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 June 30, 2022, we held approximately 503,000 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—Sources and Uses of Cash”) 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 a hybrid working arrangement that involves a combination of in-office and remote work-from-home arrangements. 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 protect the health and safety of our employees and contract workers. 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 37 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 203 Bcf of natural gas at a weighted average price of $2.48 per MMBtu and basis swaps for 11 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 as of June 30, 2022, our outstanding letters of credit decreased by $26 million since December 31, 2021. Therefore, 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 June 30, 2022, we had $71 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 $505 million . See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements and “—Capital Resources and Liquidity—Debt Agreements.” Since the onset of the COVID-19 pandemic, we have timely serviced our debt and other obligations. The global economy continues to be impacted by the effects of the COVID-19 pandemic and global events, among other factors . Employment activity has strengthened as demonstrated by the United States Bureau of Labor and Statistics (“BLS”) unemployment rate declining from a high of 15% in April 2020 to 4% in June 2022. However, the economy is also experiencing elevated inflation levels as a result of global supply and demand imbalances. For example, the BLS Consumer Price Index (“CPI”) for all urban consumers increased 9% from June 2021 to June 2022 as compared to the average annual increase of 3% over the previous 10 years. Inflationary pressures, particularly as they relate to certain of our long-term contracts with CPI-based adjustments, 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. For example, we announced a 7% increase to our drilling and completion capital budget, which primarily reflects higher diesel and steel costs and development optimization through the retention of preferred crews through 2022. See “—Capital Resources and Liquidity—2022 Capital Budget and Capital Spending” for more information. Financing Highlights Debt Repurchase Program During the six months ended June 30, 2022, we fully redeemed the remaining $585 million of our 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. Additionally, we repurchased on the open market (i) $13 million of our 8.375% senior notes due July 15, 2026 (the “2026 Notes”) and (ii) $50 million of our 7.625% senior notes due February 1, 2029 (the “2029 Notes”). See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. 38 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 and six months ended June 30, 2022, we repurchased approximately 5 million shares at a total cost of $193 million and approximately 9 million shares of our common stock at a total cost of $293 million, respectively. 2026 Convertible Notes Conversion On June 29, 2022, a noteholder elected to convert $4 million in aggregate principal amount of the 4.25% convertible senior notes due 2026 (“2026 Convertible Notes”) pursuant to their terms. We elected to settle this conversion by issuing approximately 1 million shares of common stock to the noteholder. See Note 7—Long-Term Debt 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 June 30, 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 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ July-December 2022 ​ Henry Hub ​ 203 Bcf ​ $ 2.48 /MMBtu ​ January-December 2023 ​ Henry Hub ​ 16 Bcf ​ ​ 2.37 /MMBtu ​ ​ ​ ​ ​ 219 Bcf ​ ​ 2.48 /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 June 30, 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 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ July-December 2022 ​ NYMEX to TCO ​ 12 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 ​ ​ ​ ​ ​ 48 Bcf ​ ​ 0.525 /MMBtu ​ ​ As of June 30, 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 78 Bcf remaining through December 31, 2026 at a weighted average strike price of $2.55 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 June 30, 2022, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of $1.1 billion. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information. 39 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 June 30, 2021 Compared to June 30, 2022 The operating results of our reportable segments were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended June 30, 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 ​ $ 626,520 ​ ​ — ​ ​ — ​ ​ — ​ ​ 626,520 ​ Natural gas liquids sales ​ ​ 464,381 ​ ​ — ​ ​ — ​ ​ — ​ ​ 464,381 ​ Oil sales ​ ​ 51,906 ​ ​ — ​ ​ — ​ ​ — ​ ​ 51,906 ​ Commodity derivative fair value losses ​ ​ (831,840) ​ ​ — ​ ​ — ​ ​ — ​ ​ (831,840) ​ Gathering, compression, water handling and treatment ​ ​ — ​ ​ — ​ ​ 250,455 ​ ​ (250,455) ​ ​ — ​ Marketing ​ ​ — ​ ​ 165,453 ​ ​ — ​ ​ — ​ ​ 165,453 ​ Amortization of deferred revenue, VPP ​ ​ 11,279 ​ ​ — ​ ​ — ​ ​ — ​ ​ 11,279 ​ Other loss ​ (619) ​ ​ — ​ ​ (17,668) ​ ​ 17,668 ​ ​ (619) ​ Total revenue ​ $ 321,627 ​ ​ 165,453 ​ ​ 232,787 ​ ​ (232,787) ​ ​ 487,080 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 21,645 ​ ​ — ​ ​ — ​ ​ — ​ ​ 21,645 ​ Gathering and compression ​ ​ 224,073 ​ ​ — ​ ​ 39,555 ​ ​ (39,555) ​ ​ 224,073 ​ Processing ​ ​ 209,627 ​ ​ — ​ ​ — ​ ​ — ​ ​ 209,627 ​ Transportation ​ ​ 207,662 ​ ​ — ​ ​ — ​ ​ — ​ ​ 207,662 ​ Production and ad valorem taxes ​ ​ 33,694 ​ ​ — ​ ​ — ​ ​ — ​ ​ 33,694 ​ Marketing ​ ​ — ​ ​ 198,994 ​ ​ — ​ ​ — ​ ​ 198,994 ​ Exploration ​ ​ 5,638 ​ ​ — ​ ​ — ​ ​ — ​ ​ 5,638 ​ General and administrative (excluding equity-based compensation) ​ ​ 27,928 ​ ​ — ​ ​ 11,192 ​ ​ (11,192) ​ ​ 27,928 ​ Equity-based compensation ​ ​ 4,249 ​ ​ — ​ ​ 3,059 ​ ​ (3,059) ​ ​ 4,249 ​ Depletion, depreciation and amortization ​ ​ 187,330 ​ ​ — ​ ​ 26,619 ​ ​ (26,619) ​ ​ 187,330 ​ Impairment of oil and gas properties ​ ​ 9,303 ​ ​ — ​ ​ — ​ ​ — ​ ​ 9,303 ​ Accretion of asset retirement obligations ​ ​ 1,331 ​ ​ — ​ ​ 114 ​ ​ (114) ​ ​ 1,331 ​ Contract termination and other expenses ​ ​ 844 ​ ​ — ​ ​ 849 ​ ​ (849) ​ ​ 844 ​ Gain on sale of assets ​ ​ (2,288) ​ ​ — ​ ​ — ​ ​ — ​ ​ (2,288) ​ Total operating expenses ​ ​ 931,036 ​ ​ 198,994 ​ ​ 81,388 ​ ​ (81,388) ​ ​ 1,130,030 ​ Operating income (loss) ​ $ (609,409) ​ ​ (33,541) ​ ​ 151,399 ​ ​ (151,399) ​ ​ (642,950) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 17,477 ​ ​ — ​ ​ 21,515 ​ ​ (21,515) ​ ​ 17,477 ​ ​ ​ 40 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended June 30, 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 ​ $ 1,558,994 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,558,994 ​ Natural gas liquids sales ​ ​ 702,388 ​ ​ — ​ ​ — ​ ​ — ​ ​ 702,388 ​ Oil sales ​ ​ 89,185 ​ ​ — ​ ​ — ​ ​ — ​ ​ 89,185 ​ Commodity derivative fair value losses ​ ​ (265,662) ​ ​ — ​ ​ — ​ ​ — ​ ​ (265,662) ​ Gathering, compression, water handling and treatment ​ ​ — ​ ​ — ​ ​ 246,575 ​ ​ (246,575) ​ ​ — ​ Marketing ​ ​ — ​ ​ 106,150 ​ ​ — ​ ​ — ​ ​ 106,150 ​ Amortization of deferred revenue, VPP ​ ​ 9,375 ​ ​ — ​ ​ — ​ ​ — ​ ​ 9,375 ​ Other income (loss) ​ 1,255 ​ ​ — ​ ​ (17,668) ​ ​ 17,668 ​ ​ 1,255 ​ Total revenue ​ $ 2,095,535 ​ 106,150 ​ 228,907 ​ (228,907) ​ ​ 2,201,685 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 25,253 ​ ​ — ​ ​ — ​ ​ — ​ ​ 25,253 ​ Gathering and compression ​ ​ 223,650 ​ ​ — ​ ​ 43,299 ​ ​ (43,299) ​ ​ 223,650 ​ Processing ​ ​ 219,100 ​ ​ — ​ ​ — ​ ​ — ​ ​ 219,100 ​ Transportation ​ ​ 213,462 ​ ​ — ​ ​ — ​ ​ — ​ ​ 213,462 ​ Production and ad valorem taxes ​ ​ 81,842 ​ ​ — ​ ​ — ​ ​ — ​ ​ 81,842 ​ Marketing ​ ​ — ​ ​ 131,298 ​ ​ — ​ ​ — ​ ​ 131,298 ​ Exploration and mine expenses ​ ​ 1,394 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,394 ​ General and administrative (excluding equity-based compensation) ​ ​ 36,268 ​ ​ — ​ ​ 10,438 ​ ​ (10,438) ​ ​ 36,268 ​ Equity-based compensation ​ ​ 8,171 ​ ​ — ​ ​ 5,641 ​ ​ (5,641) ​ ​ 8,171 ​ Depletion, depreciation and amortization ​ ​ 173,395 ​ ​ — ​ ​ 35,675 ​ ​ (35,675) ​ ​ 173,395 ​ Impairment of oil and gas properties ​ ​ 23,363 ​ ​ — ​ ​ — ​ ​ — ​ ​ 23,363 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 3,702 ​ ​ (3,702) ​ ​ — ​ Accretion of asset retirement obligations ​ ​ 804 ​ ​ — ​ ​ 64 ​ ​ (64) ​ ​ 804 ​ Contract termination and other expenses ​ ​ 2,096 ​ ​ — ​ ​ 1,724 ​ ​ (1,724) ​ ​ 2,096 ​ Loss (gain) on sale of assets ​ ​ 71 ​ ​ — ​ ​ (32) ​ ​ 32 ​ ​ 71 ​ Total operating expenses ​ ​ 1,008,869 ​ 131,298 ​ 100,511 ​ (100,511) ​ ​ 1,140,167 ​ Operating income (loss) ​ $ 1,086,666 ​ ​ (25,148) ​ ​ 128,396 ​ ​ (128,396) ​ ​ 1,061,518 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 14,713 ​ ​ — ​ ​ 22,824 ​ ​ (22,824) ​ ​ 14,713 ​ ​ ​ 41 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 ​ ​ ​ ​ ​ June 30, ​ Increase ​ Percent ​ ​ ​ 2021 ​ 2022 ​ (Decrease) ​ Change ​ Production data (1) (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (Bcf) ​ ​ 208 ​ ​ 203 ​ ​ (5) ​ (2) % C2 Ethane (MBbl) ​ ​ 4,356 ​ ​ 4,025 ​ ​ (331) ​ (8) % C3+ NGLs (MBbl) ​ ​ 10,440 ​ ​ 10,156 ​ ​ (284) ​ (3) % Oil (MBbl) ​ ​ 940 ​ ​ 906 ​ ​ (34) ​ (4) % Combined (Bcfe) ​ ​ 303 ​ ​ 294 ​ ​ (9) ​ (3) % Daily combined production (MMcfe/d) ​ ​ 3,324 ​ ​ 3,228 ​ ​ (96) ​ (3) % Average prices before effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 3.01 ​ ​ 7.67 ​ ​ 4.66 ​ 155 % C2 Ethane (per Bbl) ​ $ 9.97 ​ ​ 22.42 ​ ​ 12.45 ​ 125 % C3+ NGLs (per Bbl) ​ $ 40.32 ​ ​ 60.28 ​ ​ 19.96 ​ 50 % Oil (per Bbl) ​ $ 55.22 ​ ​ 98.49 ​ ​ 43.27 ​ 78 % Weighted Average Combined (per Mcfe) ​ $ 3.78 ​ ​ 8.00 ​ ​ 4.22 ​ 112 % Average realized prices after effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 2.91 ​ ​ 4.94 ​ ​ 2.03 ​ 70 % C2 Ethane (per Bbl) ​ $ 9.97 ​ ​ 22.42 ​ ​ 12.45 ​ 125 % C3+ NGLs (per Bbl) ​ $ 35.95 ​ ​ 59.84 ​ ​ 23.89 ​ 66 % Oil (per Bbl) ​ $ 52.05 ​ ​ 97.73 ​ ​ 45.68 ​ 88 % Weighted Average Combined (per Mcfe) ​ $ 3.55 ​ ​ 6.10 ​ ​ 2.55 ​ 72 % Average costs (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 0.07 ​ ​ 0.09 ​ ​ 0.02 ​ 29 % Gathering and compression ​ $ 0.74 ​ ​ 0.76 ​ ​ 0.02 ​ 3 % Processing ​ $ 0.69 ​ ​ 0.75 ​ ​ 0.06 ​ 9 % Transportation ​ $ 0.69 ​ ​ 0.73 ​ ​ 0.04 ​ 6 % Production and ad valorem taxes ​ $ 0.11 ​ ​ 0.28 ​ ​ 0.17 ​ 155 % Marketing (revenue) expense, net ​ $ 0.11 ​ ​ 0.09 ​ ​ (0.02) ​ (18) % Depletion, depreciation, amortization and accretion ​ $ 0.62 ​ ​ 0.59 ​ ​ (0.03) ​ (5) % General and administrative (excluding equity-based compensation) ​ $ 0.09 ​ ​ 0.12 ​ ​ 0.03 ​ 33 % * 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. ​ Natural gas sales . Revenues from sales of natural gas increased from $627 million for the three months ended June 30, 2021 to $1.6 billion for the three months ended June 30, 2022, an increase of $932 million, or 149%. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2022 accounted for an approximate $947 million increase in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes). Lower natural gas production volumes accounted for an approximate $15 million decrease in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price). NGLs sales . Revenues from sales of NGLs increased from $464 million for the three months ended June 30, 2021 to $702 million for the three months ended June 30, 2022, an increase of $238 million, or 51%. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2022 accounted for an approximate $253 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). 42 Table of Contents Oil sales . Revenues from sales of oil increased from $52 million for the three months ended June 30, 2021 to $89 million for the three months ended June 30, 2022, an increase of $37 million, or 72%. Higher oil prices, excluding the effects of derivative settlements, accounted for an approximate $39 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 June 30, 2022 accounted for an approximate $2 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 we believe 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 June 30, 2021 and 2022, our commodity hedges resulted in derivative fair value losses of $832 million and $266 million, respectively. For the three months ended June 30, 2021, commodity derivative fair value losses included $70 million of cash payments for settled commodity derivatives as well as $5 million for payments on derivative monetizations. For the three months ended June 30, 2022, commodity derivative fair value losses included $559 million of cash payments for settled commodity derivatives. 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 June 30, 2021 to $9 million for the three months ended June 30, 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 increased from $22 million for the three months ended June 30, 2021 to $25 million for the three months ended June 30, 2022, an increase of $3 million, or 17%, primarily due to higher oilfield service costs and water disposal costs, partially offset by lower production volumes between periods. On a per-unit basis, lease operating expenses increased from $0.07 per Mcfe for the three months ended June 30, 2021 to $0.09 per Mcfe for the three months ended June 30, 2022, primarily due to higher oilfield service costs and water disposal costs. Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense increased from $641 million for the three months ended June 30, 2021 to $656 million for the three months ended June 30, 2022, an increase of $15 million, or 2%, primarily a result of higher processing and transportation costs, partially offset by lower production between periods. Gathering and compression costs increased from $0.74 per Mcfe for the three months ended June 30, 2021 to $0.76 per Mcfe for the three months ended June 30, 2022, primarily due to annual CPI-based adjustments between periods, partially offset by $12 million in incentive fee rebates earned from Antero Midstream during the three months ended June 30, 2022 that were not earned during the three months ended June 30, 2021. Processing costs increased from $0.69 per Mcfe for the three months ended June 30, 2021 to $0.75 per Mcfe for the three months ended June 30, 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 $0.69 per Mcfe for the three months ended June 30, 2021 to $0.73 per Mcfe for the three months ended June 30, 2022 primarily due to higher fuel costs between periods. Production and ad valorem tax expense. Total production and ad valorem taxes increased from $34 million for the three months ended June 30, 2021 to $82 million for the three months ended June 30, 2022, an increase of $48 million, or 143%, primarily due to higher commodity prices between periods. On a per Mcfe basis, production and ad valorem taxes increased from $0.11 per Mcfe for the three months ended June 30, 2021 to $0.28 per Mcfe for the three months ended June 30, 2022. Production and ad valorem taxes as a percentage of natural gas revenues remained consistent at 5% for each of the three months ended June 30, 2021 and 2022. General and administrative expense . General and administrative expense (excluding equity-based compensation expense) increased from $28 million for the three months ended June 30, 2021 to $36 million for the three months ended June 30, 2022, an increase of $8 million, or 30% , primarily due to higher salary and wage expense, professional service fees and office operating costs between periods. On a per-unit basis, general and administrative expense excluding equity-based compensation increased from $0.09 43 Table of Contents per Mcfe for the three months ended June 30, 2021 to $0.12 per Mcfe for the three months ended June 30, 2022, primarily due to higher overall general and administrative expense and lower production volumes between periods. Equity-based compensation expense . Noncash equity-based compensation expense increased from $4 million for the three months ended June 30, 2021 to $8 million for the three months ended June 30, 2022, an increase of $4 million, or 92%, primarily due to an increase in the annual equity awards granted during the second quarter of 2022 as compared to prior years, partially offset by equity award forfeitures. 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 $187 million for the three months ended June 30, 2021 to $173 million for the three months ended June 30, 2022, a decrease of $14 million, or 7%, 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 $0.62 per Mcfe for the three months ended June 30, 2021 to $0.59 per Mcfe June 30, 2022, primarily as a result of increased proved reserve volumes between periods. Impairment of oil and gas properties . Impairment of oil and gas properties increased from $9 million for the three months ended June 30, 2021 to $23 million for the three months ended June 30, 2022, an increase of $14 million, or 151%, primarily related to higher 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. Net marketing expense decreased from $34 million, or $0.11 per Mcfe, for the three months ended June 30, 2021 to $25 million, or $0.09 per Mcfe, for the three months ended June 30, 2022, primarily due to lower volumes partially offset by higher gas marketing margins between periods. Marketing revenue. Marketing revenue decreased from $165 million for the three months ended June 30, 2021 to $106 million for the three months ended June 30, 2022, a decrease of $59 million, or 36%, primarily due to lower marketing volumes between periods, partially offset by increased commodity prices between periods. Lower natural gas marketing volumes accounted for a $285 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher natural gas prices accounted for an approximate $205 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 $3 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher oil prices accounted for an approximate $8 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 $2 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher ethane prices accounted for an approximate $12 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). Marketing expense. Marketing expense decreased from $199 million for the three months ended June 30, 2021 to $131 million for the three months ended June 30, 2022, a decrease of $68 million, or 34%. 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 $67 million, which was partially offset by increased NGL and oil purchases of approximately $9 million and $10 million, respectively, between periods. The total costs decreased primarily due to lower marketing volumes between periods, partially offset by increased commodity prices. Firm transportation costs were $55 million for the three months ended June 30, 2021 and $35 million for the three months ended June 30, 2022, a decrease of $20 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 $233 million for the three months ended June 30, 2021 to $229 million for the three months ended June 30, 2022, a decrease of $4 million, primarily due to a decrease in low pressure revenues due to higher fee rebates earned by us, partially offset by higher compression and high pressure gathering 44 Table of Contents revenues due to increased throughput between periods, as well as higher low pressure, compression, high pressure and water handling fees as a result of an annual CPI-based adjustment. Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $81 million for the three months ended June 30, 2021 to $101 million for the three months ended June 30, 2022, an increase of $20 million, primarily due to an increase in depreciation expense during the three months ended June 30, 2022. This increase is primarily a result of a phased early retirement of an underutilized compressor station, which allows Antero Midstream to relocate and reuse the compressor units and equipment to (i) expand an existing compressor station and (ii) contribute to a new compressor station. There are certain costs associated with the underutilized compressor station that cannot be relocated or reused that will be depreciated over the remaining period of use. Additionally, operating expenses were higher between periods due to increased direct operating costs as a result of higher gathering throughput volumes and two new compressor stations that came online between periods. Discussion of Items Not Allocated to Segments Interest expense. Interest expense decreased from $50 million for the three months ended June 30, 2021 to $34 million for the three months ended June 30, 2022, a decrease of $16 million, or 32%, primarily due to the reduction in debt as a result of the repurchase of certain of our unsecured senior notes between periods. Interest expense includes approximately $3 million and $1 million of amortization of debt issuance costs and debt discounts and premiums for the three months ended June 30, 2021 and 2022, respectively. Loss on early extinguishment of debt. During the three months ended June 30, 2021, we equitized $56 million aggregate principal amount of our 2026 Convertible Notes and as a result, we recognized a loss of $21 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 three months ended June 30, 2021, we redeemed the remaining balance of $574 million of our 5.625% senior notes due June 1, 2023 (the “2023 Notes”) at par, plus accrued and unpaid interest, and recognized a $2 million loss on early extinguishment of debt. During the three months ended June 30, 2022, we repurchased $50 million of our 2029 Notes and $13 million of our 2026 Notes , which resulted in a loss on early debt extinguishment of $4 million. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. Loss on convertible note equitization. During the three months ended June 30, 2021, we recognized a loss of $12 million for the equitization of our 2026 Convertible Notes, 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 June 30, 2022. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. ​ Income tax benefit (expense) . For the three months ended June 30, 2021, we had an income tax benefit of $176 million, with an effective tax rate of 25%, due to a loss before income taxes of $710 million. For the three months ended June 30, 2022, we had income tax expense of $226 million, with an effective tax rate of 22%, due to income before income taxes of $1.0 billion. The decrease in the effective tax rate between periods was primarily due to an income tax benefit for the equity-based awards that vested during the three months ended June 30, 2022 and the impact of tax law changes in West Virginia enacted in 2021. ​ 45 Table of Contents Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2022 The operating results of our reportable segments were as follows for the six months ended June 30, 2021 and 2022 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Six Months Ended June 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 ​ $ 1,346,889 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,346,889 ​ Natural gas liquids sales ​ ​ 904,700 ​ ​ — ​ ​ — ​ ​ — ​ ​ 904,700 ​ Oil sales ​ ​ 96,592 ​ ​ — ​ ​ — ​ ​ — ​ ​ 96,592 ​ Commodity derivative fair value losses ​ ​ (1,009,596) ​ ​ — ​ ​ — ​ ​ — ​ ​ (1,009,596) ​ Gathering, compression, water handling and treatment ​ ​ — ​ ​ — ​ ​ 492,244 ​ ​ (492,244) ​ ​ — ​ Marketing ​ ​ — ​ ​ 330,243 ​ ​ — ​ ​ — ​ ​ 330,243 ​ Amortization of deferred revenue, VPP ​ ​ 22,429 ​ ​ — ​ ​ — ​ ​ — ​ ​ 22,429 ​ Other income (loss) ​ ​ 21 ​ ​ — ​ ​ (35,336) ​ ​ 35,336 ​ ​ 21 ​ Total revenue ​ ​ 1,361,035 ​ ​ 330,243 ​ ​ 456,908 ​ ​ (456,908) ​ ​ 1,691,278 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 46,192 ​ ​ — ​ ​ — ​ ​ — ​ ​ 46,192 ​ Gathering and compression ​ ​ 444,361 ​ ​ — ​ ​ 78,869 ​ ​ (78,869) ​ ​ 444,361 ​ Processing ​ ​ 393,947 ​ ​ — ​ ​ — ​ ​ — ​ ​ 393,947 ​ Transportation ​ ​ 408,131 ​ ​ — ​ ​ — ​ ​ — ​ ​ 408,131 ​ Production and ad valorem taxes ​ ​ 78,391 ​ ​ — ​ ​ — ​ ​ — ​ ​ 78,391 ​ Marketing ​ ​ — ​ ​ 361,071 ​ ​ — ​ ​ — ​ ​ 361,071 ​ Exploration ​ ​ 5,857 ​ ​ — ​ ​ — ​ ​ — ​ ​ 5,857 ​ General and administrative (excluding equity-based compensation) ​ ​ 66,360 ​ ​ — ​ ​ 25,110 ​ ​ (25,110) ​ ​ 66,360 ​ Equity-based compensation ​ ​ 9,891 ​ ​ — ​ ​ 7,071 ​ ​ (7,071) ​ ​ 9,891 ​ Depletion, depreciation and amortization ​ ​ 381,356 ​ ​ — ​ ​ 53,469 ​ ​ (53,469) ​ ​ 381,356 ​ Impairment of oil and gas properties ​ ​ 43,365 ​ ​ — ​ ​ — ​ ​ — ​ ​ 43,365 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 1,379 ​ ​ (1,379) ​ ​ — ​ Accretion of asset retirement obligations ​ ​ 2,119 ​ ​ — ​ ​ 233 ​ ​ (233) ​ ​ 2,119 ​ Contract termination and other expenses ​ ​ 935 ​ ​ — ​ ​ 2,163 ​ ​ (2,163) ​ ​ 935 ​ Loss (gain) on sale of assets ​ ​ (2,288) ​ ​ — ​ ​ 3,628 ​ ​ (3,628) ​ ​ (2,288) ​ Total operating expenses ​ ​ 1,878,617 ​ ​ 361,071 ​ ​ 171,922 ​ ​ (171,922) ​ ​ 2,239,688 ​ Operating income (loss) ​ $ (517,582) ​ ​ (30,828) ​ ​ 284,986 ​ ​ (284,986) ​ ​ (548,410) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 36,171 ​ ​ — ​ ​ 42,259 ​ ​ (42,259) ​ ​ 36,171 ​ ​ ​ 46 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Six Months Ended June 30, 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 ​ $ 2,554,786 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,554,786 ​ Natural gas liquids sales ​ ​ 1,362,693 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,362,693 ​ Oil sales ​ ​ 152,479 ​ ​ — ​ ​ — ​ ​ — ​ ​ 152,479 ​ Commodity derivative fair value losses ​ ​ (1,277,042) ​ ​ — ​ ​ — ​ ​ — ​ ​ (1,277,042) ​ Gathering, compression, water handling and treatment ​ ​ — ​ ​ — ​ ​ 482,734 ​ ​ (482,734) ​ ​ — ​ Marketing ​ ​ — ​ ​ 175,188 ​ ​ — ​ ​ — ​ ​ 175,188 ​ Amortization of deferred revenue, VPP ​ ​ 18,647 ​ ​ — ​ ​ — ​ ​ — ​ ​ 18,647 ​ Other income (loss) ​ 1,774 ​ ​ — ​ ​ (35,336) ​ ​ 35,336 ​ ​ 1,774 ​ Total revenue ​ ​ 2,813,337 ​ ​ 175,188 ​ ​ 447,398 ​ ​ (447,398) ​ ​ 2,988,525 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 43,033 ​ ​ — ​ ​ — ​ ​ — ​ ​ 43,033 ​ Gathering and compression ​ ​ 425,112 ​ ​ — ​ ​ 85,311 ​ ​ (85,311) ​ ​ 425,112 ​ Processing ​ ​ 409,701 ​ ​ — ​ ​ — ​ ​ — ​ ​ 409,701 ​ Transportation ​ ​ 411,677 ​ ​ — ​ ​ — ​ ​ — ​ ​ 411,677 ​ Production and ad valorem taxes ​ ​ 134,650 ​ ​ — ​ ​ — ​ ​ — ​ ​ 134,650 ​ Marketing ​ ​ — ​ ​ 230,194 ​ ​ — ​ ​ — ​ ​ 230,194 ​ Exploration and mine expenses ​ ​ 2,292 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,292 ​ General and administrative (excluding equity-based compensation) ​ ​ 67,310 ​ ​ — ​ ​ 25,537 ​ ​ (25,537) ​ ​ 67,310 ​ Equity-based compensation ​ ​ 12,820 ​ ​ — ​ ​ 8,473 ​ ​ (8,473) ​ ​ 12,820 ​ Depletion, depreciation and amortization ​ ​ 341,783 ​ ​ — ​ ​ 63,975 ​ ​ (63,975) ​ ​ 341,783 ​ Impairment of oil and gas properties ​ ​ 45,825 ​ ​ — ​ ​ — ​ ​ — ​ ​ 45,825 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 3,702 ​ ​ (3,702) ​ ​ — ​ Accretion of asset retirement obligations ​ ​ 3,248 ​ ​ — ​ ​ 128 ​ ​ (128) ​ ​ 3,248 ​ Loss (gain) on sale of assets ​ ​ 1,857 ​ ​ — ​ ​ (150) ​ ​ 150 ​ ​ 1,857 ​ Contract termination and other expenses ​ ​ 2,104 ​ ​ — ​ ​ 2,872 ​ ​ (2,872) ​ ​ 2,104 ​ Total operating expenses ​ ​ 1,901,412 ​ ​ 230,194 ​ ​ 189,848 ​ ​ (189,848) ​ ​ 2,131,606 ​ Operating income (loss) ​ $ 911,925 ​ ​ (55,006) ​ ​ 257,550 ​ ​ (257,550) ​ ​ 856,919 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ 39,891 ​ ​ — ​ ​ 46,056 ​ ​ (46,056) ​ ​ 39,891 ​ ​ ​ 47 Table of Contents Exploration and Production Segment The following table sets forth selected operating data of the exploration and production segment for the six months ended June 30, 2021 compared to the six months ended June 30, 2022: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Amount of ​ ​ ​ ​ ​ ​ Six Months Ended June 30, ​ Increase ​ Percent ​ ​ ​ 2021 2022 (Decrease) Change ​ ​ Production data (1) (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (Bcf) ​ ​ 415 ​ ​ 402 ​ ​ (13) ​ (3) % ​ C2 Ethane (MBbl) ​ ​ 8,761 ​ ​ 8,030 ​ ​ (731) ​ (8) % ​ C3+ NGLs (MBbl) ​ ​ 20,366 ​ ​ 19,794 ​ ​ (572) ​ (3) % ​ Oil (MBbl) ​ ​ 1,900 ​ ​ 1,629 ​ ​ (271) ​ (14) % ​ Combined (Bcfe) ​ ​ 601 ​ ​ 579 ​ ​ (22) ​ (4) % ​ Daily combined production (MMcfe/d) ​ ​ 3,323 ​ ​ 3,197 ​ ​ (126) ​ (4) % ​ Average prices before effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) (4) ​ $ 3.24 ​ ​ 6.36 ​ ​ 3.12 ​ 96 % ​ C2 Ethane (per Bbl) ​ $ 9.08 ​ ​ 19.59 ​ ​ 10.51 ​ 116 % ​ C3+ NGLs (per Bbl) ​ $ 40.52 ​ ​ 60.90 ​ ​ 20.38 ​ 50 % ​ Oil (per Bbl) ​ $ 50.84 ​ ​ 93.59 ​ ​ 42.75 ​ 84 % ​ Weighted Average Combined (per Mcfe) ​ $ 3.90 ​ ​ 7.03 ​ ​ 3.13 ​ 80 % ​ Average realized prices after effects of derivative settlements (3) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas (per Mcf) ​ $ 3.23 ​ ​ 4.28 ​ ​ 1.05 ​ 33 % ​ C2 Ethane (per Bbl) ​ $ 8.74 ​ ​ 19.53 ​ ​ 10.79 ​ 123 % ​ C3+ NGLs (per Bbl) ​ $ 37.82 ​ ​ 60.48 ​ ​ 22.66 ​ 60 % ​ Oil (per Bbl) ​ $ 48.90 ​ ​ 92.86 ​ ​ 43.96 ​ 90 % ​ Weighted Average Combined (per Mcfe) ​ $ 3.80 ​ ​ 5.57 ​ ​ 1.77 ​ 47 % ​ Average costs (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 0.08 ​ ​ 0.07 ​ ​ (0.01) ​ (13) % ​ Gathering and compression ​ $ 0.74 ​ ​ 0.73 ​ ​ (0.01) ​ (1) % ​ Processing ​ $ 0.65 ​ ​ 0.71 ​ ​ 0.06 ​ 9 % ​ Transportation ​ $ 0.68 ​ ​ 0.71 ​ ​ 0.03 ​ 4 % ​ Production and ad valorem taxes ​ $ 0.13 ​ ​ 0.23 ​ ​ 0.10 ​ 77 % ​ Marketing expense, net ​ $ 0.05 ​ ​ 0.10 ​ ​ 0.05 ​ 100 % ​ Depletion, depreciation, amortization and accretion ​ $ 0.64 ​ ​ 0.60 ​ ​ (0.04) ​ (6) % ​ General and administrative (excluding equity-based compensation) ​ $ 0.11 ​ ​ 0.12 ​ ​ 0.01 ​ 9 % ​ * Not meaningful. (1) Production data excludes volumes related to the VPP. (2) Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and may not reflect their relative economic value. (3) Average prices reflect the before and after effects of our settled commodity derivatives. Our calculation of such after effects includes gains 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 six months ended June 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 for natural gas would have been $3.04 per Mcf for the six months ended June 30, 2021. ​ Natural gas sales . Revenues from sales of natural gas increased from $1.3 billion for the six months ended June 30, 2021 to $2.6 billion, which included litigation proceeds of $85 million, for the six months ended June 30, 2022, an increase of $1.3 billion, or 90%. See Note 14—Contingencies to the unaudited condensed consolidated financial statements for more information on the litigation proceeds. Excluding net litigation proceeds received during the six months ended June 30, 2021, higher commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, 2022 accounted for an approximate $1.3 billion increase in year-over-year natural 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 $44 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. 48 Table of Contents NGLs sales . Revenues from sales of NGLs increased from $905 million for the six months ended June 30, 2021 to $1.4 billion for the six months ended June 30, 2022, an increase of $458 million, or 51%. Higher commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, 2022 accounted for an approximate $488 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 $30 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 $97 million for the six months ended June 30, 2021 to $152 million for the six months ended June 30, 2022, an increase of $55 million, or 58%. Higher oil prices, excluding the effects of derivative settlements, accounted for an approximate $69 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 six months ended June 30, 2022 accounted for an approximate $14 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price). Commodity derivative fair value gains (losses). 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 we believe 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 six months ended June 30, 2021, our commodity hedges resulted in derivative fair value losses of $1.0 billion. For the six months ended June 30, 2022, our commodity hedges resulted in derivative fair value losses of $1.3 billion. Commodity derivative fair value losses included $65 million of cash payments on commodity derivative losses as well as $5 million for payments on derivative monetizations gains on settled derivatives for the six months ended June 30, 2021. For the six months ended June 30, 2022, commodity derivative fair value losses included $845 million of cash payments on commodity derivative losses. Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled or monetized prior to settlement. Derivative asset or liability positions at the end of any accounting period may reverse to the extent future commodity prices increase or decrease from their levels at the end of the accounting period, or as gains or losses are realized through settlement. 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 $22 million for the six months ended June 30, 2021 to $19 million for the six months ended June 30, 2022, a decrease of $3 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 $46 million for the six months ended June 30, 2021 to $43 million for the six months ended June 30, 2022, a decrease of $3 million, or 7%, primarily due to lower production volumes and water disposal costs. On a per-unit basis, lease operating expenses decreased from $0.08 per Mcfe for the six months ended June 30, 2021 to $0.07 per Mcfe for the six months ended June 30, 2022 primarily due to lower water disposal costs, partially offset by higher workover costs. Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense remained consistent at $1.2 billion for both the six months ended June 30, 2021 and 2022. Gathering and compression costs decreased from $0.74 per Mcfe for the six months ended June 30, 2021 to $0.73 per Mcfe for the six months ended June 30, 2022, primarily due to $24 million in incentive fee rebates earned from Antero Midstream during the six months ended June 30, 2022 that were not earned during the six months ended June 30, 2021. Processing costs increased from $0.65 per Mcfe for the six months ended June 30, 2021 to $0.71 per Mcfe for the six months ended June 30, 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 $0.68 per Mcfe for the six months ended June 30, 2021 to $0.71 per Mcfe for the six months ended June 30, 2022 primarily due to higher fuel costs between periods. ​ Production and ad valorem tax expense. Production and ad valorem taxes increased from $78 million for the six months ended June 30, 2021 to $135 million for the six months ended June 30, 2022, an increase of $57 million, or 72%, primarily due to higher commodity prices between periods partially offset by $5 million for the litigation judgment in 2021. Production and ad valorem taxes as a percentage of natural gas revenues remained relatively consistent at 6% and 5% for the six months ended June 30, 2021 and 2022, respectively. 49 Table of Contents General and administrative expense . General and administrative expense (excluding equity-based compensation expense) remained relatively consistent at $66 million and $67 million for the six months ended June 30, 2021 and 2022, respectively. The slight increase in expense between periods is primarily due to higher professional service fees and office operating costs, partially offset by lower salary and wage expense. On a per-unit basis, general and administrative expense excluding equity-based compensation increased from $0.11 per Mcfe during the six months ended June 30, 2021 to $0.12 per Mcfe during the six months ended June 30, 2022 as a result of lower production volumes and higher overall costs between periods. Equity-based compensation expense . Noncash equity-based compensation expense increased from $10 million for the six months ended June 30, 2021 to $13 million for the six months ended June 30, 2022, an increase of $3 million, or 30%, primarily due to an increase in the annual equity awards granted during the second quarter of 2022 as compared to prior years, partially offset by equity award forfeitures. 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. Depletion, depreciation, and amortization expense . DD&A expense decreased from $381 million for the six months ended June 30, 2021 to $342 million for the six months ended June 30, 2022, a decrease of $39 million, or 10%, 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 per Mcfe decreased from $0.64 per Mcfe for the six months ended June 30, 2021 to $0.60 per Mcfe for the six months ended June 30, 2022, primarily as a result of increased proved reserve volumes between periods. Impairment of oil and gas properties . Impairment of oil and gas properties increased from $43 million for the six months ended June 30, 2021 to $46 million for the six months ended June 30, 2022, an increase of $3 million, or 6%, primarily related to higher impairments of expiring leases between periods. During both periods, we recognized impairments primarily related to expiring leases as well as design and initial costs related to pads we no longer plan to place into service. Marketing Segment Where feasible, we purchase and sell third-party natural gas and NGLs and market our excess firm transportation capacity, or engage third parties to conduct these activities on our behalf, in order to optimize the revenues from these transportation agreements. We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production in order to secure guaranteed capacity to favorable markets. Net marketing expense increased from $31 million, or $0.05 per Mcfe, for the six months ended June 30, 2021 to $55 million, or $0.10 per Mcfe, for the six months ended June 30, 2022, primarily due to lower volumes partially offset by higher gas marketing margins between periods. Marketing revenue. Marketing revenue decreased from $330 million for the six months ended June 30, 2021 to $175 million for the six months ended June 30, 2022, a decrease of $155 million, or 47%, primarily due to lower marketing volumes between periods, partially offset by increased commodity prices between periods. Lower natural gas marketing volumes accounted for a $865 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher natural gas prices accounted for an approximate $685 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 $7 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher oil prices accounted for an approximate $13 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 $43 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher ethane prices accounted for an approximate $54 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). Marketing expense. Marketing expense decreased from $361 million for the six months ended June 30, 2021 to $230 million for the six months ended June 30, 2022, a decrease of $131 million, or 36%. 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 $121 million, which was partially offset by increased oil and NGL purchases of approximately $18 million and $9 million, respectively, between periods. The total costs decreased primarily due to decreased marketing volumes between periods, partially offset by increased commodity prices. Firm transportation costs were $110 million for the six months ended June 30, 2021 and $73 million for the six months ended June 30, 2022, a decrease of $37 million due to the reduction in firm transportation commitments and third-party marketed volumes between periods. 50 Table of Contents Equity Method Investment in Antero Midstream Antero Midstream revenue. Revenue from the Antero Midstream segment decreased from $457 million for the six months ended June 30, 2021 to $447 million for the six months ended June 30, 2022, a decrease of $10 million, primarily due to a decrease in low pressure revenues due to higher fee rebates earned by us and lower fresh water delivery 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 Antero Midstream segment increased from $172 million for the six months ended June 30, 2021 to $190 million for the six months ended June 30, 2022, an increase of $18 million, primarily due to an increase in depreciation expense during the six months ended June 30, 2022. This increase is primarily a result of a phased early retirement of an underutilized compressor station, which allows Antero Midstream to relocate and reuse the compressor units and equipment to (i) expand an existing compressor station and (ii) contribute to a new compressor station. There are certain costs associated with the underutilized compressor station that cannot be relocated or reused that will be depreciated over the remaining period of use. Additionally, operating expenses were higher between periods due to increased direct operating costs as a result of higher gathering throughput volumes, two new compressor stations and resuming fresh water deliveries to us in the Utica Shale. Items Not Allocated to Segments Interest expense. Interest expense decreased from $93 million for the six months ended June 30, 2021 to $72 million for the six months ended June 30, 2022, a decrease of $21 million or 22%, primarily due to the reduction in debt as a result of the repurchase of certain of our unsecured senior notes between periods. Loss on early extinguishment of debt. During the six months ended June 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 six months ended June 30, 2021, we redeemed the remaining balance of $661 million of our 5.125% senior notes due 2022 (“2022 Notes”) at par, plus accrued and unpaid interest and the remaining balance of $574 million of our 2023 Notes at par, plus accrued and unpaid interest, and recognized a $5 million loss on early extinguishment of debt. D uring the six months ended June 30, 2022, we (i) 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 and (ii) repurchased $50 million of our 2029 Notes and $13 million of our 2026 Notes, which resulted in a loss on early debt extinguishment of $15 million. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. ​ Loss on convertible note equitization. During the six months ended June 30, 2021, we recognized a loss of $51 million for the equitization of our 2026 Convertible Notes, which represents the consideration paid in excess of the original terms of the 2026 Convertible Notes. There were no equitization transactions during the six months ended June 30, 2022. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information. Income tax benefit (expense) . For the six months ended June 30, 2021, we had an income tax benefit of $179 million, with an effective tax rate of 25%, due to a loss before income taxes of $724 million. For the six months ended June 30, 2022, we had income tax expense of $172 million, with an effective tax rate of 21%, due to income before income taxes of $810 million. The decrease in the effective tax rate between periods was primarily due to an income tax benefit for the equity-based awards that vested during the six months ended June 30, 2022, partially offset by a higher amount of taxable income being apportioned to West Virginia. 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 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 51 Table of Contents 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 June 30, 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): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Six Months Ended June 30, ​ ​ ​ 2021 2022 Net cash provided by operating activities ​ $ 872,272 ​ ​ 1,488,385 ​ Net cash used in investing activities ​ ​ (302,878) ​ ​ (474,834) ​ Net cash used in financing activities ​ ​ (564,853) ​ ​ (1,013,551) ​ Net increase in cash and cash equivalents ​ $ 4,541 ​ ​ — ​ ​ Operating Activities. Net cash provided by operating activities was $872 million and $1.5 billion for the six months ended June 30, 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 decreased production and increased (i) cash utilized for working capital, (ii) net marketing expense and (iii) 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 $303 million for the six months ended June 30, 2021 to $475 million for the six months ended June 30, 2022, primarily due to an increase in capital expenditures of $171 million between periods. Financing Activities . Net cash flows used in financing activities increased from $565 million for the six months ended June 30, 2021 to $1.0 billion for the six months ended June 30, 2022. During the six months ended June 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 5.375% senior notes due March 1, 2030 (net of $22 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) redeem $574 million of our 2023 Notes, which were fully retired and (iii) partially repay borrowings on the Credit Facility. Also, during the six months ended June 30, 2021, we completed two equitization transactions and used the proceeds and approximately $89 million of borrowings under the Credit Facility to repurchase $206 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions . Additionally, during the six months ended June 30, 2021, we received a $51 million payment from Martica and distributed $46 million to the noncontrolling interest in Martica . During the six months ended June 30, 2022, we (i) redeemed $585 million aggregate principal amount of our 2025 Notes and repurchased $13 million of our 2026 Notes and $50 million of our 2029 Notes (ii) repurchased approximately 9 million shares of our common stock at a total cost of approximately $293 million, (iii) distributed $67 million to the noncontrolling interest in Martica and (iv) paid $65 million in employee withholding taxes for vested equity-based awards. Additionally, we borrowed $71 million, net, on our Credit Facility during the six months ended June 30, 2022. 2022 Capital Budget and Capital Spending On July 27, 2022, we announced a revised net capital budget for 2022 of $825 million to $860 million. Our revised budget includes: a range of $725 million to $750 million for drilling and completion and a range of $100 million to $110 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 periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices. 52 Table of Contents For the three months ended June 30, 2022, our total consolidated capital expenditures were approximately $268 million, including drilling and completion costs of $217 million, leasehold acquisitions of $49 million, and other capital expenditures of $2 million. For the six months ended June 30, 2022, our total consolidated capital expenditures were approximately $474 million, including drilling and completion costs of $392 million, leasehold acquisitions of $73 million, and other capital expenditures of $9 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 June 30, 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 and six months ended June 30, 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 June 30, 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. 53 Table of Contents