per Mcfe, for the nine months ended September 30, 2023 and 2024, respectively. Impairment of property and equipment . Impairment of oil and gas properties decreased from $45 million for the nine months ended September 30, 2023 to $19 million for the nine months ended September 30, 2024, a decrease of $26 million, 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, settlements and other operating expenses . Contract termination, loss contingency, settlements and other operating expenses attributable to our exploration and production segment decreased from $24 million for the nine months ended September 30, 2023 to $4 million for the nine months ended September 30, 2024. This decrease was primarily due to a loss contingency recorded in the third quarter of 2023 and lower expense associated with the early termination of certain completion contracts between periods, partially offset by our receipt of 0.1 million shares of Antero Midstream common stock during the third quarter of 2024 as part of a judgment in a legal proceeding with an unaffiliated third-party. 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 $62 million, or $0.07 per Mcfe, for the nine months ended September 30, 2023 to $48 million, or $0.05 per Mcfe, for the nine months ended September 30, 2024, primarily due to lower firm transportation commitments between periods. M arketing revenue. Marketing revenue decreased from $155 million for the nine months ended September 30, 2023 to $145 million for the nine months ended September 30, 2024, a decrease of $10 million, or 7%. This fluctuation primarily resulted from the following: ● Natural gas marketing revenue decreased by $59 million between periods primarily due to lower natural gas marketing volumes and prices. Lower natural gas marketing volumes accounted for a $50 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower natural gas prices accounted for a $9 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). ● Oil marketing revenue increased by $45 million between periods primarily due to higher oil marketing volumes and prices. Higher oil marketing volumes accounted for a $35 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 $10 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). 46 Table of Contents ● NGLs marketing revenues were $4 million for the nine months ended September 30, 2024. There were no NGLs marketing revenues for the nine months ended September 30, 2023. Marketing expense. Marketing expense decreased from $217 million for the nine months ended September 30, 2023 to $193 million for the nine months ended September 30, 2024, a decrease of $24 million, or 11%. Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related to current excess firm capacity. The cost of third-party natural gas purchases decreased $47 million between periods, partially offset by increased oil and NGLs purchases of $38 million and $4 million, respectively. The total cost of third-party commodity purchases decreased primarily due to lower natural gas marketing volumes and prices between periods, partially offset by higher oil prices and marketing volumes during the nine months ended September 30, 2024. Firm transportation costs decreased $19 million from $82 million for the nine months ended September 30, 2023 to $63 million for the nine months ended September 30, 2024, primarily due to the reduction in firm transportation commitments between periods. Contract termination, loss contingency, settlements and other operating expenses . Contract termination, loss contingency, settlements and other operating expenses attributable to our marketing segment for the nine months ended September 30, 2023, relate to a $24 million payment for the early termination of our firm transportation commitment of 200,000 MMBtu per day on the Equitrans pipeline. Our marketing segment did not incur any contract termination, loss contingency, settlements and other operating expenses for the nine months ended September 30, 2024. Antero Midstream Segment Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $782 million for the nine months ended September 30, 2023 to $819 million for the nine months ended September 30, 2024, an increase of $37 million. This increase is primarily due to higher gathering and processing revenues of $66 million, partially offset by lower water handling revenues of $29 million. The increased gathering and processing revenues between periods is primarily a result of the expiration of the growth incentive fee rebate program on December 31, 2023, increased throughput and annual CPI-based gathering and compression rate adjustments between periods. The decreased water handling revenues between periods is primarily due to lower fresh water delivery volumes and lower water handling volumes that are billed at cost plus 3%, partially offset by higher blending volumes and an increased fresh water delivery rate due to an annual CPI-based adjustment during the nine months ended September 30, 2024. Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $325 million for the nine months ended September 30, 2023 to $337 million for the nine months ended September 30, 2024, an increase of $12 million. This increase is primarily due to higher general and administrative expense, including equity-based compensation expense, and depreciation expense between periods as well as lower gains on asset sale during the nine months ended September 30, 2024. Items Not Allocated to Segments Interest expense. Interest expense increased from $85 million for the nine months ended September 30, 2023 to $91 million for the nine months ended September 30, 2024, an increase of $6 million or 7%, primarily due to higher average Credit Facility borrowings between periods and higher benchmark interest rates during the nine months ended September 30, 2024. Income tax expense (benefit) . For the nine months ended September 30, 2023, we had income tax expense of $46 million, with an effective tax rate of 17%, related to our income before income taxes of $272 million. For the nine months ended September 30, 2024, we had an income tax benefit of $2 million, with an effective tax rate of 9%, related to our loss before income taxes of $25 million. The decrease in the effective tax rate between periods was primarily due to the effects of noncontrolling interests and our loss before income taxes during the nine months ended September 30, 2024. Capital Resources and Liquidity Sources and Uses of Cash Our primary sources of liquidity have been through net cash provided by operating activities, borrowings under our Credit Facility, issuances of debt and equity securities and additional contributions from our asset sales, including our drilling partnership . 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. 47 Table of Contents Based on strip prices as of September 30, 2024, we believe that net cash provided by operating activities and available borrowings under the Credit Facility will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures and commitments and contingencies for at least the next 12 months. Cash Flows The following table summarizes our cash flows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nine Months Ended September 30, ​ ​ ​ 2023 2024 Net cash provided by operating activities ​ $ 682,546 ​ ​ 571,286 ​ Net cash used in investing activities ​ ​ (914,137) ​ ​ (588,251) ​ Net cash provided by financing activities ​ ​ 231,591 ​ ​ 16,965 ​ Net increase in cash and cash equivalents ​ $ — ​ ​ — ​ ​ Operating activities. Net cash provided by operating activities was $682 million and $571 million for the nine months ended September 30, 2023 and 2024, respectively. Net cash provided by operating activities decreased between periods primarily due to lower natural gas prices, changes in working capital and higher interest expense, partially offset by lower net marketing expense and higher NGLs and oil revenues between periods and a $202 million payment for early settlement of our swaption agreement in the nine months ended September 30, 2023. 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 decreased from $914 million for the nine months ended September 30, 2023 to $588 million for the nine months ended September 30, 2024, primarily due to lower well completions between periods, decreased drilling activity as a result of a lower rig count during the nine months ended September 30, 2024 and decreased leasing activity during the nine months ended September 30, 2024. Financing activities. Net cash provided by financing activities decreased from $232 million for the nine months ended September 30, 2023 to $17 million for the nine months ended September 30, 2024. The decrease between periods is primarily due to lower net borrowings on our Credit Facility of $330 million and payment of debt issuance costs for our Unsecured Credit Facility of $6 million, partially offset by decreased share repurchases of $75 million and decreased distributions to the noncontrolling interests in Martica of $46 million between periods. 2024 Capital Budget and Capital Spending On February 14, 2024, we announced a net capital budget for 2024 of $725 million to $800 million. Our budget includes: a range of $650 million to $700 million for drilling and completion and $75 million to $100 million for leasehold expenditures. We do not budget for acquisitions. During 2024, we plan to complete 45 to 50 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. On October 30, 2024, we announced a decrease in our net capital budget for drilling and completion to a range of $640 million to $660 million to reflect operational efficiencies and the deferral of a drilled but uncompleted pad due to low natural gas prices. Our revised net capital budget for 2024 is $715 million to $760 million. For the three months ended September 30, 2024, our total consolidated capital expenditures were $172 million, including drilling and completion costs of $148 million, leasehold acquisitions of $23 million and other capital expenditures of $1 million. For the nine months ended September 30, 2024, our total consolidated capital expenditures were $578 million, including drilling and completion costs of $499 million, leasehold acquisitions of $69 million and other capital expenditures of $10 million. 48 Table of Contents 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 2023 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 2023 Form 10-K for information on our critical accounting estimates. We evaluate the carrying amount of our proved natural gas, NGLs and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount of our proved properties exceeds the estimated undiscounted future net cash flows (measured using futures prices at the balance sheet date), we further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeds the estimated fair value of the properties. Based on future prices as of September 30, 2024, 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 and nine months ended September 30, 2023 and 2024. We believe that the estimates and assumptions related to our undiscounted future net cash flows and the fair value of our proved properties are critical because different natural gas, NGLs and oil pricing, cost assumptions or discount rates, as applicable, may affect the recognition, timing and amount of an impairment and, if changed, could have a material effect on the Company's financial position and results of operations. New Accounting Pronouncements See Note 2—Summary of Significant Accounting Policies to the unaudited condensed consolidated financial statements for information on new accounting pronouncements. Off-Balance Sheet Arrangements See Note 13—Commitments to the unaudited condensed consolidated financial statements for further information on off balance sheet arrangements.