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, 2022, we held approximately 501,000 net acres of rich gas and dry gas properties located in the Appalachian Basin in West Virginia and Ohio. Our corporate headquarters are in Denver, Colorado. COVID-19 Pandemic Since the start of the COVID-19 pandemic, governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, among other actions, which caused a significant decrease in activity in the global economy and the demand for oil and to a lesser extent natural gas and NGLs. As vaccines have become widely available, social distancing guidelines, travel restrictions and stay-at-home orders have eased, activity in the global economy has increased and demand for oil, natural gas and NGLs and related commodity pricing, has improved . However, new variants of the virus could cause further commodity market volatility and resulting financial market instability, and these are variables beyond our control that may adversely impact our generation of funds from operating cash flows, distributions from unconsolidated affiliate, available borrowings under our Credit Facility (defined below in “—Capital Resources and Liquidity—Debt Agreements—Senior Secured Revolving Credit Facility”) and our ability to access the capital markets. We have continued to operate throughout the pandemic, in some cases subject to federal, state and local regulations, and we are taking steps to protect the health and safety of our workers. We have implemented protocols to reduce the risk of an outbreak within our field operations, and these protocols have not reduced our production and throughput in a significant manner. A substantial portion of our non-field level employees currently operate in remote work from home arrangements, and we have been able to maintain a consistent level of effectiveness through these arrangements, including maintaining our day-to-day operations, our financial reporting systems and our internal control over financial reporting. We continue to monitor the COVID-19 environment in order to (i) protect the health and safety of our employees and contract workers and (ii) to determine when a return to in-office working arrangements will be appropriate. Our supply chain has not experienced any significant interruptions as a result of the COVID-19 pandemic. The lack of a market or available storage for any one NGL product or oil could result in our having to delay or discontinue well completions and 35 Table of Contents commercial production or shut in production for other products because we cannot curtail the production of individual products in a meaningful way without reducing production of other products. Potential impacts of these constraints may include partial shut-in of production, although we are not able to determine the extent of shut-ins or for how long they may last. However, because some of our wells produce rich gas, which is processed, and some produce dry gas, which does not require processing, we can change the mix of products that we produce and wells that we complete to adjust our production to address takeaway capacity constraints for certain products. For example, we can shut-in rich gas wells and still produce from our dry gas wells if processing or storage capacity of NGL products becomes limited or constrained. Prior to the COVID-19 pandemic, we had developed a diverse set of buyers and destinations, as well as in-field and off-site storage capacity for our condensate volumes. As a result of the pandemic, we have expanded our customer base and our condensate storage capacity within the Appalachian Basin. Our natural gas, NGLs and oil producing properties are located in the liquids-rich Appalachian Basin. We maintain a hedging program designed to mitigate volatility in commodity prices and to protect certain of our expected future cash flows for our future operations and capital spending plans. All of our hedges are financial hedges and do not have physical delivery requirements. As such, any decreases in anticipated production, such as a result of decreased development activity, would not impact our ability to realize the benefits of or reduce the obligations for our hedges. For the year ending December 31, 2022, we have hedged through fixed price contracts the sale of 313 Bcf of natural gas at a weighted average price of $2.49 per MMBtu and basis swaps for 17 Bcf with a weighted average pricing differential of $0.515 per MMBtu. In addition, our borrowing capacity is directly impacted by the amount of financial assurance that we are required to provide in the form of letters of credit to third parties, primarily pipeline capacity providers. The amount of financial assurance we provided has not increased during the COVID-19 pandemic and, thus far, we have not experienced any losses due to counterparty risk. However, our ability to limit any additional financial assurance we are required to provide, as well as to protect ourselves from the counterparty risk of our financial hedges, may be limited in the future. As of March 31, 2022, we had $388 million of borrowings under our Credit Facility (defined below in “—Capital Resources and Liquidity—Sources and Uses of Cash”) and had outstanding letters of credit of $531 million . See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements and “—Capital Resources and Liquidity—Debt Agreements— Senior Secured Revolving Credit Facility.” Since the onset of the COVID-19 pandemic, we have timely serviced our debt and other obligations. As the global economy continues to recover from the effects of the COVID-19 pandemic, economic indicators have continued to strengthen. However, the economy has begun to experience elevated inflation levels as a result of global supply and demand imbalances. For example, the United States Bureau of Labor and Statistics (“BLS”) Consumer Price Index (“CPI”) for all urban consumers increased 9% from March 2021 to March 2022 as compared to the average historical 10-year rate of 2%. Additionally, employment activity has also begun to strengthen as demonstrated by the United States BLS unemployment rate declining from a high of 15% in April 2020 to 4% in March 2022. Inflationary pressures and labor shortages could result in increases to our operating and capital costs that are not fixed, renegotiation of contracts and/or supply agreements and higher labor costs, among others. These economic variables are beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows. Financing Highlights Debt Repurchase Program During the three months ended March 31, 2022, we fully redeemed the remaining $585 million of our remaining outstanding 5.00% senior notes due March 1, 2025 (the “2025 Notes”) at a redemption price of 101.25% of the principal amount thereof, plus accrued and unpaid interest. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. 36 Table of Contents Share Repurchase Program On February 15, 2022, our Board of Directors authorized a share repurchase program that allows us to repurchase up to $1.0 billion of outstanding common stock. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by us at our discretion and will depend on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. During the three months ended March 31, 2022 , we repurchased 3.7 million shares of our common stock at a total cost of $100 million. Hedge Position (Excluding Martica) We are exposed to certain risks relating to our ongoing business operations, and we use derivative instruments to manage our commodity price risk. In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. The table below excludes derivative instruments attributable to Martica, our consolidated variable interest entity (“VIE”), since all gains or losses from such contracts are fully attributable to the noncontrolling interests in Martica. As of March 31, 2022, our fixed price natural gas, oil and NGL swap positions excluding Martica were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Commodity / Settlement Period Index Contracted Volume Price Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ April-December 2022 ​ Henry Hub ​ 313 Bcf ​ $ 2.49 /MMBtu ​ January-December 2023 ​ Henry Hub ​ 16 Bcf ​ ​ 2.37 /MMBtu ​ ​ ​ ​ ​ 329 Bcf ​ ​ 2.49 /MMBtu ​ ​ In addition, we have a swaption agreement, which entitles the counterparty the right, but not the obligation, to enter into a fixed price swap agreement for approximately 156 Bcf at a price of $2.77 per MMBtu for the year ending December 31, 2024. As of March 31, 2022, our natural gas basis swap positions, which 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 2022 ​ NYMEX to TCO ​ 17 Bcf ​ $ 0.515 /MMBtu ​ January-December 2023 ​ NYMEX to TCO ​ 18 Bcf ​ ​ 0.525 /MMBtu ​ January-December 2024 ​ NYMEX to TCO ​ 18 Bcf ​ ​ 0.530 /MMBtu ​ ​ ​ ​ ​ 53 Bcf ​ ​ 0.524 /MMBtu ​ ​ As of March 31, 2022, we also had an embedded put option tied to NYMEX pricing for the production volumes associated with our retained interest in the VPP (as defined below) properties of 83 Bcf remaining through December 31, 2026 at a weighted average strike price of $2.54 per MMBtu. We maintain a hedging program designed to mitigate volatility in commodity prices and to protect certain of our expected future cash flows for our future operations and capital spending plans. As of March 31, 2022, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of approximately $1.4 billion. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information. 37 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 and treatment 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. Three Months Ended March 31, 2021 Compared to March 31, 2022 The operating results of our reportable segments were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended March 31, 2021 ​ ​ ​ ​ ​ ​ ​ ​ ​ Elimination of ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity Method ​ Intersegment ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Transactions and ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliates Total ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 720,369 ​ ​ — ​ ​ — ​ ​ — ​ ​ 720,369 ​ Natural gas liquids sales ​ ​ 440,319 ​ ​ — ​ ​ — ​ ​ — ​ ​ 440,319 ​ Oil sales ​ ​ 44,686 ​ ​ — ​ ​ — ​ ​ — ​ ​ 44,686 ​ Commodity derivative fair value losses ​ ​ (177,756) ​ ​ — ​ ​ — ​ ​ — ​ ​ (177,756) ​ Gathering, compression, water handling and treatment ​ ​ — ​ ​ — ​ ​ 241,789 ​ ​ (241,789) ​ ​ — ​ Marketing ​ ​ — ​ ​ 164,790 ​ ​ — ​ ​ — ​ ​ 164,790 ​ Amortization of deferred revenue, VPP ​ ​ 11,150 ​ ​ — ​ ​ — ​ ​ — ​ ​ 11,150 ​ Other income (loss) ​ 640 ​ ​ — ​ ​ (17,668) ​ ​ 17,668 ​ ​ 640 ​ Total revenue ​ $ 1,039,408 ​ ​ 164,790 ​ ​ 224,121 ​ ​ (224,121) ​ ​ 1,204,198 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 24,547 ​ ​ — ​ ​ — ​ ​ — ​ ​ 24,547 ​ Gathering and compression ​ ​ 220,288 ​ ​ — ​ ​ 39,314 ​ ​ (39,314) ​ ​ 220,288 ​ Processing ​ ​ 184,320 ​ ​ — ​ ​ — ​ ​ — ​ ​ 184,320 ​ Transportation ​ ​ 200,469 ​ ​ — ​ ​ — ​ ​ — ​ ​ 200,469 ​ Production and ad valorem taxes ​ ​ 44,697 ​ ​ — ​ ​ — ​ ​ — ​ ​ 44,697 ​ Marketing ​ ​ — ​ ​ 162,077 ​ ​ — ​ ​ — ​ ​ 162,077 ​ Exploration ​ ​ 219 ​ ​ — ​ ​ — ​ ​ — ​ ​ 219 ​ General and administrative (excluding equity-based compensation) ​ ​ 38,432 ​ ​ — ​ ​ 13,918 ​ ​ (13,918) ​ ​ 38,432 ​ Equity-based compensation ​ ​ 5,642 ​ ​ — ​ ​ 4,012 ​ ​ (4,012) ​ ​ 5,642 ​ Depletion, depreciation, and amortization ​ ​ 194,026 ​ ​ — ​ ​ 26,850 ​ ​ (26,850) ​ ​ 194,026 ​ Impairment of oil and gas properties ​ ​ 34,062 ​ ​ — ​ ​ — ​ ​ — ​ ​ 34,062 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 1,379 ​ ​ (1,379) ​ ​ — ​ Accretion of asset retirement obligations ​ ​ 788 ​ ​ — ​ ​ 119 ​ ​ (119) ​ ​ 788 ​ Contract termination and other expenses ​ ​ 91 ​ ​ — ​ ​ 4,942 ​ ​ (4,942) ​ ​ 91 ​ Total operating expenses ​ ​ 947,581 ​ ​ 162,077 ​ ​ 90,534 ​ ​ (90,534) ​ ​ 1,109,658 ​ Operating income ​ $ 91,827 ​ ​ 2,713 ​ ​ 133,587 ​ ​ (133,587) ​ ​ 94,540 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 18,694 ​ ​ — ​ ​ 20,744 ​ ​ (20,744) ​ ​ 18,694 ​ ​ ​ 38 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended March 31, 2022 ​ ​ ​ ​ ​ ​ ​ ​ ​ Elimination of ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity Method ​ Intersegment ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Transactions and ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliates 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, water handling and treatment ​ ​ — ​ ​ — ​ ​ 236,159 ​ ​ (236,159) ​ ​ — ​ Marketing ​ ​ — ​ ​ 69,038 ​ ​ — ​ ​ — ​ ​ 69,038 ​ Amortization of deferred revenue, VPP ​ ​ 9,272 ​ ​ — ​ ​ — ​ ​ — ​ ​ 9,272 ​ Other income (loss) ​ 519 ​ ​ — ​ ​ (17,668) ​ ​ 17,668 ​ ​ 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 ​ ​ — ​ ​ 42,012 ​ ​ (42,012) ​ ​ 201,462 ​ Processing ​ ​ 190,601 ​ ​ — ​ ​ — ​ ​ — ​ ​ 190,601 ​ Transportation ​ ​ 198,215 ​ ​ — ​ ​ — ​ ​ — ​ ​ 198,215 ​ Production and ad valorem taxes ​ ​ 52,808 ​ ​ — ​ ​ — ​ ​ — ​ ​ 52,808 ​ Marketing ​ ​ — ​ ​ 98,896 ​ ​ — ​ ​ — ​ ​ 98,896 ​ Exploration ​ ​ 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 oil and gas properties ​ ​ 22,462 ​ ​ — ​ ​ — ​ ​ — ​ ​ 22,462 ​ Accretion of asset retirement obligations ​ ​ 2,444 ​ ​ — ​ ​ 64 ​ ​ (64) ​ ​ 2,444 ​ Contract termination and other 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 ​ ​ ​ 39 Table of Contents Exploration and Production Segment The following table sets forth selected operating data of the exploration and production segment: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended ​ Amount of ​ ​ ​ ​ ​ March 31, ​ Increase ​ Percent ​ ​ ​ 2021 ​ 2022 ​ (Decrease) ​ Change ​ Production data (1) (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (Bcf) ​ ​ 207 ​ ​ 199 ​ ​ (8) ​ (4) % C2 Ethane (MBbl) ​ ​ 4,405 ​ ​ 4,005 ​ ​ (400) ​ (9) % C3+ NGLs (MBbl) ​ ​ 9,926 ​ ​ 9,638 ​ ​ (288) ​ (3) % Oil (MBbl) ​ ​ 960 ​ ​ 724 ​ ​ (236) ​ (25) % Combined (Bcfe) ​ ​ 299 ​ ​ 285 ​ ​ (14) ​ (5) % Daily combined production (MMcfe/d) ​ ​ 3,322 ​ ​ 3,165 ​ ​ (157) ​ (5) % Average prices before effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) (4) ​ $ 3.48 ​ ​ 5.01 ​ ​ 1.53 ​ 44 % C2 Ethane (per Bbl) ​ $ 8.20 ​ ​ 16.74 ​ ​ 8.54 ​ 104 % C3+ NGLs (per Bbl) ​ $ 40.72 ​ ​ 61.55 ​ ​ 20.83 ​ 51 % Oil (per Bbl) ​ $ 46.55 ​ ​ 87.45 ​ ​ 40.90 ​ 88 % Weighted Average Combined (per Mcfe) ​ $ 4.03 ​ ​ 6.04 ​ ​ 2.01 ​ 50 % Average realized prices after effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 3.56 ​ ​ 3.60 ​ ​ 0.04 ​ 1 % C2 Ethane (per Bbl) ​ $ 7.53 ​ ​ 16.63 ​ ​ 9.10 ​ 121 % C3+ NGLs (per Bbl) ​ $ 39.79 ​ ​ 61.14 ​ ​ 21.35 ​ 54 % Oil (per Bbl) ​ $ 45.80 ​ ​ 86.76 ​ ​ 40.96 ​ 89 % Weighted Average Combined (per Mcfe) ​ $ 4.05 ​ ​ 5.03 ​ ​ 0.98 ​ 24 % Average costs (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 0.08 ​ ​ 0.06 ​ ​ (0.02) ​ (25) % Gathering and compression ​ $ 0.74 ​ ​ 0.71 ​ ​ (0.03) ​ (4) % Processing ​ $ 0.62 ​ ​ 0.67 ​ ​ 0.05 ​ 8 % Transportation ​ $ 0.67 ​ ​ 0.70 ​ ​ 0.03 ​ 4 % Production and ad valorem taxes ​ $ 0.15 ​ ​ 0.19 ​ ​ 0.04 ​ 27 % Marketing (revenue) expense, net ​ $ (0.01) ​ ​ 0.10 ​ ​ 0.11 ​ * ​ Depletion, depreciation, amortization, and accretion ​ $ 0.65 ​ ​ 0.60 ​ ​ (0.05) ​ (8) % General and administrative (excluding equity-based compensation) ​ $ 0.13 ​ ​ 0.11 ​ ​ (0.02) ​ (15) % * Not meaningful. (1) Production data excludes volumes related to the volumetric production payment transaction (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 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, 2021 includes $85 million of net litigation proceeds related to a favorable litigation judgment. See Note 14—Contingencies to the unaudited condensed consolidated financial statements for further discussion on the litigation proceeds. Excluding the effect of the litigation proceeds received, the average realized price for natural gas would have been $3.07 per Mcf for the three months ended March 31, 2021. ​ Natural gas sales . Revenues from sales of natural gas increased from $720 million, which included net litigation proceeds of $85 million, for the three months ended March 31, 2021 to $996 million for the March 31, 2022, an increase of $276 million, or 38%. See Note 14—Contingencies to the unaudited condensed consolidated financial statements for more information on the litigation proceeds. Excluding net litigation proceeds, higher commodity prices (excluding the effects of derivative settlements) during the three months ended March 31, 2022 accounted for an approximate $391 million increase in year-over-year gas sales revenue (calculated as the change in the year-to-year average price excluding the net proceeds from the litigation times current year production volumes). Lower natural gas production volumes accounted for an approximate $30 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 excluding the net proceeds from the litigation). See Note 14—Contingencies to the unaudited condensed consolidated financial statements for further discussion on the litigation proceeds. 40 Table of Contents NGLs sales . Revenues from sales of NGLs increased from $440 million for the three months ended March 31, 2021 to $660 million for the three months ended March 31, 2022, an increase of $220 million, or 50%. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended March 31, 2022 accounted for an approximate $235 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower NGLs production volumes accounted for an approximate $15 million decrease in year-over-year NGL revenues (calculated as the change in year-to-year volumes times the prior year average price). Oil sales . Revenues from sales of oil increased from $45 million for the three months ended March 31, 2021 to $63 million for the three months ended March 31, 2022, an increase of $18 million, or 42%. Higher oil prices, excluding the effects of derivative settlements, accounted for an approximate $29 million increase in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower oil production volumes during the three months ended March 31, 2022 accounted for an approximate $11 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 losses. To achieve more predictable cash flows, and to reduce our exposure to price fluctuations, we enter into fixed for variable price swap contracts, swaptions, basis swap contracts and collar contracts when management believes that favorable future sales prices for our production can be secured. 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, 2021 and 2022, our commodity hedges resulted in derivative fair value losses of $178 million and $1.0 billion, respectively. For the three months ended March 31, 2021, commodity derivative fair value losses included $5 million of cash proceeds for gains on settled derivatives. For the three months ended March 31, 2022, commodity derivative fair value losses included $285 million of cash payments on commodity settled derivatives losses. Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled or monetized prior to settlement. Derivative asset or liability positions at the end of any accounting period may reverse to the extent future commodity prices increase or decrease from their levels at the end of the accounting period, or as gains or losses are realized through settlement. We expect continued volatility in commodity prices and the related fair value of our derivative instruments in the future. Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP decreased from $11 million for the three months ended March 31, 2021 to $9 million for the three months ended March 31, 2022, a decrease of $2 million or 17%, primarily due to a decrease in production volumes. Under the terms of the agreement, the production volumes are delivered at approximately $1.61 per MMBtu over the contractual term. Lease operating expense . Lease operating expense decreased from $25 million for the three months ended March 31, 2021 to $18 million for the three months ended March 31, 2022, a decrease of $7 million or 28%, primarily due to lower production volumes. On a per unit basis, lease operating expenses decreased from $0.08 per Mcfe for the three months ended March 31, 2021 to $0.06 per Mcfe for the three months ended March 31, 2022, primarily due to lower water disposal costs, partially offset by decreased production and higher workover expense. Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense decreased from $605 million for the three months ended March 31, 2021 to $590 million for the three months ended March 31, 2022, a decrease of $15 million or 2%, primarily a result of lower production and decreased gathering and compression costs, partially offset by higher processing costs between periods. Gathering and compression costs decreased from $0.74 per Mcfe for the three months ended March 31, 2021 to $0.71 per Mcfe for the three months ended March 31, 2022, primarily due to $12 million in incentive fee rebates earned from Antero Midstream during the three months ended March 31, 2022 that were not earned during the three months ended March 31, 2021. Processing costs increased from $0.62 per Mcfe for the three months ended March 31, 2021 to $0.67 per Mcfe for the three months ended March 31, 2022, primarily due to increased costs for ethane transportation as well as increased processing fees as a result of an annual CPI-based adjustment during the first quarter of 2022. Transportation costs increased from $0.67 per Mcfe for the three months ended March 31, 2021 to $0.70 per Mcfe for the three months ended March 31, 2022, primarily due to higher fuel costs between periods. Production and ad valorem tax expense. Total production and ad valorem taxes increased from $45 million for the three months ended March 31, 2021 to $53 million for the three months ended March 31, 2022, an increase of $8 million, or 18% primarily due to higher commodity prices between periods. On a per Mcfe basis, production and ad valorem taxes increased from $0.15 per Mcfe for the three months ended March 31, 2021 to $0.19 per Mcfe for the three months ended March 31, 2022. Production and ad 41 Table of Contents valorem taxes as a percentage of natural gas revenues remained relatively consistent at 6% and 5% for the three months ended March 31, 2021 and 2022, respectively. General and administrative expense . General and administrative expense (excluding equity-based compensation expense) decreased from $38 million for the three months ended March 31, 2021 to $31 million for the three months ended March 31, 2022, a decrease of $7 million, or 19% , primarily due to lower salary and wage expense between periods and lower professional service fees. On a per-unit basis, general and administrative expense excluding equity-based compensation decreased from $0.13 per Mcfe for the three months ended March 31, 2021 to $0.11 per Mcfe for the three months ended March 31, 2022, primarily due to lower overall general and administrative expense between periods. Equity-based compensation expense . Noncash equity-based compensation expense decreased from $6 million for the three months ended March 31, 2021 to $5 million for the three months ended March 31, 2022, a decrease of $1 million or 18%, primarily due to lower restricted share unit awards granted during 2020 (which vest over a four year service period) and equity award forfeitures, partially offset by new awards granted to employees. When an equity award is forfeited, expense previously recognized for the award is reversed. See Note 9—Equity Based Compensation and Cash Awards to the unaudited condensed consolidated financial statements for more information. Depletion, depreciation, and amortization expense . Depletion, depreciation and amortization (“DD&A”) expense decreased from $194 million for the three months ended March 31, 2021 to $168 million for the three months ended March 31, 2022, a decrease of $26 million, or 13%, primarily as a result of increased proved reserve volumes due to higher commodity prices as well as lower production volumes between periods. DD&A expense decreased from $0.65 per Mcfe for the three months ended March 31, 2021 to $0.60 per Mcfe March 31, 2022, primarily as a result of increased proved reserve volumes between periods. Impairment of oil and gas properties . Impairment of oil and gas properties decreased from $ 34 million for the three months ended March 31, 2021 to $ 22 million for the three months ended March 31, 2022 , a decrease of $ 12 million, or 34 %, primarily related to lower impairments of expiring leases between periods. During both periods, we recognized impairments primarily related to expiring leases 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. The net effect of our marketing segment changes from net marketing income of $3 million, or $0.01 per Mcfe, for the three months ended March 31, 2021 to net marketing expenses of $30 million, or $0.10 per Mcfe, for the three months ended March 31, 2022, primarily due to lower volumes and lower gas marketing margins between periods. Marketing revenue. Marketing revenue decreased from $165 million for the three months ended March 31, 2021 to $69 million for the three months ended March 31, 2022, a decrease of $96 million, or 58%, primarily due to lower marketing volumes between periods, partially offset by increased commodity prices between periods. Lower natural gas marketing volumes accounted for a $115 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our natural gas prices accounted for an approximate $15 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). Higher oil marketing volumes accounted for a $4 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our oil prices accounted for an approximate $5 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). Lower ethane marketing volumes accounted for a $3 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our ethane prices accounted for an approximate $5 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). Lower NGL marketing volumes between periods also contributed to decreased marketing revenues during the three months ended March 31, 2022. Marketing expense. Marketing expense decreased from $162 million for the three months ended March 31, 2021 to $99 million for the three months ended March 31, 2022, a decrease of $63 million, or 39%. Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related to current excess firm capacity. The cost of third-party natural gas decreased approximately $54 million, which was partially offset by increased oil purchases of 42 Table of Contents approximately $8 million between periods. The total costs decreased primarily due to decreased marketing volumes between periods, partially offset by increased commodity prices. Firm transportation costs were $56 million for the three months ended March 31, 2021 and $38 million for the three months ended March 31, 2022, a decrease of $18 million due to the reduction in firm transportation commitments and third-party marketed volumes between periods. Antero Midstream Segment Antero Midstream revenue. Revenue from the Antero Midstream segment decreased from $224 million for the three months ended March 31, 2021 to $218 million for the three months ended March 31, 2022, a decrease of $6 million, primarily due to a decrease in low pressure revenues due to higher fee rebates earned by us and lower water handling revenue as a result of decreased well completions period-over-period, partially offset by higher compression and high pressure gathering revenues due to increased throughput between periods as well as higher low pressure, compression and high pressure fees as a result of an annual CPI-based adjustment. Antero Midstream operating expense. Total operating expense related to the segment decreased from $91 million for the three months ended March 31, 2021 to $89 million for the three months ended March 31, 2022 primarily due to increased direct operating costs as a result of resuming fresh water deliveries to us in the Utica Shale and a loss on the sale of excess pipe inventory during the three months ended March 31, 2021 compared to a gain on asset sale of miscellaneous equipment and pipe inventory during the three months ended March 31, 2022. Discussion of Items Not Allocated to Segments Interest expense. Interest expense decreased from $43 million for the three months ended March 31, 2021 to $38 million for the three months ended March 31, 2022, a decrease of $5 million or 12%, primarily due to the reduction in debt as a result of the repurchase of certain of our unsecured senior notes between periods. Interest expense includes approximately $5 million and $1 million of amortization of debt issuance costs and debt discounts and premiums for the three months ended March 31, 2021 and 2022, respectively. Loss on early extinguishment of debt. On January 12, 2021, we completed a registered direct offering (the “January Share Offering”) of an aggregate of 31.4 million shares of our common stock at a price of $6.35 per share to certain holders of our 4.25% convertible senior notes due 2026 (the “2026 Convertible Notes”). We used the proceeds from the January Share Offering and approximately $63 million of borrowings under the senior secured revolving credit facility prior to October 26, 2021 to repurchase from such holders $150 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions (the “January Convertible Note Repurchase,” and, collectively with the January Share Offering, the “January Equitization Transactions”). Additionally, during the three months ended March 31, 2021, we redeemed $661 million of our 5.125% senior notes due December 1, 2022 (the “2022 Notes”) at par, plus accrued and unpaid interest and recognized a $2 million loss on early extinguishment of debt. As result, the 2022 Notes were fully retired as of February 10, 2021. 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. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements. Loss on convertible note equitization. During the three months ended March 31, 2021, we recognized a loss of $39 million for the January Equitization Transactions, which represents the consideration paid in excess of the original terms of the 2026 Convertible Notes. There were no equitization transactions during the three months ended March 31, 2022. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. ​ Income tax benefit . Income tax benefit increased from $3 million, with an effective tax rate of 21%, for the three months ended March 31, 2021 to $53 million, with an effective tax rate of 23%, for the three months ended March 31, 2022, an increase of $50 million. The increase in tax benefit was primarily due to a higher loss before income taxes between periods. Capital Resources and Liquidity Sources and Uses of Cash Our primary sources of liquidity have been through net cash provided by operating activities, borrowings under our senior secured revolving credit facility (the “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 43 Table of Contents 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. For information about the impacts of COVID-19 on our capital resources and liquidity, see “—COVID-19 Pandemic.” Based on strip prices as of March 31, 2022, we believe that net cash provided by operating activities, distributions from our unconsolidated affiliate and available borrowings under the Credit Facility will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures and commitments and contingencies for at least the next 12 months. Cash Flows The following table summarizes our cash flows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended March 31, ​ ​ ​ 2021 2022 Net cash provided by operating activities ​ $ 563,731 ​ ​ 565,673 ​ Net cash used in investing activities ​ ​ (122,975) ​ ​ (215,117) ​ Net cash used in financing activities ​ ​ (440,756) ​ ​ (350,556) ​ Net increase in cash and cash equivalents ​ $ — ​ ​ — ​ ​ Operating Activities. Net cash provided by operating activities was $564 million and $566 million for the three months ended March 31, 2021 and 2022, respectively. Net cash provided by operating activities increased primarily due to increases in commodity prices both before and after the effects of settled commodity derivatives, partially offset by increased cash utilized for working capital, decreased production, increased net marketing expense and increased 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. For example, the impact of the COVID-19 outbreak reduced global demand for natural gas, NGLs and oil. These factors are beyond our control and are difficult to predict. Investing Activities. Net cash used in investing activities increased from $123 million for the three months ended March 31, 2021 to $215 million for the three months ended March 31, 2022 , primarily due to an increase in capital expenditures of $93 million between periods. Financing Activities . Net cash flows used in financing activities decreased from $441 million for the three months ended March 31, 2021 to $351 million for the three months ended March 31, 2022. During the three months ended March 31, 2021, we issued $500 million aggregate principal amount of 8.375% senior notes due July 15, 2026 and $700 million aggregate principal amount of 7.625% senior notes due February 1, 2029 (net of $15 million of aggregate debt issuance costs), of which proceeds were used to (i) redeem $661 million aggregate principal amount of our 2022 Notes, which were fully retired, (ii) and partially repay borrowings on our senior secured revolving credit facility. Also, during the three months ended March 31, 2021, we completed the January Share Offering and used the proceeds and approximately $63 million of borrowings under the senior secured revolving credit facility to repurchase $150 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions. Additionally, during the three months ended March 31, 2021, we distributed $25 million to the noncontrolling interest in Martica. During the three months ended March 31, 2022, we (i) redeemed $585 million aggregate principal amount of our 2025 Notes (ii) repurchased 3.7 million shares of our common stock at a total cost of approximately $100 million and (iii) distributed $36 million to the noncontrolling interest in Martica. Additionally, we borrowed $388 million, net, on our Credit Facility during the three months ended March 31, 2022. 2022 Capital Budget and Capital Spending On February 16, 2022, we announced our net capital budget for 2022 is $740 million to $775 million. Our budget includes: a range of $675 million to $700 million for drilling and completion and a range of $65 million to $75 million for leasehold expenditures. We do not budget for acquisitions. During 2022, we plan to complete 60 to 65 net horizontal wells in the Appalachian Basin. We 44 Table of Contents 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, 2022, our total consolidated capital expenditures were approximately $206 million, including drilling and completion costs of $175 million, leasehold acquisitions of $24 million, and other capital expenditures of $7 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 2021 Form 10-K for information on our senior notes. 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 2021 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 2021 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, 2022, 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, 2021 and 2022. 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, 2022, 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. 45 Table of Contents