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, potential shut-ins of production due to lack of downstream demand or storage capacity, 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 profitably grow 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 Marcellus Shale and Utica Shale of the Appalachian Basin. As of September 30, 2021, we held approximately 508,000 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. 2021 Developments and Highlights COVID-19 Pandemic In March 2020, the World Health Organization declared the COVID-19 outbreak a pandemic. Governments 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. The imbalance between the supply of and demand for oil, as well as the uncertainty around the extent and timing of an economic recovery, caused extreme market volatility and a substantial adverse effect on commodity prices in 2020. 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. As a producer of natural gas, NGLs and oil, we are recognized as an essential business under various federal, state and local regulations related to the COVID-19 pandemic. As such, we have continued to operate throughout the pandemic as permitted under these regulations while taking steps to protect the health and safety of our employees and contract workers. We have implemented protocols to reduce the risk of an outbreak within our field operations, and these protocols have not reduced production or efficiency in a significant manner. A substantial portion of our non-field level employees operated in remote work from home arrangements through September 30, 2021, and due to the rise of COVID-19 cases as a result of new variants of the virus, our plans to return to in- 38 Table of Contents office arrangements during the third quarter of 2021 have been deferred in order to protect the health and safety of our employees and contract workers. 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. Our natural gas, NGLs and oil producing properties are located in the liquids-rich Appalachian Basin. We have hedged through fixed price contracts the sale of 2.2 Bcf per day of natural gas at a weighted average price of $2.78 per MMBtu for the remainder of 2021. Our hedges cover a substantial majority of our expected natural gas production for the remainder of 2021. We also have fixed priced contracts for the sale of 3,000 barrels per day of oil at a weighted average price of $55.16 per barrel for the remainder of 2021. 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, will not impact our ability to realize the benefits of our hedges. Our supply chain has not experienced any significant interruptions. 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 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 further 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. As of September 30, 2021, we had $98 million of borrowings under our Prior Credit Facility (defined below in “—Capital Resources and Liquidity—Debt Agreements—Senior Secured Revolving Credit Facility”) and had outstanding letters of credit of $742 million . On October 26, 2021, we amended our Prior Credit Facility with a borrowing base of $3.5 billion and lender commitments of $1.5 billion. 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.” In addition, our borrowing capacity is directly impacted by the amount of financial assurance 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. Since the onset of the COVID-19 pandemic, we have timely serviced our debt and other obligations, and we have not materially modified the terms of any agreements. Financing and Asset Sales Program Highlights Credit Facility On October 26, 2021, we entered into an amended and restated senior secured revolving credit facility with a borrowing base of $3.5 billion and lender commitments of $1.5 billion. and matures on the earlier of (i) October 26, 2026 and (ii) the day that is 180 days prior to the earliest stated redemption date of any series of our senior notes. Lender commitments were reduced by $1.1 billion from the previous commitments of $2.64 billion to better align with our expected future liquidity needs. 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” for more information. ​ Issuance of Senior Notes On January 4, 2021, we issued $500 million of our 8.375% senior notes due July 15, 2026 (the “2026 Notes”) at par. On January 26, 2021, we issued $700 million of 7.625% senior notes due February 1, 2029 (the “2029 Notes”) at par. On June 1, 2021, we issued $600 million of 5.375% senior notes due March 1, 2030 (the “2030 Notes”). The 2026 Notes, 2029 Notes and 2030 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2026 Notes, 2029 Notes and 2030 Notes rank pari passu to our other outstanding senior notes. The 2026 Notes, 2029 Notes and 2030 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by our existing subsidiaries that guarantee the Credit Facility and certain of our future restricted subsidiaries. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. 39 Table of Contents Redemption of Senior Notes We fully redeemed all of our outstanding 5.125% senior notes due December 1, 2022 (the “2022 Notes”) at par, plus accrued and unpaid interest in the first quarter of 2021. During the second quarter of 2021, we fully redeemed all of our outstanding 5.625% senior notes due June 1, 2023 (the “2023 Notes”) at par, plus accrued and unpaid interest. On July 1, 2021, we redeemed $175 million of the principal amount of our 2026 Notes at a redemption price of 108.375% of the principal amount thereof, plus accrued and unpaid interest. Immediately following the redemption, there were $325 million aggregate principal amount of 2026 Notes outstanding. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. On October 18, 2021, we issued a notice of partial redemption with respect to the 2029 Notes. On November 2, 2021, we will redeem $116 million aggregate principal amount of outstanding 2029 Notes at a redemption price of 107.625% of the principal amount thereof, plus accrued and unpaid interest. Immediately following the redemption, there will be $584 million aggregate principal amount of 2029 Notes outstanding. The $9 million premium to the principal amount to be redeemed along with the write off of a proportional amount of unamortized debt issuance costs will be included in our loss on early debt extinguishment during the fourth quarter of 2021. ​ Convertible Notes Equitizations 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 Prior Credit Facility 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”). On May 13, 2021, we completed a registered direct offering (the “May Share Offering”) of an aggregate of 11.6 million shares of our common stock at a price of $11.01 per share to certain holders of our 2026 Convertible Notes. We used the proceeds from the May Share Offering and approximately $26 million of borrowings under the Prior Credit Facility to repurchase from such holders $56 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions (the “May Convertible Note Repurchase,” and, collectively with the May Share Offering, the “May Equitization Transactions”). See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. Drilling Partnership On February 17, 2021, we announced the formation of a drilling partnership with QL Capital Partners (“QL”), an affiliate of Quantum Energy Partners, for our 2021 through 2024 drilling program. Under the terms of the arrangement, each year in which QL participates represents an annual tranche, and QL will be conveyed a working interest in any wells spud by us during such tranche year. For 2021, together with QL, we agreed to a capital budget for such annual tranche, and for each subsequent year through 2024, we will propose a capital budget and estimated internal rate of return (“IRR”) for all wells to be spud during such year and, subject to the mutual agreement of the parties that the estimated IRR for the year exceeds a specified return, QL will be obligated to participate in such tranche. We develop and manage the drilling program associated with each tranche, including the selection of wells. Additionally, for each annual tranche in which QL participates, together with QL, we will enter into an assignment, bill of sale and conveyance pursuant to which QL will be conveyed a proportionate working interest percentage in each well spud in that year, which conveyance will not be subject to any reversion. Under the terms of the arrangement, QL will fund 20% of development capital for wells spud in 2021 and is expected to fund between 15% and 20% of development capital for wells spud from 2022 through 2024, which funding amounts represent QL’s proportionate working interest in such wells. Additionally, we may receive a carry in the form of a one-time payment from QL for each annual tranche if the IRR for such tranche exceeds certain specified returns, which will be determined no earlier than December 31 following the end of each tranche year. Capital costs in excess of, and cost savings below, a specified percentage of budgeted amounts for each annual tranche will be for our account. Subject to the preceding sentence, for any wells included in a tranche, QL is obligated and responsible for its working interest share of costs and liabilities, and is entitled to its working interest share of revenues, associated with such wells for the life of such wells. If we present a capital budget for an annual tranche with an estimated IRR equal to or exceeding a specified return that QL in good faith believes is less than such specified return and QL elects not to participate, we will not be obligated to offer QL the opportunity to participate in subsequent annual tranches. See Note 3—Transactions to the unaudited condensed consolidated financial statements for more information. 40 Table of Contents Overriding Royalty Interest Additional Contributions On June 15, 2020, we announced the consummation of a transaction with an affiliate of Sixth Street Partners, LLC (“Sixth Street”) relating to certain overriding royalty interests across our existing asset base (the “ORRIs”). In connection with the transaction, we contributed the ORRIs to a newly formed subsidiary, Martica Holdings LLC (“Martica”). At the initial closing, Sixth Street contributed $300 million in cash (subject to customary adjustments) and agreed to contribute up to an additional $102 million in cash if certain production thresholds attributable to the ORRIs were achieved in the third quarter of 2020 and first quarter of 2021. All cash contributed by Sixth Street was distributed to us. We met the applicable production thresholds related to the third quarter of 2020 and first quarter of 2021 as of September 31, 2020 and March 31, 2021, respectively. We received a $51 million cash distribution during each of the fourth quarter of 2020 and the second quarter of 2021. See Note 3—Transactions to the unaudited condensed consolidated financial statements for more information. 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 September 30, 2021, our fixed price natural gas, oil and NGL swap positions excluding Martica, our consolidated VIE, were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Commodity / Settlement Period Index Contracted Volume Price Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ October-December 2021 ​ Henry Hub ​ 199 Bcf ​ $ 2.78 /MMBtu ​ January-December 2022 ​ Henry Hub ​ 422 Bcf ​ ​ 2.50 /MMBtu ​ January-December 2023 ​ Henry Hub ​ 16 Bcf ​ ​ 2.37 /MMBtu ​ ​ ​ ​ ​ 637 Bcf ​ ​ 2.58 /MMBtu ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Butane ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ October-December 2021 ​ Mont Belvieu Butane-OPIS Non-TET ​ 239 MBbl ​ $ 33.77 /Bbl ​ October-December 2021 ​ Mont Belvieu Butane-OPIS TET ​ 138 MBbl ​ $ 32.24 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural Gasoline ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ October-December 2021 ​ Mont Belvieu Natural Gasoline-OPIS Non-TET ​ 764 MBbl ​ $ 49.70 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Isobutane ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ October-December 2021 ​ Mont Belvieu Isobutane-OPIS Non-TET ​ 258 MBbl ​ $ 35.75 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ October-December 2021 ​ West Texas Intermediate ​ 276 MBbl ​ $ 55.16 /Bbl ​ ​ In addition, we have a call option agreement, which entitles the holder, if exercised, to enter into a fixed price swap agreement for approximately 156 Bcf at a price of $2.77 per MMBtu in 2024. As of September 30, 2021, 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 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ October-December 2021 ​ NYMEX to TCO ​ 4 Bcf ​ $ 0.414 /MMBtu ​ January-December 2022 ​ NYMEX to TCO ​ 22 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 ​ ​ ​ ​ ​ 62 Bcf ​ ​ 0.516 /MMBtu ​ 41 Table of Contents ​ As of September 30, 2021, we had natural gas and NGL contracts that fix the Mont Belvieu index price for natural gasoline to percentages of WTI as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted Average ​ Commodity / Settlement Period Index to Basis Differential Contracted Volume Payout Ratio ​ Gas Liquids ​ ​ ​ ​ ​ ​ ​ ​ ​ October-December 2021 ​ Mont Belvieu Natural Gasoline to WTI ​ 858 MBbl ​ 77 % ​ ​ As of September 30, 2021, 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 95 Bcf remaining through December 31, 2026 at a weighted average strike price of $2.57 per MMBtu. We believe our hedge position provides some certainty to cash flows supporting our future operations and capital spending plans. As of September 30, 2021, the estimated fair value of our commodity derivative contracts was a net liability of approximately $1.7 billion. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information. ​ 42 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 Corporation. Revenues from Antero Midstream Corporation’s operations were primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream Partners. All intersegment transactions were eliminated upon consolidation, including revenues from water handling and treatment services provided by Antero Midstream Partners LP (“Antero Midstream Partners”), 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 September 30, 2020 Compared to Three Months Ended September 30, 2021 The operating results of our reportable segments were as follows for the three months ended September 30, 2020 and 2021 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended September 30, 2020 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ Elimination of ​ ​ ​ ​ ​ ​ ​ ​ ​ Investment in ​ Intersegment ​ ​ ​ ​ ​ Exploration ​ ​ ​ Antero ​ Transactions and ​ ​ ​ ​ ​ and ​ ​ ​ Midstream ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Corporation Affiliates Total ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 436,304 ​ ​ — ​ ​ — ​ ​ — ​ ​ 436,304 ​ Natural gas liquids sales ​ ​ 327,426 ​ ​ — ​ ​ — ​ ​ — ​ ​ 327,426 ​ Oil sales ​ ​ 34,265 ​ ​ — ​ ​ — ​ ​ — ​ ​ 34,265 ​ Commodity derivative fair value losses ​ ​ (514,751) ​ ​ — ​ ​ — ​ ​ — ​ ​ (514,751) ​ Gathering, compression, water handling and treatment ​ ​ — ​ ​ — ​ ​ 251,215 ​ ​ (251,215) ​ ​ — ​ Marketing ​ ​ — ​ ​ 91,497 ​ ​ — ​ ​ — ​ ​ 91,497 ​ Amortization of deferred revenue, VPP ​ ​ 5,175 ​ ​ — ​ ​ — ​ ​ — ​ ​ 5,175 ​ Other income (loss) ​ 675 ​ ​ — ​ ​ (17,800) ​ ​ 17,800 ​ ​ 675 ​ Total revenue ​ $ 289,094 ​ ​ 91,497 ​ ​ 233,415 ​ ​ (233,415) ​ ​ 380,591 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 21,450 ​ ​ — ​ ​ — ​ ​ — ​ ​ 21,450 ​ Gathering and compression ​ ​ 221,004 ​ ​ — ​ ​ 38,052 ​ ​ (38,052) ​ ​ 221,004 ​ Processing ​ ​ 244,888 ​ ​ — ​ ​ — ​ ​ — ​ ​ 244,888 ​ Transportation ​ ​ 190,723 ​ ​ — ​ ​ — ​ ​ — ​ ​ 190,723 ​ Production and ad valorem taxes ​ ​ 25,790 ​ ​ — ​ ​ — ​ ​ — ​ ​ 25,790 ​ Marketing ​ ​ — ​ ​ 128,580 ​ ​ — ​ ​ — ​ ​ 128,580 ​ Exploration ​ ​ 454 ​ ​ — ​ ​ — ​ ​ — ​ ​ 454 ​ Impairment of oil and gas properties ​ ​ 29,392 ​ ​ — ​ ​ — ​ ​ — ​ ​ 29,392 ​ Depletion, depreciation, and amortization ​ ​ 238,418 ​ ​ — ​ ​ 26,801 ​ ​ (26,801) ​ ​ 238,418 ​ Accretion of asset retirement obligations ​ ​ 1,115 ​ ​ — ​ ​ 39 ​ ​ (39) ​ ​ 1,115 ​ General and administrative (excluding equity-based compensation) ​ ​ 25,941 ​ ​ — ​ ​ 9,554 ​ ​ (9,554) ​ ​ 25,941 ​ Equity-based compensation ​ ​ 5,699 ​ ​ — ​ ​ 3,678 ​ ​ (3,678) ​ ​ 5,699 ​ Contract termination and rig stacking and other expenses ​ ​ 1,246 ​ ​ — ​ ​ 3,474 ​ ​ (3,474) ​ ​ 1,246 ​ Total operating expenses ​ ​ 1,006,120 ​ ​ 128,580 ​ ​ 81,598 ​ ​ (81,598) ​ ​ 1,134,700 ​ Operating income (loss) ​ $ (717,026) ​ ​ (37,083) ​ ​ 151,817 ​ ​ (151,817) ​ ​ (754,109) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 24,419 ​ ​ — ​ ​ 23,173 ​ ​ (23,173) ​ ​ 24,419 ​ ​ ​ 43 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended September 30, 2021 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ Elimination of ​ ​ ​ ​ ​ ​ ​ ​ ​ Investment in ​ Intersegment ​ ​ ​ ​ ​ Exploration ​ ​ ​ Antero ​ Transactions and ​ ​ ​ ​ ​ and ​ ​ ​ Midstream ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Corporation Affiliates Total ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 884,669 ​ ​ — ​ ​ — ​ ​ — ​ ​ 884,669 ​ Natural gas liquids sales ​ ​ 598,327 ​ ​ — ​ ​ — ​ ​ — ​ ​ 598,327 ​ Oil sales ​ ​ 56,734 ​ ​ — ​ ​ — ​ ​ — ​ ​ 56,734 ​ Commodity derivative fair value losses ​ ​ (1,250,466) ​ ​ — ​ ​ — ​ ​ — ​ ​ (1,250,466) ​ Gathering, compression, water handling and treatment ​ ​ — ​ ​ — ​ ​ 242,472 ​ ​ (242,472) ​ ​ — ​ Marketing ​ ​ — ​ ​ 232,685 ​ ​ — ​ ​ — ​ ​ 232,685 ​ Amortization of deferred revenue, VPP ​ ​ 11,404 ​ ​ — ​ ​ — ​ ​ — ​ ​ 11,404 ​ Gain on sale of assets ​ ​ 539 ​ ​ — ​ ​ — ​ ​ — ​ ​ 539 ​ Other income (loss) ​ 530 ​ ​ — ​ ​ (17,668) ​ ​ 17,668 ​ ​ 530 ​ Total revenue ​ $ 301,737 ​ 232,685 ​ 224,804 ​ (224,804) ​ ​ 534,422 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 25,363 ​ ​ — ​ ​ — ​ ​ — ​ ​ 25,363 ​ Gathering and compression ​ ​ 218,815 ​ ​ — ​ ​ 39,499 ​ ​ (39,499) ​ ​ 218,815 ​ Processing ​ ​ 207,093 ​ ​ — ​ ​ — ​ ​ — ​ ​ 207,093 ​ Transportation ​ ​ 202,317 ​ ​ — ​ ​ — ​ ​ — ​ ​ 202,317 ​ Production and ad valorem taxes ​ ​ 52,219 ​ ​ — ​ ​ — ​ ​ — ​ ​ 52,219 ​ Marketing ​ ​ — ​ ​ 266,751 ​ ​ — ​ ​ — ​ ​ 266,751 ​ Exploration ​ ​ 235 ​ ​ — ​ ​ — ​ ​ — ​ ​ 235 ​ Impairment of oil and gas properties ​ ​ 26,253 ​ ​ — ​ ​ — ​ ​ — ​ ​ 26,253 ​ Depletion, depreciation, and amortization ​ ​ 182,810 ​ ​ — ​ ​ 27,487 ​ ​ (27,487) ​ ​ 182,810 ​ Accretion of asset retirement obligations ​ ​ 828 ​ ​ — ​ ​ 114 ​ ​ (114) ​ ​ 828 ​ General and administrative (excluding equity-based compensation) ​ ​ 27,144 ​ ​ — ​ ​ 11,555 ​ ​ (11,555) ​ ​ 27,144 ​ Equity-based compensation ​ ​ 5,298 ​ ​ — ​ ​ 3,255 ​ ​ (3,255) ​ ​ 5,298 ​ Contract termination and rig stacking and other expenses ​ ​ 3,370 ​ ​ — ​ ​ 1,073 ​ ​ (1,073) ​ ​ 3,370 ​ Total operating expenses ​ ​ 951,745 ​ 266,751 ​ 82,983 ​ (82,983) ​ ​ 1,218,496 ​ Operating income (loss) ​ $ (650,008) ​ ​ (34,066) ​ ​ 141,821 ​ ​ (141,821) ​ ​ (684,074) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 21,450 ​ ​ — ​ ​ 24,088 ​ ​ (24,088) ​ ​ 21,450 ​ ​ ​ 44 Table of Contents Exploration and Production Segment The following table sets forth selected operating data of the exploration and production segment for the three months ended September 30, 2020 compared to the three months ended September 30, 2021: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended ​ Amount of ​ ​ ​ ​ ​ September 30, ​ Increase ​ Percent ​ ​ ​ 2020 ​ 2021 ​ (Decrease) ​ Change ​ Production data (1) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (Bcf) ​ ​ 226 ​ ​ 205 ​ ​ (21) ​ (9) % C2 Ethane (MBbl) ​ ​ 5,459 ​ ​ 4,372 ​ ​ (1,087) ​ (20) % C3+ NGLs (MBbl) ​ ​ 13,400 ​ ​ 10,258 ​ ​ (3,142) ​ (23) % Oil (MBbl) ​ ​ 1,367 ​ ​ 932 ​ ​ (435) ​ (32) % Combined (Bcfe) ​ ​ 347 ​ ​ 299 ​ ​ (48) ​ (14) % Daily combined production (MMcfe/d) ​ ​ 3,772 ​ ​ 3,247 ​ ​ (525) ​ (14) % Average prices before effects of derivative settlements (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 1.93 ​ ​ 4.31 ​ ​ 2.38 ​ 123 % C2 Ethane (per Bbl) ​ $ 5.94 ​ ​ 13.25 ​ ​ 7.31 ​ 123 % C3+ NGLs (per Bbl) ​ $ 22.01 ​ ​ 52.68 ​ ​ 30.67 ​ 139 % Oil (per Bbl) ​ $ 25.07 ​ ​ 60.87 ​ ​ 35.80 ​ 143 % Weighted Average Combined (per Mcfe) ​ $ 2.30 ​ ​ 5.15 ​ ​ 2.85 ​ 124 % Average realized prices after effects of derivative settlements (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 2.73 ​ ​ 3.00 ​ ​ 0.27 ​ 10 % C2 Ethane (per Bbl) ​ $ 5.67 ​ ​ 13.25 ​ ​ 7.58 ​ 134 % C3+ NGLs (per Bbl) ​ $ 23.81 ​ ​ 38.67 ​ ​ 14.86 ​ 62 % Oil (per Bbl) ​ $ 34.96 ​ ​ 56.31 ​ ​ 21.35 ​ 61 % Weighted Average Combined (per Mcfe) ​ $ 2.92 ​ ​ 3.79 ​ ​ 0.87 ​ 30 % Average costs (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 0.06 ​ ​ 0.08 ​ ​ 0.02 ​ 33 % Gathering and compression ​ $ 0.64 ​ ​ 0.73 ​ ​ 0.09 ​ 14 % Processing ​ $ 0.71 ​ ​ 0.69 ​ ​ (0.02) ​ (3) % Transportation ​ $ 0.55 ​ ​ 0.68 ​ ​ 0.13 ​ 24 % Production taxes ​ $ 0.07 ​ ​ 0.17 ​ ​ 0.10 ​ 143 % Marketing, net ​ $ 0.11 ​ ​ 0.11 ​ ​ — ​ — % Depletion, depreciation, amortization and accretion ​ $ 0.69 ​ ​ 0.61 ​ ​ (0.08) ​ (12) % General and administrative (excluding equity-based compensation) ​ $ 0.07 ​ ​ 0.09 ​ ​ 0.02 ​ 29 % (1) Production data excludes volumes related to the volumetric production payment transaction (the “VPP”). See Note 3— Transactions to the unaudited condensed consolidated financial statements for more information. (2) Average sales prices shown in the table reflect both 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. 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 does not necessarily reflect their relative economic value. ​ Natural gas sales . Revenues from sales of natural gas increased from $436 million for the three months ended September 30, 2020 to $885 million for the three months ended September 30, 2021, an increase of $449 million, or 103%. Lower natural gas production volumes during the three months ended September 30, 2021 accounted for an approximate $39 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), and increases in commodity prices (excluding the effects of derivative settlements) accounted for an approximate $488 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). NGLs sales . Revenues from sales of NGLs increased from $327 million for the three months ended September 30, 2020 to $598 million for the three months ended September 30, 2021, an increase of $271 million, or 83% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Lower NGLs production volumes accounted for an approximate $76 million decrease in year-over-year NGL revenues (calculated as the change in year-to-year volumes times the prior year average price), and increases in commodity prices, excluding the effects of derivative settlements, accounted for an approximate $347 million 45 Table of Contents increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Oil sales . Revenues from sales of oil increased from $34 million for the three months ended September 30, 2020 to $57 million for the three months ended September 30, 2021, an increase of $23 million, or 66% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Lower oil production volumes 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), and increases in commodity prices, excluding the effects of derivative settlements, accounted for an approximate $34 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Commodity derivative fair value gains (losses) . To achieve more predictable cash flows, and to reduce our exposure to price fluctuations, we enter into fixed for variable price swap contracts, 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 September 30, 2020 and 2021, our commodity hedges resulted in derivative fair value losses of $515 million and $1.3 billion, respectively. For the three months ended September 30, 2020, commodity derivative fair value losses included $234 million of cash proceeds for gains on settled derivatives. For the three months ended September 30, 2021, commodity derivative fair value losses included $416 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 increased from $5 million for the three months ended September 30, 2020 to $11 million for the three months ended September 30, 2021 as a result of the VPP closing in August 2020. Under the terms of the agreement, the production volumes are delivered at approximately $1.61 per MMBtu over the contractual term. See Note 3—Transactions to the unaudited condensed consolidated financial statements for more information on this transaction. Lease operating expense . Lease operating expense increased from $21 million for the three months ended September 30, 2020 to $25 million for the three months ended September 30, 2021, an increase of $4 million or 18%. On a per unit basis, lease operating expenses increased from $0.06 per Mcfe for the three months ended September 30, 2020 to $0.08 per Mcfe for the three months ended September 30, 2021 primarily due to decreased production and higher fixed costs partially offset by lower water disposal costs. Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense decreased from $657 million for the three months ended September 30, 2020 to $628 million for the three months ended September 30, 2021, a decrease of $29 million or 4%. This decrease is primarily a result of lower production and decreased processing costs, partially offset by higher gathering and compression and transportation costs between periods. Gathering and compression costs increased from $0.64 per Mcfe for the three months ended September 30, 2020 to $0.73 per Mcfe for the three months ended September 30, 2021, primarily due to higher fuel costs as a result of increased natural gas prices and $12 million in incentive fee rebates from Antero Midstream Corporation received during the three months ended September 30, 2020 that were not received during the three months ended September 30, 2021. Processing costs decreased from $0.71 per Mcfe for the three months ended September 30, 2020 to $0.69 per Mcfe for the three months ended September 30, 2021, due to a decrease in C3+ NGL volumes as compared to total production volumes between periods, partially offset by increased NGL pipeline and terminaling fees from higher NGL volumes taken in-kind between periods. Transportation costs increased from $0.55 per Mcfe for the three months ended September 30, 2020 to $0.68 per Mcfe for the three months ended September 30, 2021 primarily due to increased utilization on higher tariff pipelines to the Midwest and Gulf Coast between periods. Production and ad valorem tax expense. Production and ad valorem taxes increased from $26 million for the three months ended September 30, 2020 to $52 million for the three months ended September 30, 2021, an increase of $26 million, or 100% primarily due to higher commodity prices between periods. Production and ad valorem taxes as a percentage of natural gas revenues remained consistent at 6% in each of the three months ended September 30, 2020 and 2021. 46 Table of Contents Impairment of oil and gas properties . Impairment of oil and gas properties decreased from $ 29 million for the three months ended September 30, 2020 to $ 26 million for the three months ended September 30, 2021 , a decrease of $3 million, or 11%, 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. Depletion, depreciation, and amortization expense . Depletion, depreciation and amortization (“DD&A”) expense decreased from $238 million for the three months ended September 30, 2020 to $183 million for the three months ended September 30, 2021, a decrease of $55 million, or 23%, 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 $0.69 per Mcfe for the three months ended September 30, 2020 to $0.61 per Mcfe for the three months ended September 30, 2021, primarily as a result of increased proved reserve volumes between periods. General and administrative expense . General and administrative expense (excluding equity-based compensation expense) increased from $26 million for the three months ended September 30, 2020 to $27 million for the three months ended September 30, 2021, an increase of $1 million, or 5%. The increase was primarily due to higher salary and wage expense between periods, which includes our annual incentive program that was significantly reduced during 2020, partially offset by lower employee headcount during 2021. We had 520 and 506 employees as of September 30, 2020 and 2021, respectively. On a per-unit basis, general and administrative expense excluding equity-based compensation increased from $0.07 per Mcfe for the three months ended September 30, 2020 to $0.09 per Mcfe for the three months ended September 30, 2021 primarily due to lower production between periods. Equity-based compensation expense . Noncash equity-based compensation expense decreased from $6 million for the three months ended September 30, 2020 to $5 million for the three months ended September 30, 2021, primarily due to 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 on equity-based compensation awards. Marketing Segment Marketing. 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, to optimize the revenues and mitigate costs from these transportation agreements. We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production to secure guaranteed capacity to favorable markets. Net marketing expenses decreased from $37 million, or $0.11 per Mcfe, for the three months ended September 30, 2020 to $34 million, or $0.11 per Mcfe, for the three months ended September 30, 2021. The decrease in net marketing expense was driven by higher marketing volumes and margins that mitigated some of our excess firm transportation expense. Marketing revenues increased from $91 million for the three months ended September 30, 2020 to $233 million for the three months ended September 30, 2021, an increase of $142 million due to increased marketing volumes. Marketing expenses increased from $129 million for the three months ended September 30, 2020 to $267 million for the three months ended September 30, 2021, an increase of $138 million, or 107%. Marketing expenses include firm transportation costs related to current excess firm capacity as well as the cost of third-party purchased gas and NGLs. Firm transportation costs included in the expenses above were $32 million and $28 million for the three months ended September 30, 2020 and 2021, respectively. Equity Method Investment in Antero Midstream Corporation Antero Midstream Corporation. Revenue from the Antero Midstream Corporation segment decreased from $233 million for the three months ended September 30, 2020 to $225 million for the three months ended September 30, 2021, a decrease of $8 million, or 4%, primarily due to lower water handling revenue due to decreased well completions period-over-period and lower gathering and compression revenues as a result of reduced throughput between periods. Total operating expenses related to the segment remained relatively consistent between periods at $82 million and $83 million for the three months ended September 30, 2020 and 2021, respectively. 47 Table of Contents Items Not Allocated to Segments Interest expense. Our interest expense decreased from $48 million for the three months ended September 30, 2020 to $45 million for the three months ended September 30, 2021, a decrease of $3 million or 5%, primarily due to the reduction in debt as a result of the repurchase of certain our unsecured senior notes, paydown of our Prior Credit Facility and increased interest income between periods, partially offset by interest that accrued on the 2026 Notes, 2029 Notes and 2030 Notes, each of which was issued after September 30, 2020. Gain (loss) on early extinguishment of debt. During the three months ended September 30, 2020 , we recognized a gain on early extinguishment of debt of $56 million related to $1.1 billion principal amount of debt that we repurchased at a weighted average discount of 13%. During the three months ended September 30, 2021 , we redeemed $175 million of our 2026 Notes at a redemption price of 108.375% of par, plus accrued and unpaid interest, which resulted in a loss on early debt extinguishment of $17 million. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. ​ Transaction expense. Transaction expense remained consistent between periods at less than $1 million for both the three months ended September 31, 2020 and 2021. Income tax benefit . Income tax benefit decreased from $169 million, with an effective tax rate of 23%, for the three months ended September 30, 2020 to $159 million, with an effective tax rate of 22%, for the three months ended September 30, 2021, a decrease of $10 million. The decrease was primarily due to unfavorable adjustments related to the West Virginia law change effecting apportionment and sourcing methodologies resulting in lower income tax benefit for the period ending September 30, 2021. ​ 48 Table of Contents Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2021 The operating results of our reportable segments were as follows for the nine months ended September 30, 2020 and 2021 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nine Months Ended September 30, 2020 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ Elimination of ​ ​ ​ ​ ​ ​ ​ ​ ​ Investment in ​ Intersegment ​ ​ ​ ​ ​ Exploration ​ ​ ​ Antero ​ Transactions and ​ ​ ​ ​ ​ and ​ ​ ​ Midstream ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Corporation Affiliates Total ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 1,214,801 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,214,801 ​ Natural gas liquids sales ​ ​ 797,296 ​ ​ — ​ ​ — ​ ​ — ​ ​ 797,296 ​ Oil sales ​ ​ 78,233 ​ ​ — ​ ​ — ​ ​ — ​ ​ 78,233 ​ Commodity derivative fair value losses ​ ​ (116,933) ​ ​ — ​ ​ — ​ ​ — ​ ​ (116,933) ​ Gathering, compression, water handling and treatment ​ ​ — ​ ​ — ​ ​ 749,870 ​ ​ (749,870) ​ ​ — ​ Marketing ​ ​ — ​ ​ 201,855 ​ ​ — ​ ​ — ​ ​ 201,855 ​ Amortization of deferred revenue, VPP ​ ​ 5,175 ​ ​ — ​ ​ — ​ ​ — ​ ​ 5,175 ​ Other income (loss) ​ ​ 2,180 ​ ​ — ​ ​ (53,011) ​ ​ 53,011 ​ ​ 2,180 ​ Total revenue ​ $ 1,980,752 ​ ​ 201,855 ​ ​ 696,859 ​ ​ (696,859) ​ ​ 2,182,607 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 71,836 ​ ​ — ​ ​ — ​ ​ — ​ ​ 71,836 ​ Gathering and compression ​ ​ 616,785 ​ ​ — ​ ​ 128,847 ​ ​ (128,847) ​ ​ 616,785 ​ Processing ​ ​ 697,716 ​ ​ — ​ ​ — ​ ​ — ​ ​ 697,716 ​ Transportation ​ ​ 562,583 ​ ​ — ​ ​ — ​ ​ — ​ ​ 562,583 ​ Production and ad valorem taxes ​ ​ 71,481 ​ ​ — ​ ​ — ​ ​ — ​ ​ 71,481 ​ Marketing ​ ​ — ​ ​ 334,906 ​ ​ — ​ ​ — ​ ​ 334,906 ​ Exploration ​ ​ 895 ​ ​ — ​ ​ — ​ ​ — ​ ​ 895 ​ Impairment of oil and gas properties ​ ​ 155,962 ​ ​ — ​ ​ — ​ ​ — ​ ​ 155,962 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 665,491 ​ ​ (665,491) ​ ​ — ​ Depletion, depreciation, and amortization ​ ​ 652,130 ​ ​ — ​ ​ 81,889 ​ ​ (81,889) ​ ​ 652,130 ​ Accretion of asset retirement obligations ​ ​ 3,330 ​ ​ — ​ ​ 142 ​ ​ (142) ​ ​ 3,330 ​ General and administrative (excluding equity-based compensation) ​ ​ 84,263 ​ ​ — ​ ​ 29,478 ​ ​ (29,478) ​ ​ 84,263 ​ Equity-based compensation ​ ​ 17,001 ​ ​ — ​ ​ 9,713 ​ ​ (9,713) ​ ​ 17,001 ​ Contract termination and rig stacking and other expenses ​ ​ 12,317 ​ ​ — ​ ​ 13,920 ​ ​ (13,920) ​ ​ 12,317 ​ Total operating expenses ​ ​ 2,946,299 ​ ​ 334,906 ​ ​ 929,480 ​ ​ (929,480) ​ ​ 3,281,205 ​ Operating loss ​ $ (965,547) ​ ​ (133,051) ​ ​ (232,621) ​ ​ 232,621 ​ ​ (1,098,598) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings (loss) of unconsolidated affiliates ​ $ (83,408) ​ ​ — ​ ​ 63,197 ​ ​ (63,197) ​ ​ (83,408) ​ ​ ​ 49 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nine Months Ended September 30, 2021 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ Elimination of ​ ​ ​ ​ ​ ​ ​ ​ ​ Investment in ​ Intersegment ​ ​ ​ ​ ​ Exploration ​ ​ ​ Antero ​ Transactions and ​ ​ ​ ​ ​ and ​ ​ ​ Midstream ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Corporation Affiliates Total ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 2,231,558 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,231,558 ​ Natural gas liquids sales ​ ​ 1,503,027 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,503,027 ​ Oil sales ​ ​ 153,326 ​ ​ — ​ ​ — ​ ​ — ​ ​ 153,326 ​ Commodity derivative fair value losses ​ ​ (2,260,062) ​ ​ — ​ ​ — ​ ​ — ​ ​ (2,260,062) ​ Gathering, compression, water handling and treatment ​ ​ — ​ ​ — ​ ​ 734,716 ​ ​ (734,716) ​ ​ — ​ Marketing ​ ​ — ​ ​ 562,928 ​ ​ — ​ ​ — ​ ​ 562,928 ​ Amortization of deferred revenue, VPP ​ ​ 33,833 ​ ​ — ​ ​ — ​ ​ — ​ ​ 33,833 ​ Gain on sale of assets ​ ​ 2,827 ​ ​ ​ ​ ​ — ​ ​ — ​ ​ 2,827 ​ Other income (loss) ​ 551 ​ ​ — ​ ​ (53,004) ​ ​ 53,004 ​ ​ 551 ​ Total revenue ​ $ 1,665,060 ​ ​ 562,928 ​ ​ 681,712 ​ ​ (681,712) ​ ​ 2,227,988 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 71,555 ​ ​ — ​ ​ — ​ ​ — ​ ​ 71,555 ​ Gathering and compression ​ ​ 663,176 ​ ​ — ​ ​ 118,368 ​ ​ (118,368) ​ ​ 663,176 ​ Processing ​ ​ 601,040 ​ ​ — ​ ​ — ​ ​ — ​ ​ 601,040 ​ Transportation ​ ​ 610,448 ​ ​ — ​ ​ — ​ ​ — ​ ​ 610,448 ​ Production and ad valorem taxes ​ ​ 130,610 ​ ​ — ​ ​ — ​ ​ — ​ ​ 130,610 ​ Marketing ​ ​ — ​ ​ 627,822 ​ ​ — ​ ​ — ​ ​ 627,822 ​ Exploration ​ ​ 6,092 ​ ​ — ​ ​ — ​ ​ — ​ ​ 6,092 ​ Impairment of oil and gas properties ​ ​ 69,618 ​ ​ — ​ ​ — ​ ​ — ​ ​ 69,618 ​ Depletion, depreciation, and amortization ​ ​ 564,166 ​ ​ — ​ ​ 80,956 ​ ​ (80,956) ​ ​ 564,166 ​ Accretion of asset retirement obligations ​ ​ 2,947 ​ ​ — ​ ​ 347 ​ ​ (347) ​ ​ 2,947 ​ General and administrative (excluding equity-based compensation) ​ ​ 93,504 ​ ​ — ​ ​ 36,665 ​ ​ (36,665) ​ ​ 93,504 ​ Equity-based compensation ​ ​ 15,189 ​ ​ — ​ ​ 10,326 ​ ​ (10,326) ​ ​ 15,189 ​ Contract termination and rig stacking and other expenses ​ ​ 4,305 ​ ​ — ​ ​ 8,243 ​ ​ (8,243) ​ ​ 4,305 ​ Total operating expenses ​ ​ 2,832,650 ​ ​ 627,822 ​ ​ 254,905 ​ ​ (254,905) ​ ​ 3,460,472 ​ Operating income (loss) ​ $ (1,167,590) ​ ​ (64,894) ​ ​ 426,807 ​ ​ (426,807) ​ ​ (1,232,484) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 57,621 ​ ​ — ​ ​ 66,347 ​ ​ (66,347) ​ ​ 57,621 ​ ​ ​ 50 Table of Contents Exploration and Production Segment The following table sets forth selected operating data of the exploration and production segment for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2021: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Amount of ​ ​ ​ ​ ​ ​ Nine Months Ended September 30, ​ Increase ​ Percent ​ ​ ​ 2020 2021 (Decrease) Change ​ ​ Production data (1) (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (Bcf) ​ ​ 649 ​ ​ 621 ​ ​ (28) ​ (4) % ​ C2 Ethane (MBbl) ​ ​ 14,686 ​ ​ 13,132 ​ ​ (1,554) ​ (11) % ​ C3+ NGLs (MBbl) ​ ​ 36,167 ​ ​ 30,624 ​ ​ (5,543) ​ (15) % ​ Oil (MBbl) ​ ​ 3,308 ​ ​ 2,832 ​ ​ (476) ​ (14) % ​ Combined (Bcfe) ​ ​ 974 ​ ​ 900 ​ ​ (74) ​ (8) % ​ Daily combined production (MMcfe/d) ​ ​ 3,554 ​ ​ 3,297 ​ ​ (257) ​ (7) % ​ Average prices before effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 1.87 ​ ​ 3.60 ​ ​ 1.73 ​ 93 % ​ C2 Ethane (per Bbl) ​ $ 5.85 ​ ​ 10.47 ​ ​ 4.62 ​ 79 % ​ C3+ NGLs (per Bbl) ​ $ 19.67 ​ ​ 44.59 ​ ​ 24.92 ​ 127 % ​ Oil (per Bbl) ​ $ 23.65 ​ ​ 54.14 ​ ​ 30.49 ​ 129 % ​ Weighted Average Combined (per Mcfe) ​ $ 2.15 ​ ​ 4.32 ​ ​ 2.17 ​ 101 % ​ Average realized prices after effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 2.80 ​ ​ 3.16 ​ ​ 0.36 ​ 13 % ​ C2 Ethane (per Bbl) ​ $ 5.72 ​ ​ 10.24 ​ ​ 4.52 ​ 79 % ​ C3+ NGLs (per Bbl) ​ $ 22.25 ​ ​ 38.11 ​ ​ 15.86 ​ 71 % ​ Oil (per Bbl) ​ $ 38.00 ​ ​ 51.34 ​ ​ 13.34 ​ 35 % ​ Weighted Average Combined (per Mcfe) ​ $ 2.91 ​ ​ 3.79 ​ ​ 0.88 ​ 30 % ​ Average costs (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 0.07 ​ ​ 0.08 ​ ​ 0.01 ​ 14 % ​ Gathering and compression ​ $ 0.63 ​ ​ 0.74 ​ ​ 0.11 ​ 17 % ​ Processing ​ $ 0.72 ​ ​ 0.67 ​ ​ (0.05) ​ (7) % ​ Transportation ​ $ 0.58 ​ ​ 0.68 ​ ​ 0.10 ​ 17 % ​ Production and ad valorem taxes ​ $ 0.07 ​ ​ 0.15 ​ ​ 0.08 ​ 114 % ​ Marketing expense, net ​ $ 0.14 ​ ​ 0.07 ​ ​ (0.07) ​ (50) % ​ Depletion, depreciation, amortization, and accretion ​ $ 0.67 ​ ​ 0.63 ​ ​ (0.04) ​ (6) % ​ General and administrative (excluding equity-based compensation) ​ $ 0.09 ​ ​ 0.10 ​ ​ 0.01 ​ 11 % ​ (1) Production data excludes volumes related to the VPP. See Note 3— Transactions to the unaudited condensed consolidated financial statements for more information. (2) Average sales prices shown in the table reflect both 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. 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 does not necessarily reflect their relative economic value. (3) The average realized price for the nine months ended September 30, 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 would have been $3.46 per Mcf. Natural gas sales . Revenues from sales of natural gas increased from $1.2 billion for the nine months ended September 30, 2020 to $2.2 billion, which included litigation proceeds of $85 million, for the nine months ended September 30, 2021, an increase of $1.0 billion, or 84%. See Note 14— Contingencies to the unaudited condensed consolidated financial statements for more information on the litigation proceeds. Excluding net litigation proceeds, lower natural gas production volumes during the nine months ended September 30, 2021 accounted for an approximate $53 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), and increases in commodity prices (excluding the effects of derivative settlements) accounted for an approximate $984 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). 51 Table of Contents NGLs sales . Revenues from sales of NGLs increased from $797 million for the nine months ended September 30, 2020 to $1.5 billion for the nine months ended September 30, 2021, an increase of $706 million, or 89% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Lower NGLs production volumes accounted for an approximate $118 million decrease in year-over-year NGL revenues (calculated as the change in year-to-year volumes times the prior year average price), and increases in commodity prices, excluding the effects of derivative settlements, accounted for an approximate $824 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Oil sales . Revenues from sales of oil increased from $78 million for the nine months ended September 30, 2020 to $153 million for the nine months ended September 30, 2021, an increase of $75 million, or 96% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Lower oil production volumes accounted for a $11 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price), and increases in commodity prices, excluding the effects of derivative settlements, accounted for an approximate $86 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Commodity derivative fair value gains (losses). To achieve more predictable cash flows, and to reduce our exposure to price fluctuations, we enter into fixed for variable price swap contracts, 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 nine months ended September 30, 2020, our commodity hedges resulted in derivative fair value losses of $117 million. For the nine months ended September 30, 2021, our commodity hedges resulted in derivative fair value loss of $2.3 billion. Commodity derivative fair value losses included $759 million of cash proceeds for gains on settled derivatives for the nine months ended September 30, 2020. For the nine months ended September 30, 2021, commodity derivative fair value losses included $481 million of cash payments on commodity derivative losses as well as $5 million for payments on derivative monetizations. 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 increased from $5 million for the nine months ended September 30, 2020 to $34 million for the nine months ended September 30, 2021 as a result of the VPP closing in August 2020. Under the terms of the agreement, the production volumes are delivered at approximately $1.61 per MMBtu over the contractual term. See Note 3—Transactions to the unaudited condensed consolidated financial statements for more information on this transaction. Lease operating expense . Lease operating expense was $72 million for each of the nine months ended September 30, 2020 and 2021. On a per unit basis, lease operating expenses increased from $0.07 per Mcfe for the nine months ended September 30, 2020 to $0.08 per Mcfe for the three months ended September 30, 2021 primarily due to lower production volumes. Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense remained relatively flat at $1.9 billion for both the nine months ended September 30, 2020 and 2021. Gathering and compression costs increased from $0.63 per Mcfe for the nine months ended September 30, 2020 to $0.74 per Mcfe for the nine months ended September 30, 2021, primarily due to higher fuel costs as a result of increased natural gas prices and $36 million in incentive fee rebates from Antero Midstream Corporation received during the nine months ended September 30, 2020 that were not received during the nine months ended September 30, 2021. Processing costs decreased from $0.72 per Mcfe for the nine months ended September 30, 2020 to $0.67 per Mcfe for the nine months ended September 30, 2021, due to a decrease in C3+ NGL volumes as compared to total production volumes between periods, partially offset by increased NGL pipeline and terminaling fees from higher NGL volumes taken in-kind between periods. Transportation costs increased from $0.58 per Mcfe for the nine months ended September 30, 2020 to $0.68 per Mcfe for the nine months ended September 30, 2021 primarily due to increased utilization on higher tariff pipelines to the Midwest and Gulf Coast between periods. ​ Production and ad valorem tax expense. Production and ad valorem taxes increased from $71 million for the nine months ended September 30, 2020 to $131 million for the nine months ended September 30, 2021, an increase of $60 million, or 83% primarily due to higher commodity prices between periods and $5 million for the litigation judgment. Production and ad valorem 52 Table of Contents taxes as a percentage of natural gas revenues remained consistent at 6% in each of the nine months ended September 30, 2020 and 2021. Impairment of oil and gas properties . Impairment of oil and gas properties decreased from $ 156 million for the nine months ended September 30, 2020 to $ 70 million for the nine months ended September 30, 2021 , a decrease of $86 million, or 55%, 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. Depletion, depreciation, and amortization expense . DD&A expense decreased from $652 million for the nine months ended September 30, 2020 to $564 million for the nine months ended September 30, 2021, a decrease of $88 million, or 13%, primarily as a result of increased proved reserve volumes between periods due to higher commodity prices as well as lower production volumes between periods. DD&A per Mcfe remained relatively consistent at $0.67 per Mcfe and $0.63 per Mcfe during the nine months ended September 30, 2020 and 2021, respectively. General and administrative expense . General and administrative expense (excluding equity-based compensation expense) increased from $84 million for the nine months ended September 30, 2020 to $94 million for the nine months ended September 30, 2021, an increase of $10 million, or 11%. The increase was primarily due to higher salary and wage expense between periods, which includes our annual incentive program that was significantly reduced during 2020. We had 520 and 506 employees as of September 30, 2020 and 2021, respectively. On a per-unit basis, general and administrative expense excluding equity-based compensation increased from $0.09 per Mcfe during the nine months ended September 30, 2020 to $0.10 per Mcfe during the nine months ended September 30, 2021 as a result of lower production volumes and higher overall costs between periods. Equity-based compensation expense . Noncash equity-based compensation expense decreased from $17 million for the nine months ended September 30, 2020 to $15 million for the nine months ended September 30, 2021, primarily due to 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 on equity-based compensation awards. Marketing Segment Marketing. 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, to optimize the revenues and mitigate costs from these transportation agreements. We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production to secure guaranteed capacity to favorable markets. Net marketing expenses decreased from $133 million, or $0.14 per Mcfe, for the nine months ended September 30, 2020 to $65 million, or $0.07 per Mcfe, for the nine months ended September 30, 2021. The decrease was driven by higher marketing volumes and margins that mitigated some of our excess firm transportation expense. Marketing revenues increased from $202 million for the nine months ended September 30, 2020 to $563 million for the nine months ended September 30, 2021, an increase of $361 million due to increased marketing volumes. Marketing expenses increased from $335 million for the nine months ended September 30, 2020 to $628 million for the nine months ended September 30, 2021, an increase of $293 million, or 87%. Marketing expenses include firm transportation costs related to current excess firm capacity as well as the cost of third-party purchased gas and NGLs. Firm transportation costs included in the expenses above were $122 million and $81 million for the nine months ended September 30, 2020 and 2021, respectively. Equity Method Investment in Antero Midstream Corporation Antero Midstream Corporation. Revenue from the Antero Midstream Corporation segment decreased from $697 million for the nine months ended September 30, 2020 to $682 million for the nine months ended September 30, 2021, a decrease of $15 million, or 2%, primarily due to lower fresh water delivery revenue as a result of decreased well completions period-over-period and lower gathering volumes, partially offset by higher compression revenues as a result of increased throughput between periods. Total operating expenses related to the segment decreased from $929 million for the nine months ended September 30, 2020 to $255 million for the nine months ended September 30, 2021, primarily due to impairments by Antero Midstream Corporation during the nine months ended September 30, 2020 of $89 million on its freshwater pipelines and equipment and impairment of goodwill of $575 million. Antero Midstream Corporation’s impairment expense was $2 million for the nine months ended September 30, 2021 due to a lower of cost or market adjustment for pipe inventory. 53 Table of Contents Items Not Allocated to Segments Interest expense. Our interest expense decreased from $153 million for the nine months ended September 30, 2020 to $138 million for the nine months ended September 30, 2021 primarily due to the reduction in debt as a result of our debt repurchases of our unsecured senior notes, paydown of our Prior Credit Facility and increased interest income between periods, partially offset by interest that accrued on the (i) 2026 Convertible Notes, which were issued in August 2020 and (ii) 2026 Notes, 2029 Notes and 2030 Notes, each of which was issued after September 30, 2020. Impairment of equity investment . As of March 31, 2020, we determined that events and circumstances indicated that the carrying value of our equity method investment in Antero Midstream Corporation had experienced an other-than-temporary decline and we recorded an impairment of $611 million. The fair value of the equity method investment in Antero Midstream Corporation was based on the quoted market share price of Antero Midstream Corporation as of March 31, 2020. There was no such impairment for the nine months ended September 30, 2021. Gain (loss) on early extinguishment of debt. During the nine months ended September 30, 2020 , we recognized a gain on early extinguishment of debt of $175 million related to $1.1 billion principal amount of debt that we repurchased at a weighted average discount of 17%. During the nine months ended September 30, 2021 , we equitized $206 million aggregate principal amount of our 2026 Convertible Notes in privately negotiated exchange transactions and as a result, we recognized a loss of $61 million which represents the difference between the fair value of the liability component of the 2026 Convertible Notes and the carrying value of such notes. Additionally, during the nine months ended September 30, 2021, we redeemed (i) the remaining balance of $661 million of our 2022 Notes at par, plus accrued and unpaid interest, (ii) the remaining balance of $574 million of our 2023 Notes at par, plus accrued and unpaid interest and (iii) $175 million of our 2026 Notes at a redemption price of 108.375% of par, plus accrued and unpaid interest and recognized a $22 million loss on early extinguishment of debt for such redemptions. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. ​ Loss on convertible note equitization. During the nine months ended September 30, 2021, we recognized a loss of $51 million for the January Equitization Transactions and the May Equitization Transactions, which represents the consideration paid in excess of the original terms of the 2026 Convertible Notes. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. Transaction expense. Transaction expense decreased from $7 million for the nine months ended September 30, 2020 to $3 million for the nine months ended September 30, 2021, a decreased of $4 million or 53%. Transaction expense for the nine months ended September 30, 2020 included legal and transaction fees associated with the sale of our overriding royalty interest and the creation of Martica, as well as the VPP transaction. For the nine months ended September 30, 2021, transaction expense included legal and transaction fees associated with the drilling partnership. See Note 3—Transactions to the unaudited condensed consolidated financial statements for more information on these transactions. Income tax benefit . Income tax benefit decreased from $421 million, with an effective tax rate of 24%, for the nine months ended September 30, 2020 to $338 million, with an effective tax rate of 23%, for the nine months ended September 30, 2021, a decrease of $83 million. The decrease was primarily due to lower 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 including borrowings under the Prior 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. For information about the impacts of COVID-19 on our capital resources and liquidity, see “—COVID-19 Pandemic.” Based on strip prices as of September 30, 2021, we believe that net cash provided by operating activities, distributions from unconsolidated affiliate, available borrowings under the Credit Facility, capital market transactions and the effects of the drilling partnership 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. 54 Table of Contents 2021 Capital Budget and Capital Spending On February 17, 2021, we announced our net capital budget for 2021 is $635 million, which includes: $590 million for drilling and completion and $45 million for leasehold expenditures. We do not include acquisitions in our capital budget. We periodically review our capital expenditures and adjust our budget and its allocation based on commodity prices, takeaway constraints, operating cash flow and liquidity, and on July 28, 2021, we announced a $22.5 million increase for our leasehold expenditures for 2021 to reflect accelerated leasing activity focused on organically expanding our core liquids rich inventory. As a result, our total net capital budget for 2021 was revised to $657.5 million . ​ For the nine months ended September 30, 2021, our total consolidated capital expenditures, which excludes QL’s working interest share of such costs, were approximately $542 million, including drilling and completion costs of $475 million, leasehold acquisitions of $48 million, and other capital expenditures of $19 million. Cash Flows The following table summarizes our cash flows for the nine months ended September 30, 2020 and 2021: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nine Months Ended September 30, ​ ​ 2020 2021 Net cash provided by operating activities ​ $ 492,510 ​ ​ 1,184,952 ​ Net cash used in investing activities ​ ​ (384,063) ​ ​ (505,455) ​ Net cash used in financing activities ​ ​ (108,447) ​ ​ (679,497) ​ Net increase in cash and cash equivalents ​ $ — ​ ​ — ​ ​ Operating Activities. Net cash provided by operating activities was $493 million and $1.2 billion for the nine months ended September 30, 2020 and 2021, 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, decreased net marketing expense as well as decreased cash utilized for working capital, partially offset by increases in gathering, compression and transportation costs 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. For example, the impact of the COVID-19 outbreak has reduced domestic and international demand for natural gas, NGLs, and oil. These factors are beyond our control and are difficult to predict. Investing Activities. Cash flows used in investing activities increased from $384 million for the nine months ended September 30, 2020 to $505 million for the nine months ended September 30, 2021 , primarily due to $216 million in proceeds from the VPP and $125 million in settlement of the water earnout impacting the nine months ended September 30, 2020, partially offset by a decrease in capital expenditures of $215 million during the nine months ended September 30, 2021 as compared to the same period in 2020. Financing Activities . Net cash flows used in financing activities increased from $108 million for the nine months ended September 30, 2020 to $679 million for the nine months ended September 30, 2021. During the nine months ended September 30, 2021, we issued $500 million aggregate principal amount of 2026 Notes, $700 million aggregate principal amount of 2029 Notes and $600 million aggregate principal amount of 2030 Notes (net of $23 million of aggregate debt issuance costs), of which proceeds were used to (i) redeem $661 million of our 2022 Notes, which were fully retired, (ii) redeem $574 million of our 2023 Notes, which were fully retired (ii) redeem $175 million of our 2026 Notes and (iv) partially repay borrowings on our Prior Credit Facility. Also, during the nine months ended September 30, 2021, we completed the January Share Offering and the May Share Offering and used the proceeds and approximately $89 million of borrowings under the Prior Credit Facility to repurchase $206 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions. Additionally, during the nine months ended September 30, 2021, we received a $51 million payment from Martica and distributed $65 million to the noncontrolling interest in Martica. During the nine months ended September 30, 2020, we repurchased (i) $1.1 billion principal amount of debt at a weighted average discount of 17% for $900 million of cash and (ii) $43 million of our common stock at weighted average price of $1.54 per share. 55 Table of Contents Debt Agreements Senior Secured Revolving Credit Facility Antero Resources has a senior secured revolving credit facility with a consortium of bank lenders. On October 26, 2021, Antero Resources entered into an amended and restated senior secured revolving credit facility. References to the (i) “Prior Credit Facility” refers to the senior secured revolving credit facility in effect for periods before October 26, 2021, (ii) “New Credit Facility” refers to the senior secured revolving credit facility in effect on or after October 26, 2021 and (ii) “Credit Facility” refers to Prior Credit Facility and New Credit Facility collectively. Borrowings under the New Credit Facility are subject to borrowing base limitations based on the collateral value of our assets and are subject to regular semi-annual redeterminations. As of October 26, 2021, the borrowing base was $3.5 billion and lender commitments were $1.5 billion. The next redetermination of the borrowing base is scheduled to occur in April 2022. The maturity date of the New Credit Facility is the earlier of (i) October 26, 2026 and (ii) the date that is 180 days prior to the earliest stated redemption date of any series of Antero’s senior notes. As of September 30, 2021, we had $98 million borrowings and had $742 million of letters of credit outstanding under the Prior Credit Facility. The New Credit Facility provides for borrowing under either an Adjusted Term Secured Overnight Financing Rate (“SOFR”), an Adjusted Daily Simple SOFR or an Alternate Base Rate (each as defined in the New Credit Facility). The New Credit Facility contains restrictive covenants that may limit our ability to, among other things: ● incur additional indebtedness; ● sell assets; ● make loans to others; ● make investments; ● enter into mergers; ● pay dividends; ● hedge future production; ● incur liens; and ● engage in certain other transactions without the prior consent of the lenders. The New Credit Facility also requires us to maintain the following financial ratios (subject to certain exceptions): The current ratio and the leverage ratio shall be tested quarterly commencing with the quarter ending December 31, 2021. ● a minimum consolidated current ratio of 1.0 to 1.0 at the end of each fiscal quarter; and ● a maximum leverage ratio of total debt to EBITDAX for the trailing four quarter period of 4.00 to 1.00 at the end of each fiscal quarter. ​ We were in compliance with the applicable covenants and ratios as of December 31, 2020 and September 30, 2021 under the Prior Credit Facility. As of September 30, 2021, our current ratio was 2.7 to 1.0 and our interest coverage ratio was 15.0 to 1.0. See Note 7—Long Term Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q for more information on our Credit Facility. Senior Notes and Convertible Senior Notes 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 2020 Form 10-K for information on our senior notes. 56 Table of Contents Non-GAAP Financial Measures Adjusted EBITDAX is a non-GAAP financial measure that we define as net income (loss), including noncontrolling interests, before interest expense, interest income, gains or losses from commodity derivatives, amortization of deferred revenue, gain on sale of assets but including net cash receipts or payments on derivative instruments included in derivative gains or losses other than proceeds from and payments for derivative monetizations, income taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain (loss) on early extinguishment of debt, contract termination and rig stacking costs, equity in earnings (loss) of unconsolidated affiliate, transaction fees and loss on convertible note equitization. Adjusted EBITDAX as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income or loss, net income or loss, cash flows provided by operating, investing, and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding our capital structure, borrowings, interest costs, capital expenditures, working capital movement, or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure: ● is widely used by investors in the oil and natural gas industry to measure operating performance without regard to items excluded from the calculation of such term, which may vary substantially from company to company depending upon accounting methods and the book value of assets, capital structure and the method by which assets were acquired, among other factors; ● helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital and legal structure from our operating structure; ● is used by our management team for various purposes, including as a measure of our operating performance, in presentations to our Board of Directors, and as a basis for strategic planning and forecasting; and ● is used by our Board of Directors as a performance measure in determining executive compensation. There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effects of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies, and the different methods of calculating Adjusted EBITDAX reported by different companies. The following table represents a reconciliation of our net income (loss), including noncontrolling interest, to Adjusted EBITDAX and a reconciliation of our Adjusted EBITDAX to net cash provided by operating activities per our unaudited condensed consolidated statements of cash flows, in each case, for the three and nine months ended September 30, 2020 and 2021 (in thousands). Adjusted EBITDAX also excludes the noncontrolling interests in Martica and these adjustments are disclosed in the table below as Martica related adjustments. 57 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended September 30, ​ Nine Months Ended September 30, ​ ​ 2020 2021 ​ 2020 2021 ​ Reconciliation of net loss to Adjusted EBITDAX: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net loss and comprehensive loss attributable to Antero Resources Corporation ​ $ (535,613) ​ ​ (549,318) ​ ​ (1,337,727) ​ ​ (1,088,284) ​ Net loss and comprehensive loss attributable to noncontrolling interests ​ ​ (18,233) ​ ​ (17,257) ​ ​ (17,997) ​ ​ (23,846) ​ Unrealized commodity derivative losses ​ ​ 748,791 ​ ​ 834,334 ​ ​ 875,811 ​ ​ 1,774,410 ​ Payments for (proceeds from) derivative monetizations ​ ​ (18,073) ​ ​ — ​ ​ (18,073) ​ ​ 4,569 ​ Amortization of deferred revenue, VPP ​ ​ (5,175) ​ ​ (11,404) ​ ​ (5,175) ​ ​ (33,833) ​ Loss on sale of assets ​ ​ — ​ ​ (539) ​ ​ — ​ ​ (2,827) ​ Interest expense, net ​ ​ 48,043 ​ ​ 45,414 ​ ​ 152,956 ​ ​ 138,120 ​ Loss (gain) on early extinguishment of debt ​ ​ (55,633) ​ ​ 16,567 ​ ​ (175,365) ​ ​ 82,836 ​ Loss on convertible note equitizations ​ ​ — ​ ​ — ​ ​ — ​ ​ 50,777 ​ Provision for income tax benefit ​ ​ (168,778) ​ ​ (158,656) ​ ​ (421,167) ​ ​ (337,568) ​ Depletion, depreciation, amortization, and accretion ​ ​ 239,533 ​ ​ 183,638 ​ ​ 655,460 ​ ​ 567,113 ​ Impairment of oil and gas properties ​ ​ 29,392 ​ ​ 26,253 ​ ​ 155,962 ​ ​ 69,618 ​ Impairment of equity method investment ​ ​ — ​ ​ — ​ ​ 610,632 ​ ​ — ​ Exploration expense ​ ​ 454 ​ ​ 235 ​ ​ 895 ​ ​ 6,092 ​ Equity-based compensation expense ​ ​ 5,699 ​ ​ 5,298 ​ ​ 17,001 ​ ​ 15,189 ​ Equity in (earnings) loss of unconsolidated affiliate ​ ​ (24,419) ​ ​ (21,450) ​ ​ 83,408 ​ ​ (57,621) ​ Dividends from unconsolidated affiliate ​ ​ 42,755 ​ ​ 31,285 ​ ​ 128,267 ​ ​ 105,325 ​ Contract termination and rig stacking ​ ​ 1,246 ​ ​ 3,370 ​ ​ 12,317 ​ ​ 4,305 ​ Transaction expense ​ ​ 524 ​ ​ 626 ​ ​ 6,662 ​ ​ 3,102 ​ ​ ​ ​ 290,513 ​ ​ 388,396 ​ ​ 723,867 ​ ​ 1,277,477 ​ Martica related adjustments (1) ​ ​ (18,072) ​ ​ (30,197) ​ ​ (21,172) ​ ​ (80,436) ​ Adjusted EBITDAX ​ $ 272,441 ​ ​ 358,199 ​ ​ 702,695 ​ ​ 1,197,041 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Reconciliation of our Adjusted EBITDAX to net cash provided by operating activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Adjusted EBITDAX ​ $ 272,441 ​ ​ 358,199 ​ ​ 702,695 ​ ​ 1,197,041 ​ Martica related adjustments (1) ​ ​ 18,072 ​ ​ 30,197 ​ ​ 21,172 ​ ​ 80,436 ​ Interest expense, net ​ ​ (48,043) ​ ​ (45,414) ​ ​ (152,956) ​ ​ (138,120) ​ Exploration expense ​ ​ (454) ​ ​ (235) ​ ​ (895) ​ ​ (6,092) ​ Changes in current assets and liabilities ​ ​ (80,308) ​ ​ (28,316) ​ ​ (78,891) ​ ​ 53,541 ​ Transaction expense ​ ​ (524) ​ ​ (626) ​ ​ (6,662) ​ ​ (3,102) ​ Proceeds from (payments for) derivative monetizations ​ ​ 18,073 ​ ​ — ​ ​ 18,073 ​ ​ (4,569) ​ Other items ​ ​ (3,387) ​ ​ (1,125) ​ ​ (10,026) ​ ​ 5,817 ​ Net cash provided by operating activities ​ $ 175,870 ​ ​ 312,680 ​ ​ 492,510 ​ ​ 1,184,952 ​ (1) Adjustments reflect noncontrolling interests in Martica not otherwise adjusted in amounts above. 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 measures of future cash flows, and impairment of proved properties. We provide an expanded discussion of our more significant accounting policies, 58 Table of Contents estimates and judgments in the 2020 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 2020 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 September 30, 2021, the estimated undiscounted future net cash flows exceeded the carrying amount and no further evaluation was required. We have not recorded any impairment expenses associated with our proved properties during the three and nine months ended September 30, 2020 and 2021. Estimated undiscounted future net cash flows are very sensitive to commodity price swings at current commodity price levels and a relatively small 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 September 30, 2021, 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 As of September 30, 2021, we did not have any off balance sheet arrangements other than contractual commitments for firm transportation, gas processing and fractionation, gathering, and compression services and land payment obligations. See Note 13—Commitments to the unaudited condensed consolidated financial statements for further information on off balance sheet arrangements. ​