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, including the COVID-19 pandemic, 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 March 31, 2023, we held approximately 512,000 net acres in the Appalachian Basin. Market Conditions and Business Trends Commodity Markets Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Natural gas, NGLs and oil benchmark prices decreased significantly during the three months ended March 31, 2023 as compared to the same period of 2022. As a result, we experienced a decrease in price realizations during the three months ended March 31, 2023. 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 Russia-Ukraine conflict, 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. The following table details the average benchmark natural gas and oil prices: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended March 31, ​ ​ 2022 2023 ​ Henry Hub (1) ($/Mcf) ​ $ 4.95 ​ ​ 3.42 ​ West Texas Intermediate (2) ($/Bbl) ​ ​ 94.29 ​ ​ 76.13 ​ (1) NYMEX first of month average natural gas price. (2) Energy Information Administration calendar month average settled futures price. 31 Table of Contents 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 as we deem necessary 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 past levels, the percentage of our expected production that we hedge has decreased. For the three months ended March 31, 2022 and 2023, 36% and 2%, respectively, of our production was hedged through fixed price commodity swaps. Assuming our 2023 production is the same as our production in 2022, 1% of our production for 2023 will be hedged through fixed price commodity swaps. 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 March 31, 2023, our fixed price natural gas swap positions excluding Martica were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Commodity / Settlement Period Index Contracted Volume Price Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ April-December 2023 ​ Henry Hub ​ 12 Bcf ​ $ 2.37 /MMBtu ​ ​ As of March 31, 2023, 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 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ April-December 2023 ​ NYMEX to TCO ​ 14 Bcf ​ $ 0.525 /MMBtu ​ January-December 2024 ​ NYMEX to TCO ​ 18 Bcf ​ ​ 0.530 /MMBtu ​ ​ ​ ​ ​ 32 Bcf ​ ​ 0.53 /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 March 31, 2023, 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 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ April-December 2023 ​ Henry Hub ​ 15 Bcf ​ $ 2.466 /MMBtu ​ $ 2.466 /MMBtu ​ January-December 2024 ​ Henry Hub ​ 19 Bcf ​ ​ 2.477 /MMBtu ​ ​ 2.527 /MMBtu ​ January-December 2025 ​ Henry Hub ​ 16 Bcf ​ ​ 2.564 /MMBtu ​ ​ 2.614 /MMBtu ​ January-December 2026 ​ Henry Hub ​ 12 Bcf ​ ​ 2.629 /MMBtu ​ ​ 2.679 /MMBtu ​ ​ ​ ​ ​ 62 Bcf ​ ​ 2.525 /MMBtu ​ ​ 2.563 /MMBtu ​ ​ In addition, we had a swaption agreement, which entitled the counterparty the right, but not the obligation, to enter into a fixed price swap agreement for 156 Bcf at a price of $2.77 per MMBtu for the year ending December 31, 2024. In January 2023, we executed an early settlement of this swaption agreement and made a cash payment of $202 million, which was funded by cash flows from operations and borrowings under our Credit Facility. As of March 31, 2023, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of $70 million. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information. 32 Table of Contents 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 March 31, 2023, Martica’s fixed price natural gas, NGLs and oil swap positions were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Commodity / Settlement Period Index Contracted Volume Price ​ Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ April-December 2023 ​ Henry Hub ​ 9 Bcf ​ $ 2.35 /MMBtu ​ January-December 2024 ​ Henry Hub ​ 9 Bcf ​ ​ 2.33 /MMBtu ​ January-March 2025 ​ Henry Hub ​ 2 Bcf ​ ​ 2.53 /MMBtu ​ ​ ​ ​ ​ 20 Bcf ​ ​ 2.35 /MMBtu ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural Gasoline ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ April-December 2023 ​ Mont Belvieu Natural Gasoline-OPIS Non-TET ​ 66,080 Bbl ​ ​ 40.74 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ April-December 2023 ​ West Texas Intermediate ​ 24,102 Bbl ​ ​ 44.85 /Bbl ​ January-December 2024 ​ West Texas Intermediate ​ 15,699 Bbl ​ ​ 44.02 /Bbl ​ January-March 2025 ​ West Texas Intermediate ​ 3,535 Bbl ​ ​ 45.06 /Bbl ​ ​ ​ ​ ​ 43,336 Bbl ​ ​ 44.57 /Bbl ​ ​ As of March 31, 2023, the estimated fair value of Martica’s commodity derivative contracts was a net liability of $19 million. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information. Economic Indicators The economy is experiencing elevated inflation levels as a result of global supply and demand imbalances, where global demand continues to outpace current supplies. For example, the BLS Consumer Price Index (“CPI”) for all urban consumers increased 5% from March 2022 to March 2023 as compared to the Federal Reserve’s stated goal of 2%. In order to manage the inflation risk currently present in the United States’ economy, the Federal Reserve has utilized monetary policy in the form of interest rate increases in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis. The economy also continues to be impacted by the effects of global events and the aftermath of the COVID-19 pandemic, among other factors. 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. For example, our 2023 capital budget reflects an approximate 10% increase in service cost inflation as compared to the year ended December 31, 2022. 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 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. 33 Table of Contents Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2023 The operating results of our reportable segments were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended March 31, 2022 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliate Total Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 995,792 ​ ​ — ​ ​ — ​ ​ — ​ ​ 995,792 ​ Natural gas liquids sales ​ ​ 660,305 ​ ​ — ​ ​ — ​ ​ — ​ ​ 660,305 ​ Oil sales ​ ​ 63,294 ​ ​ — ​ ​ — ​ ​ — ​ ​ 63,294 ​ Commodity derivative fair value losses ​ ​ (1,011,380) ​ ​ — ​ ​ — ​ ​ — ​ ​ (1,011,380) ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 218,491 ​ ​ (218,491) ​ ​ — ​ Marketing ​ ​ — ​ ​ 69,038 ​ ​ — ​ ​ — ​ ​ 69,038 ​ Amortization of deferred revenue, VPP ​ ​ 9,272 ​ ​ — ​ ​ — ​ ​ — ​ ​ 9,272 ​ Other revenue and income ​ ​ 519 ​ ​ — ​ ​ — ​ ​ — ​ ​ 519 ​ Total revenue ​ ​ 717,802 ​ ​ 69,038 ​ ​ 218,491 ​ ​ (218,491) ​ ​ 786,840 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 17,780 ​ ​ — ​ ​ — ​ ​ — ​ ​ 17,780 ​ Gathering and compression ​ ​ 201,462 ​ ​ — ​ ​ 17,182 ​ ​ (17,182) ​ ​ 201,462 ​ Processing ​ ​ 190,601 ​ ​ — ​ ​ — ​ ​ — ​ ​ 190,601 ​ Transportation ​ ​ 198,215 ​ ​ — ​ ​ — ​ ​ — ​ ​ 198,215 ​ Water handling ​ ​ — ​ ​ — ​ ​ 24,830 ​ ​ (24,830) ​ ​ — ​ Production and ad valorem taxes ​ ​ 52,808 ​ ​ — ​ ​ — ​ ​ — ​ ​ 52,808 ​ Marketing ​ ​ — ​ ​ 98,896 ​ ​ — ​ ​ — ​ ​ 98,896 ​ Exploration and mine expenses ​ ​ 898 ​ ​ — ​ ​ — ​ ​ — ​ ​ 898 ​ General and administrative (excluding equity-based compensation) ​ ​ 31,042 ​ ​ — ​ ​ 15,099 ​ ​ (15,099) ​ ​ 31,042 ​ Equity-based compensation ​ ​ 4,649 ​ ​ — ​ ​ 2,832 ​ ​ (2,832) ​ ​ 4,649 ​ Depletion, depreciation and amortization ​ ​ 168,388 ​ ​ — ​ ​ 28,300 ​ ​ (28,300) ​ ​ 168,388 ​ Impairment of property and equipment ​ ​ 22,462 ​ ​ — ​ ​ ​ ​ ​ — ​ ​ 22,462 ​ Accretion of asset retirement obligations ​ ​ 2,444 ​ ​ — ​ ​ 64 ​ ​ (64) ​ ​ 2,444 ​ Contract termination and other operating expenses ​ ​ 8 ​ ​ — ​ ​ 1,148 ​ ​ (1,148) ​ ​ 8 ​ Loss (gain) on sale of assets ​ ​ 1,786 ​ ​ — ​ ​ (118) ​ ​ 118 ​ ​ 1,786 ​ Total operating expenses ​ ​ 892,543 ​ ​ 98,896 ​ ​ 89,337 ​ ​ (89,337) ​ ​ 991,439 ​ Operating income (loss) ​ $ (174,741) ​ ​ (29,858) ​ ​ 129,154 ​ ​ (129,154) ​ ​ (204,599) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 25,178 ​ ​ — ​ ​ 23,232 ​ ​ (23,232) ​ ​ 25,178 ​ ​ ​ 34 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended March 31, 2023 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliate Total ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 668,315 ​ ​ — ​ ​ — ​ ​ — ​ ​ 668,315 ​ Natural gas liquids sales ​ ​ 495,435 ​ ​ — ​ ​ — ​ ​ — ​ ​ 495,435 ​ Oil sales ​ ​ 51,811 ​ ​ — ​ ​ — ​ ​ — ​ ​ 51,811 ​ Commodity derivative fair value gains ​ ​ 126,192 ​ ​ — ​ ​ — ​ ​ — ​ ​ 126,192 ​ Gathering, compression and water handling ​ ​ — ​ ​ — ​ ​ 259,475 ​ ​ (259,475) ​ ​ — ​ Marketing ​ ​ — ​ ​ 58,529 ​ ​ — ​ ​ — ​ ​ 58,529 ​ Amortization of deferred revenue, VPP ​ ​ 7,533 ​ ​ — ​ ​ — ​ ​ — ​ ​ 7,533 ​ Other revenue and income ​ ​ 533 ​ ​ — ​ ​ — ​ ​ — ​ ​ 533 ​ Total revenue ​ ​ 1,349,819 ​ 58,529 ​ 259,475 ​ (259,475) ​ ​ 1,408,348 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 29,321 ​ ​ — ​ ​ — ​ ​ — ​ ​ 29,321 ​ Gathering and compression ​ ​ 212,604 ​ ​ — ​ ​ 24,118 ​ ​ (24,118) ​ ​ 212,604 ​ Processing ​ ​ 237,268 ​ ​ — ​ ​ . ​ ​ — ​ ​ 237,268 ​ Transportation ​ ​ 195,300 ​ ​ — ​ ​ — ​ ​ — ​ ​ 195,300 ​ Water handling ​ ​ — ​ ​ — ​ ​ 33,755 ​ ​ (33,755) ​ ​ — ​ Production and ad valorem taxes ​ ​ 49,276 ​ ​ — ​ ​ — ​ ​ — ​ ​ 49,276 ​ Marketing ​ ​ — ​ ​ 81,361 ​ ​ — ​ ​ — ​ ​ 81,361 ​ Exploration and mine expenses ​ ​ 763 ​ ​ — ​ ​ — ​ ​ — ​ ​ 763 ​ General and administrative (excluding equity-based compensation) ​ ​ 44,243 ​ ​ — ​ ​ 11,020 ​ ​ (11,020) ​ ​ 44,243 ​ Equity-based compensation ​ ​ 13,018 ​ ​ — ​ ​ 6,327 ​ ​ (6,327) ​ ​ 13,018 ​ Depletion, depreciation and amortization ​ ​ 167,582 ​ ​ — ​ ​ 35,196 ​ ​ (35,196) ​ ​ 167,582 ​ Impairment of property and equipment ​ ​ 15,560 ​ ​ — ​ ​ — ​ ​ — ​ ​ 15,560 ​ Accretion of asset retirement obligations ​ ​ 878 ​ ​ — ​ ​ 44 ​ ​ (44) ​ ​ 878 ​ Gain on sale of assets ​ ​ (91) ​ ​ — ​ ​ (245) ​ ​ 245 ​ ​ (91) ​ Contract termination and other operating expenses ​ ​ 6,012 ​ ​ 23,763 ​ ​ 915 ​ ​ (915) ​ ​ 29,775 ​ Total operating expenses ​ ​ 971,734 ​ 105,124 ​ 111,130 ​ (111,130) ​ ​ 1,076,858 ​ Operating income (loss) ​ $ 378,085 ​ ​ (46,595) ​ ​ 148,345 ​ ​ (148,345) ​ ​ 331,490 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 17,681 ​ ​ — ​ ​ 24,456 ​ ​ (24,456) ​ ​ 17,681 ​ ​ ​ 35 Table of Contents Exploration and Production Segment The following table sets forth selected operating data of the exploration and production segment: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Amount of ​ ​ ​ ​ ​ ​ Three Months Ended March 31, ​ Increase ​ Percent ​ ​ ​ 2022 2023 (Decrease) Change ​ ​ Production data (1) (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (Bcf) ​ ​ 199 ​ ​ 194 ​ ​ (5) ​ (3) % ​ C2 Ethane (MBbl) ​ ​ 4,005 ​ ​ 6,141 ​ ​ 2,136 ​ 53 % ​ C3+ NGLs (MBbl) ​ ​ 9,638 ​ ​ 9,857 ​ ​ 219 ​ 2 % ​ Oil (MBbl) ​ ​ 724 ​ ​ 831 ​ ​ 107 ​ 15 % ​ Combined (Bcfe) ​ ​ 285 ​ ​ 295 ​ ​ 10 ​ 4 % ​ Daily combined production (MMcfe/d) ​ ​ 3,165 ​ ​ 3,274 ​ ​ 109 ​ 3 % ​ Average prices before effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 5.01 ​ ​ 3.45 ​ ​ (1.56) ​ (31) % ​ C2 Ethane (per Bbl) (4) ​ $ 16.74 ​ ​ 11.73 ​ ​ (5.01) ​ (30) % ​ C3+ NGLs (per Bbl) ​ $ 61.55 ​ ​ 42.95 ​ ​ (18.60) ​ (30) % ​ Oil (per Bbl) ​ $ 87.45 ​ ​ 62.35 ​ ​ (25.10) ​ (29) % ​ Weighted Average Combined (per Mcfe) ​ $ 6.04 ​ ​ 4.13 ​ ​ (1.91) ​ (32) % ​ Average realized prices after effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 3.60 ​ ​ 3.38 ​ ​ (0.22) ​ (6) % ​ C2 Ethane (per Bbl) (4) ​ $ 16.63 ​ ​ 11.73 ​ ​ (4.90) ​ (29) % ​ C3+ NGLs (per Bbl) ​ $ 61.14 ​ ​ 42.89 ​ ​ (18.25) ​ (30) % ​ Oil (per Bbl) ​ $ 86.76 ​ ​ 61.90 ​ ​ (24.86) ​ (29) % ​ Weighted Average Combined (per Mcfe) ​ $ 5.03 ​ ​ 4.08 ​ ​ (0.95) ​ (19) % ​ Average costs (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 0.06 ​ ​ 0.10 ​ ​ 0.04 ​ 67 % ​ Gathering and compression ​ $ 0.71 ​ ​ 0.72 ​ ​ 0.01 ​ 1 % ​ Processing ​ $ 0.67 ​ ​ 0.81 ​ ​ 0.14 ​ 21 % ​ Transportation ​ $ 0.70 ​ ​ 0.66 ​ ​ (0.04) ​ (6) % ​ Production and ad valorem taxes ​ $ 0.19 ​ ​ 0.17 ​ ​ (0.02) ​ (11) % ​ Marketing expense, net ​ $ 0.10 ​ ​ 0.08 ​ ​ (0.02) ​ (20) % ​ Depletion, depreciation, amortization and accretion ​ $ 0.60 ​ ​ 0.57 ​ ​ (0.03) ​ (5) % ​ General and administrative (excluding equity-based compensation) ​ $ 0.11 ​ ​ 0.15 ​ ​ 0.04 ​ 36 % ​ (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 March 31, 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 would have been $10.76 per Bbl. ​ Natural gas sales . Revenues from sales of natural gas decreased from $996 million for the three months ended March 31, 2022 to $668 million for the three months ended March 31, 2023, a decrease of $328 million, or 33%. Lower commodity prices (excluding the effects of derivative settlements) during the three months ended March 31, 2023 accounted for an approximate $303 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 $25 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 decreased from $660 million for the three months ended March 31, 2022 to $495 million for the three months ended March 31, 2023, a decrease of $165 million, or 25%. Lower commodity prices (excluding the effects of derivative settlements) during the three months ended March 31, 2023 accounted for an approximate $214 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year 36 Table of Contents production volumes). Higher NGLs production volumes accounted for an approximate $49 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price). Oil sales . Revenues from sales of oil decreased from $63 million for the three months ended March 31, 2022 to $52 million for the three months ended March 31, 2023, a decrease of $11 million, or 18%. Lower oil prices, excluding the effects of derivative settlements, accounted for an approximate $21 million decrease in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes). Higher oil production volumes during the three months ended March 31, 2023 accounted for an approximate $10 million increase in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price). Commodity derivative fair value gains (losses). Our commodity derivatives included 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 three months ended March 31, 2022 and 2023, our commodity hedges resulted in derivative fair value losses of $1.0 billion and fair value gains of $126 million, respectively. For the three months ended March 31, 2022, commodity derivative fair value losses included $285 million of cash payments on commodity settled derivatives losses. For the three months ended March 31, 2023, commodity derivative fair value gains included $14 million of cash payments on commodity derivative losses and $202 million cash payment for the early settlement of our swaption. 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 2023 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 $9 million for the three months ended March 31, 2022 to $8 million for the three months ended March 31, 2023, a decrease of $1 million or 19%, primarily due to lower production volumes attributable to the VPP properties between periods. Under the terms of the agreement, the production volumes are delivered at $1.61 per MMBtu over the contractual term. Lease operating expense . Lease operating expense increased from $18 million, or $0.06 per Mcfe, for the three months ended March 31, 2022 to $29 million, or $0.10 per Mcfe for the three months ended March 31, 2023, an increase of $11 million or $0.04 per Mcfe, primarily due to higher oilfield service and produced water handling costs. Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense increased from $590 million for the three months ended March 31, 2022 to $645 million for three months ended March 31, 2023, an increase of $55 million, or 9%. This fluctuation primarily resulted from the following: ● Gathering and compression costs on a per unit basis remained relatively consistent at $0.71 and $0.72 per Mcfe for the three months ended March 31, 2022 and 2023, respectively. ● Processing costs on a per unit basis increased from $0.67 per Mcfe for the three months ended March 31, 2022 to $0.81 per Mcfe for the three months ended March 31, 2023, primarily due to increased costs for NGLs processing and transportation, which include annual CPI-based and commodity based adjustments, as well as higher terminal fees and ethane transportation. ● Transportation costs on a per unit basis decreased from $0.70 per Mcfe for the three months ended March 31, 2022 to $0.66 per Mcfe for the three months ended March 31, 2023 primarily due to lower fuel costs as a result of lower commodity prices between periods. Production and ad valorem tax expense. Production and ad valorem taxes decreased from $53 million for the three months ended March 31, 2022 to $49 million for the three months ended March 31, 2023, a decrease of $4 million, or 7%, primarily due to lower commodity prices between periods, partially offset by higher production volumes between periods. Production and ad valorem taxes as a percentage of natural gas revenues increased from 5.3% for the three months ended March 31, 2022 to 7.4% for the three months ended March 31, 2023 primarily as a result of higher ad valorem taxes, which 2023 ad valorem taxes are based on commodity prices during 2022. 37 Table of Contents General and administrative expense . General and administrative expense (excluding equity-based compensation expense) increased from $31 million for the three months ended March 31, 2022 to $44 million for the three months ended March 31, 2023, an increase of $13 million, or 43%, primarily due to higher salary and wage expense, professional service fees, office operating costs and software license costs between periods. We had 521 and 599 employees as of three months ended March 31, 2022 and 2023, respectively. General and administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.11 per Mcfe for the three months ended March 31, 2022 to $0.15 per Mcfe for the three months ended March 31, 2023 as a result of our higher overall general and administrative costs, partially offset by increased production volumes between periods. Equity-based compensation expense . Noncash equity-based compensation expense increased from $5 million for the three months ended March 31, 2022 to $13 million for the three months ended March 31, 2023, an increase of $8 million, primarily due to an increase in the annual equity awards granted during the fourth quarter of 2022 and first quarter of 2023 as compared to prior years, which were temporarily and significantly reduced during 2020 and supplemented by our cash awards program. Our equity awards vest over three or four year service periods, and our equity incentive program began returning to normal levels in 2021. See Note 9—Equity Based Compensation and Cash Awards to the unaudited condensed consolidated financial statements for more information on equity-based compensation awards. Depletion, depreciation and amortization expense (“DD&A expense”) . DD&A expense remained relatively consistent at $168 million, or $0.60 per Mcfe, and $168 million, or $0.57 per Mcfe, for the three months ended March 31, 2022 and 2023, respectively. This decrease in DD&A expense per Mcfe between periods was primarily due to higher reserve volumes during the three months ended March 31, 2023. Impairment of oil and gas properties . Impairment of oil and gas properties decreased from $22 million for the three months ended March 31, 2022 to $16 million for the three months ended March 31, 2023, a decrease of $6 million, or 31%, primarily related 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. 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 (calculated as marketing revenues less marketing expense) decreased from $30 million, or $0.10 per Mcfe, for the three months ended March 31, 2022 to $23 million, or $0.08 per Mcfe, for the three months ended March 31, 2023, primarily due to lower firm transportation commitments between periods. Marketing revenue. Marketing revenue decreased from $69 million for the three months ended March 31, 2022 to $59 million for the three months ended March 31, 2023, a decrease of $10 million, or 15%, primarily due to decreased commodity prices and ethane marketing volumes between periods, partially offset by higher natural gas and oil marketing volumes. Lower ethane marketing volumes accounted for a $13 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), partially offset by increased oil marketing revenues of $3 million. Higher oil marketing volumes accounted for a $8 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 an approximate $5 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). Natural gas marketing revenue remained relatively consistent between periods with higher marketing volumes during the three months ended March 31, 2023 being fully offset by lower commodity prices during the same period. Marketing expense. Marketing expense decreased from $99 million for the three months ended March 31, 2022 to $81 million for the three months ended March 31, 2023, a decrease of $18 million, or 18%. Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related to current excess firm capacity. The cost of third-party purchases decreased $6 million primarily due to lower commodity prices between periods, partially offset by higher natural gas and oil marketing volumes. Firm transportation costs were $32 million for the three months ended March 31, 2022 and $20 million for the three months ended March 31, 2023, a decrease of $12 million due to the reduction in firm transportation commitments and higher third-party marketed volumes between periods. Contract termination expense . Our marketing segment did not incur any contract termination expense for the three months ended March 31, 2022. Contract termination expense attributable to our marketing segment for the three months ended 38 Table of Contents March 31, 2023, is due to a $24 million payment for the early termination of our firm transportation commitment of 200,000 MMBtu per day on the Equitrans pipeline. Antero Midstream Segment Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $218 million for the three months ended March 31, 2022 to $259 million for the three months ended March 31, 2023, an increase of $41 million, primarily due to increased throughput, fresh water delivery volumes and other fluid handling volumes between periods as well as higher low pressure, compression, high pressure and water handling fees primarily as a result of an annual CPI-based adjustments. Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $89 million for the three months ended March 31, 2022 to $111 million for the three months ended March 31, 2023, an increase of $22 million, primarily due to increased direct operating costs and depreciation expense during the three months ended March 31, 2023, partially offset by lower general and administrative costs between periods Direct operating costs increased between periods primarily as a result of 12 compressors that were acquired during the fourth quarter of 2022 and higher water trucking expense between periods. The increase in depreciation expense is primarily a result of a phased early retirement of an underutilized compressor station, which allows Antero Midstream to relocate and reuse the compressor units and equipment to (i) expand an existing compressor station and/or (ii) contribute to a new compressor station. There are certain costs associated with the underutilized compressor station that cannot be relocated or reused that will be depreciated over the first half of 2023. Antero Midstream also had incremental depreciation expense related to asset acquisitions completed during the fourth quarter of 2022 and gathering, compression and water handling assets placed in service between periods. Items Not Allocated to Segments Interest expense. Interest expense decreased from $38 million for the three months ended March 31, 2022 to $26 million for the three months ended March 31, 2023, a decrease of $12 million or 32%, primarily due to the reduction in debt as a result of the repurchase of certain of our unsecured senior notes between periods, partially offset by higher Credit Facility borrowings and benchmark interest rates during the three months ended March 31, 2023. Loss on early extinguishment of debt. During the three months ended March 31, 2022, we redeemed the remaining $585 million aggregate principal amount of our 2025 Notes at a redemption price of 101.25% of par, plus accrued and unpaid interest, which resulted in a loss on early debt extinguishment of $11 million. There were no debt redemptions or repurchases during the three months ended March 31, 2023. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. ​ Income tax benefit (expense) . For the three months ended March 31, 2022, we had an income tax benefit of $53 million, with an effective tax rate of 23%, due to a loss before income taxes of $230 million. For the three months ended March 31, 2023, we had income tax expense of $62 million, with an effective tax rate of 19%, due to income before income taxes of $323 million. The decrease in the effective tax rate between periods was primarily due the impact of changes in state apportionment and a reduction to Pennsylvania’s corporate income tax rate enacted in the third quarter of 2022. 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 program, 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 growing 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, 2023, 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. 39 Table of Contents Cash Flows The following table summarizes our cash flows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended March 31, ​ ​ ​ 2022 2023 Net cash provided by operating activities ​ $ 565,673 ​ ​ 343,902 ​ Net cash used in investing activities ​ ​ (215,117) ​ ​ (350,804) ​ Net cash provided by (used in) financing activities ​ ​ (350,556) ​ ​ 6,902 ​ Net increase in cash and cash equivalents ​ $ — ​ ​ — ​ ​ Operating activities. Net cash provided by operating activities was $566 million and $344 million for the three months ended March 31, 2022 and 2023, respectively. Net cash provided by operating activities decreased primarily due to lower commodity prices, a $202 million payment for early settlement of our swaption agreement and increased gathering compression, processing and transportation expenses, lease operating expenses, general and administrative expenses (excluding equity-based compensation expense) and contract termination expense, partially offset by increased production and decreased net marketing expense 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 $215 million for the three months ended March 31, 2022 to $351 million for the three months ended March 31, 2023, primarily due to an increase in capital expenditures of $135 million between periods. The increase in capital expenditures between periods is primarily due to increased completions activity, higher fresh water delivery and drilling costs and increased land purchases between periods. Financing activities . Net cash flows used in financing activities for the three months ended March 31, 2022 were $351 million, as compared to $7 million in net cash flows provided by financing activities for the three months ended March 31, 2023. During the three months ended March 31, 2022, we (i) redeemed $585 million aggregate principal amount of our 2025 Notes at 101.25% of the principal amount thereof, (ii) repurchased 4 million shares of our common stock at a total cost of $100 million, (iii) distributed $36 million to the noncontrolling interests in Martica and (iv) paid $10 million in employee withholding taxes for vested equity-based awards. Additionally, we borrowed $388 million, net, on our Credit Facility during the three months ended March 31, 2022. During the three months ended March 31, 2023, we borrowed $145 million, net, on our Credit Facility, partially offset by the repurchase of 3 million shares of our common stock at a total cost of $75 million, distributions to the noncontrolling interests in Martica of $51 million and payments for employee withholding taxes for vested equity-based awards of $11 million. 2023 Capital Budget and Capital Spending On February 15, 2023, we announced a net capital budget for 2023 of $1.025 billion to $1.075 billion. Our budget includes: a range of $875 million to $925 million for drilling and completion and $150 million for leasehold expenditures. We do not budget for acquisitions. During 2023, we plan to complete 60 to 65 net horizontal wells in the Appalachian Basin. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices. For the three months ended March 31, 2023, our total consolidated capital expenditures were $342 million, including drilling and completion costs of $267 million, leasehold acquisitions of $72 million, and other capital expenditures of $3 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 2022 Form 10-K for information on our senior notes. 40 Table of Contents Critical Accounting Policies and 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. 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 and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that 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 carrying values of assets and liabilities 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. Our more significant accounting policies and estimates include the successful efforts method of accounting for our production activities, estimates of natural gas, NGLs and oil reserve quantities and standardized measure of future cash flows and impairment of proved properties. We provide an expanded discussion of our more significant accounting policies, estimates and judgments in the 2022 Form 10-K. We believe these accounting policies reflect our more significant estimates and assumptions used in the preparation of our unaudited condensed consolidated financial statements. Also, see Note 2—Summary of Significant Accounting Policies to the consolidated financial statements, included in the 2022 Form 10-K, for a discussion of additional accounting policies and estimates made by management. We evaluate the carrying amount of our proved natural gas, NGLs and oil properties for impairment for the Utica and Marcellus Shale properties, by property, when events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. Under GAAP for successful efforts accounting, if the carrying amount exceeds the estimated undiscounted future net cash flows (measured using future prices), we estimate the fair value of our proved properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties. Based on future prices as of March 31, 2023, 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, 2022 and 2023. Estimated undiscounted future net cash flows are sensitive to commodity price swings and a decline in prices could result in the carrying amount exceeding the estimated undiscounted future net cash flows at the end of a future reporting period, which would require us to further evaluate if an impairment charge would be necessary. If future prices decline from March 31, 2023, the fair value of our properties may be below their carrying amounts and an impairment charge may be necessary. We are unable, however, to predict future commodity prices with any reasonable certainty. 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.