# ANTERO RESOURCES Corp (AR) FY 2023 MD&A Verbatim Item 7 Management's Discussion and Analysis from ANTERO RESOURCES Corp's 10-K for fiscal year 2023. SEC filing source: https://www.sec.gov/Archives/edgar/data/1433270/000155837024001162/ar-20231231x10k.htm Accession: 0001558370-24-001162 Filing date: 2024-02-14 Report date: 2023-12-31 Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Confidence: high Company profile: /company/AR/ All MD&A years: /company/AR/mda/ Previous year: /company/AR/mda/fy2022/ (FY 2022) Next year: /company/AR/mda/fy2024/ (FY 2024) ITEM 7. 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 consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in natural gas, NGLs and oil prices, the timing of planned capital expenditures, our ability to fund our development programs, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, impacts of world health events and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements.” Also, see the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. 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 December 31, 2023, we held approximately 515,000 net acres in the Appalachian Basin. In addition, we estimate that approximately 172,000 net acres of our leasehold may be prospective for the slightly shallower Upper Devonian Shale. As of December 31, 2023, our estimated proved reserves were 18.1 Tcfe, consisting of 10.6 Tcf of natural gas, 690 MMBbl of assumed recovered ethane, 532 MMBbl of C3+ NGLs and 29 MMBbl of oil. This represents a 2% increase in estimated proved reserves from December 31, 2022. These reserve estimates have been prepared by our internal reserve engineers and management and audited by our independent reserve engineers. As of December 31, 2023, we had 1,588 potential horizontal well locations on our existing leasehold acreage that were classified as proved, probable and possible. We operate in the following reportable segments: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing of excess firm transportation capacity; and (iii) midstream services through our equity method investment in Antero Midstream Corporation (“Antero Midstream”). All of our operations are conducted in the United States. Financing Highlights Share Repurchase Program During 2022, our Board of Directors authorized a share repurchase program that allows us to repurchase up to $2.0 billion of outstanding common stock. During the years ended December 31, 2022 and 2023, we repurchased 25 million and 3 million shares of our common stock, respectively, through our share repurchase program at a total cost of $874 million and $75 million, respectively. As of December 31, 2023, we have $1.1 billion remaining under our share repurchase program. 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. 2026 Convertible Notes Conversions During the year ended December 31, 2023, $9 million aggregate principal amount of the 2026 Convertible Notes were converted pursuant to their terms, and an additional $21 million aggregate principal amount of the 2026 Convertible Notes were induced into conversion by us. We elected to settle these conversions and inducements by issuing 7 million shares of common stock 51 Table of Contents to the noteholders together with a cash inducement premium of $0.4 million. 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, 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 through 2024, we agreed to the estimated IRR or our capital budget for each annual tranche, and QL agreed to participate in all four annual tranches. We develop and manage the drilling program associated with each tranche, including the selection of wells. Additionally, for each annual tranche, we will enter into assignments, bills of sale and conveyances pursuant to which QL will be conveyed a proportionate working interest percentage in each well spud in that year, which conveyances will not be subject to any reversion. Under the terms of the arrangement, QL funded development capital of 20%, 15% and 15% for wells spud in 2021, 2022 and 2023, respectively, and will fund 20% of development capital for wells spud in 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 October 31 and no later than December 1 following the end of each tranche year. We received a carry of $29 million for each of the 2021 and 2022 tranches during the years ended December 31, 2022 and 2023. Capital costs in excess of, and cost savings below, a specified percentage of budgeted amounts for each annual tranche will be for our account. Subject to the preceding sentence, for any wells included in a tranche, QL is obligated and responsible for its working interest share of costs and liabilities, and is entitled to its working interest share of revenues, associated with such wells for the life of such wells. See Note 3—Transactions to the consolidated financial statements for more information. Market Conditions and Business Trends Commodity Markets Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Natural gas, NGLs and oil benchmark prices decreased significantly during 2023 as compared to 2022. As a result, we experienced a decrease in price realizations during the year ended December 31, 2023. We monitor the economic factors that impact natural gas, NGLs and oil prices, including domestic and foreign supply and demand indicators, domestic and foreign commodity inventories, the actions of Organization of Petroleum Exporting Countries and other large producing nations and the current conflicts in Ukraine and in the Middle East, among others. In the current economic environment, we expect that commodity prices for some or all of the commodities we produce could remain volatile. This volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows. The following table details the average benchmark natural gas and oil prices: [[GREPCENT_TABLE]] [["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Year Ended December 31,","\u200b"],["\u200b","","2022","","2023","\u200b"],["Henry Hub (1) ($/Mcf)","\u200b","$","6.64","\u200b","\u200b","2.74","\u200b"],["West Texas Intermediate (2) ($/Bbl)","\u200b","\u200b","94.23","\u200b","\u200b","77.62","\u200b"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["(1)","New York Mercantile Exchange first of month average natural gas price."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["(2)","Energy Information Administration calendar month average settled futures price."]] [[/GREPCENT_TABLE]] Hedge Position Antero Resources (Excluding Martica) We are exposed to certain commodity price risks relating to our ongoing business operations, and we use derivative instruments when circumstances warrant to manage such risks. In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased. For the years ended December 31, 2022 and 2023, 33% and 1%, respectively, of our production was hedged through fixed price commodity swaps, and as of December 31, 2023, we had no fixed price commodity swap positions. The tables and narrative below exclude derivative instruments attributable to Martica, our consolidated VIE, since all gains or losses from such contracts are fully attributable to the noncontrolling interests in Martica. 52 Table of Contents As of December 31, 2023, our natural gas basis swap positions settle on the pricing index to basis differential of the Columbia Gas Transmission pipeline (“TCO”) to the NYMEX Henry Hub natural gas price were as follows: [[GREPCENT_TABLE]] [["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","Weighted Average","\u200b"],["Commodity / Settlement Period","\u200b","Index to Basis Differential","","Contracted Volume","","Hedged Differential","\u200b"],["Natural Gas","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["January-December 2024","\u200b","NYMEX to TCO","\u200b","18","Bcf","\u200b","\u200b","0.530","/MMBtu","\u200b"]] [[/GREPCENT_TABLE]] ​ We have a call option and an embedded put option tied to NYMEX pricing for the production volumes associated with the Company’s retained interest in the VPP properties. As of December 31, 2023, our call option and embedded put option arrangements were as follows: [[GREPCENT_TABLE]] [["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","Embedded","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","Call Option","\u200b","Put Option","\u200b"],["Commodity / Settlement Period","","Index","","Contracted Volume","","Strike Price","","Strike Price"],["Natural Gas","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["January-December 2024","\u200b","Henry Hub","\u200b","19","Bcf","\u200b","\u200b","2.477","/MMBtu","\u200b","\u200b","2.527","/MMBtu","\u200b"],["January-December 2025","\u200b","Henry Hub","\u200b","16","Bcf","\u200b","\u200b","2.564","/MMBtu","\u200b","\u200b","2.614","/MMBtu","\u200b"],["January-December 2026","\u200b","Henry Hub","\u200b","12","Bcf","\u200b","\u200b","2.629","/MMBtu","\u200b","\u200b","2.679","/MMBtu","\u200b"],["\u200b","\u200b","\u200b","\u200b","47","Bcf","\u200b","\u200b","2.544","/MMBtu","\u200b","\u200b","2.594","/MMBtu","\u200b"]] [[/GREPCENT_TABLE]] ​ As of December 31, 2023, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of $32 million. See Note 11—Derivative Instruments to the consolidated financial statements for more information. Martica Our consolidated VIE, Martica, also maintains a portfolio of fixed swap natural gas, NGLs and oil derivatives for the benefit of the noncontrolling interests in Martica. As such, all gains and losses attributable to Martica’s derivative portfolio are fully attributable to the noncontrolling interests in Martica. As of December 31, 2023, Martica’s fixed price natural gas, NGLs and oil swap positions were as follows: [[GREPCENT_TABLE]] [["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","Weighted","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","Average","\u200b"],["Commodity / Settlement Period","","Index","","Contracted Volume","","Price","\u200b"],["Natural Gas","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["January-December 2024","\u200b","Henry Hub","\u200b","9","Bcf","\u200b","\u200b","2.33","/MMBtu","\u200b"],["January-March 2025","\u200b","Henry Hub","\u200b","1","Bcf","\u200b","\u200b","2.53","/MMBtu","\u200b"],["\u200b","\u200b","\u200b","\u200b","10","Bcf","\u200b","\u200b","2.36","/MMBtu","\u200b"],["Oil","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["January-December 2024","\u200b","West Texas Intermediate","\u200b","16","MBbl","\u200b","\u200b","44.02","/Bbl","\u200b"],["January-March 2025","\u200b","West Texas Intermediate","\u200b","3","MBbl","\u200b","\u200b","45.06","/Bbl","\u200b"],["\u200b","\u200b","\u200b","\u200b","19","MBbl","\u200b","\u200b","44.21","/Bbl","\u200b"]] [[/GREPCENT_TABLE]] ​ As of December 31, 2023, the estimated fair value of Martica’s commodity derivative contracts was a net liability of $5 million. See Note 11—Derivative Instruments to the consolidated financial statements for more information. Economic Indicators The economy experienced elevated inflation levels as a result of global supply and demand imbalances, where global demand outpaced supplies beginning in 2021 and continuing through 2023. For example, CPI for all urban consumers increased 8% from December 2021 to December 2022 and an additional 4% from December 2022 to December 2023 as compared to the Federal Reserve’s stated goal of 2%. In order to manage the inflation risk present in the United States’ economy, the Federal Reserve utilized monetary policy in the form of interest rate increases beginning in March 2022 in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis. Between March 2022 and December 2023, the Federal Reserve increased the federal funds interest rate by 5.25%. While inflationary pressures in the United States’ economy have begun to subside, we continue to be impacted by the increased federal funds interest rate. See “—Results of Operations” for more information. 53 Table of Contents The economy also continues to be impacted by the effects of global events. These events have often caused global supply chain disruptions with additional pressure due to trade sanctions on Russia and other global trade restrictions, among others. However, our supply chain has not experienced any significant interruptions as a result of such events. Inflationary pressures, particularly as they relate to certain of our long-term contracts with CPI-based adjustments, and supply chain disruptions have and could continue to result in increases to our operating and capital costs that are not fixed. These economic variables are beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows. Sources of Our Revenues [[GREPCENT_TABLE]] [["","\u25cf","Natural gas, NGLs and oil sale revenues. Our revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from our natural gas during processing. Our production is entirely from within the continental United States; however, some of our production revenues are attributable to customers who export our products. During 2022 and 2023, our production revenues were comprised of 67% and 51%, respectively, from the sale of natural gas and 33% and 49%, respectively, from the sale of NGLs and oil. Natural gas, NGLs and oil prices are inherently volatile and are influenced by many factors outside of our control. All of our production is derived from natural gas wells, some of which also produce NGLs which are extracted through processing, and oil."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","Commodity derivatives. We utilize derivative instruments to hedge future sales prices for a portion of our production when circumstances warrant. We currently utilize call and embedded put options, as well as basis swap contracts that hedge the difference between the NYMEX index price and a local index price. We may also enter into commodity fixed price swaps, collars or other similar instruments related to the price risk associated with our production. Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased. As of December 31, 2023, we had no fixed price commodity swap positions. See Note 11\u2014Derivative Instruments to the consolidated financial statements for more information. At the end of each accounting period, we estimate the fair value of these derivative instruments, because we have not elected hedge accounting, we recognize changes in the fair value of these derivative instruments in earnings. We expect continued volatility in the prices we receive for our production and the fair value of our derivative instruments."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","Marketing revenues. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market excess firm transportation capacity to third parties."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","Gathering, compression and water handling revenues. Gathering, compression and water handling revenues are derived from our ownership interest in Antero Midstream."]] [[/GREPCENT_TABLE]] Principal Components of Our Cost Structure [[GREPCENT_TABLE]] [["","\u25cf","Lease operating expenses. These are the operating costs incurred to maintain our production. Such costs include produced water hauling, water handling, water disposal, and labor-related costs to monitor producing wells, maintenance, repairs and workover expenses. Cost levels for these expenses can vary based on the volume of water produced, supply and demand for oilfield services, activity levels, and other factors."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","Gathering, compression, processing and transportation. These costs include the fees paid to Antero Midstream and other third parties who operate low and high pressure gathering and compression systems that transport our gas. They also include costs to process and extract NGLs from our liquids-rich gas and to transport our natural gas, NGLs and oil to market. We often enter into fixed price long-term contracts that secure transportation and processing capacity, which may include minimum volume commitments, the cost for which is included in these expenses to the extent that they are not associated with excess capacity. Costs associated with excess capacity are included in marketing expenses."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","Water handling. Water handling expenses relate to the direct operating costs attributable to fresh water and other fluid handling services."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","Production and ad valorem taxes. Production and ad valorem taxes consist of severance and ad valorem taxes. Severance taxes are paid on produced natural gas and oil based on a percentage of sales prices, which exclude the effects of our derivative instruments, or at fixed per-unit rates established by state authorities. Ad valorem taxes are paid based on the value of our reserves as well as the value of property and equipment."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","Marketing expenses. We purchase and sell third-party natural gas and NGLs and market our excess capacity under long-term contracts. Marketing costs include the cost of purchased third-party natural gas and NGLs. We also classify firm"]] [[/GREPCENT_TABLE]] 54 Table of Contents [[GREPCENT_TABLE]] [["","","transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize this excess capacity as marketing expenses, because we market this excess capacity to third parties. We enter into long-term firm transportation agreements for a significant portion of our current and expected future production in order to secure capacity on major pipelines."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","Exploration and mine expenses. These are primarily costs related to unsuccessful leasing efforts, as well as geological and geophysical costs, including seismic costs, costs of unsuccessful exploratory dry holes and costs of other exploratory activities, including costs associated with our sand mine."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","Impairment of property and equipment. These costs include impairment and costs associated with leases expirations, impairment of design and initial costs related to pads that are no longer planned to be placed into service and impairment of proved properties due to lower future commodity prices. We charge impairment expense for expired or soon-to-be expired leases when we determine they are impaired based on factors such as remaining lease terms, reservoir performance, commodity price outlooks and future plans to develop the acreage. We record impairment charges for proved properties on a geological reservoir basis when events or changes in circumstances indicate that a property\u2019s carrying amount may not be recoverable. We also record impairment charges for other property and equipment when events or changes in circumstances indicate that the carrying amount of such property and/or equipment may not be recoverable."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","Depletion, depreciation and amortization. DD&A includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas, NGLs and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts and allocate these costs using the units of production method. Depreciation is computed over an asset\u2019s estimated useful life using the straight-line basis."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","General and administrative expense. These costs include overhead, including payroll and benefits for our staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other professional fees, insurance, legal expenses and other administrative expenses. General and administrative expense also includes noncash equity-based compensation expense. See Note 9\u2014Equity-Based Compensation to the consolidated financial statements for more information."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","Interest expense. We finance a portion of our capital expenditures, working capital requirements and acquisitions with borrowings under our Credit Facility, which has a variable rate of interest based on SOFR (defined below in \u201c\u2014Capital Resources and Liquidity\u2014Debt Agreements\u2014Credit Facility\u201d) or the Alternate Base Rate (each term as defined in the Credit Facility). As of December 31, 2023, we had an outstanding balance on the Credit Facility of $417 million with a weighted average interest rate of 7.71%. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions. As of December 31, 2023, we had fixed interest rates ranging from 5.375% to 8.375% on our Senior Notes with an aggregate principal balance of $1.1 billion and 4.25% on our 2026 Convertible Notes with an aggregate principal balance of $26 million. See Note 7\u2014Long-Term Debt to the consolidated financial statements for more information."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","Income tax expense. We are subject to state and U.S. federal income taxes, but we are currently not in a cash tax paying position with respect to U.S. federal income taxes. The difference between our financial statement income tax expense and our current U.S. federal income tax liability is primarily due to the differences in the tax and financial statement treatment of oil and gas properties, the effects of noncontrolling interests and the deferral of unsettled commodity derivative gains and losses for tax purposes until they are settled. We have recorded deferred income tax expense to the extent our deferred income tax liabilities exceed our deferred income tax assets. See Note 13\u2014Income Taxes to the consolidated financial statements for more information."]] [[/GREPCENT_TABLE]] ​ 55 Table of Contents Results of Operations We have three operating segments: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing and utilization of excess firm transportation capacity; and (iii) midstream services through our equity method investment in Antero Midstream. Revenues from Antero Midstream’s operations were primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream. All intersegment transactions were eliminated upon consolidation, including revenues from water handling services provided by Antero Midstream, which we capitalized as proved property development costs. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity. See Note 17—Reportable Segments to the consolidated financial statements for more information. Year Ended December 31, 2022 Compared to Year Ended December 31, 2023 The operating results of our reportable segments were as follows (in thousands): [[GREPCENT_TABLE]] [["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Year Ended December 31, 2022","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","Equity Method","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Exploration","\u200b","\u200b","\u200b","Investment in","\u200b","Elimination of","\u200b","\u200b","\u200b"],["\u200b","\u200b","and","\u200b","\u200b","\u200b","Antero","\u200b","Unconsolidated","\u200b","Consolidated","\u200b"],["\u200b","","Production","","Marketing","","Midstream","","Affiliate","","Total"],["Revenue and other:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Natural gas sales","\u200b","$","5,520,419","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","5,520,419","\u200b"],["Natural gas liquids sales","\u200b","\u200b","2,498,657","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","2,498,657","\u200b"],["Oil sales","\u200b","\u200b","275,673","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","275,673","\u200b"],["Commodity derivative fair value losses","\u200b","\u200b","(1,615,836)","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","(1,615,836)","\u200b"],["Gathering, compression and water handling","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","919,985","\u200b","\u200b","(919,985)","\u200b","\u200b","\u2014","\u200b"],["Marketing","\u200b","\u200b","\u2014","\u200b","\u200b","416,758","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","416,758","\u200b"],["Amortization of deferred revenue, VPP","\u200b","\u200b","37,603","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","37,603","\u200b"],["Other revenue and income","\u200b","\u200b","5,162","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","5,162","\u200b"],["Total revenue","\u200b","\u200b","6,721,678","\u200b","\u200b","416,758","\u200b","\u200b","919,985","\u200b","\u200b","(919,985)","\u200b","\u200b","7,138,436","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Operating expenses:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Lease operating","\u200b","\u200b","99,595","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","99,595","\u200b"],["Gathering and compression","\u200b","\u200b","892,533","\u200b","\u200b","\u2014","\u200b","\u200b","75,889","\u200b","\u200b","(75,889)","\u200b","\u200b","892,533","\u200b"],["Processing","\u200b","\u200b","869,744","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","869,744","\u200b"],["Transportation","\u200b","\u200b","843,103","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","843,103","\u200b"],["Water handling","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","104,365","\u200b","\u200b","(104,365)","\u200b","\u200b","\u2014","\u200b"],["Production and ad valorem taxes","\u200b","\u200b","287,406","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","287,406","\u200b"],["Marketing","\u200b","\u200b","\u2014","\u200b","\u200b","531,304","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","531,304","\u200b"],["Exploration and mine expenses","\u200b","\u200b","7,409","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","7,409","\u200b"],["General and administrative (excluding equity-based compensation)","\u200b","\u200b","137,466","\u200b","\u200b","\u2014","\u200b","\u200b","42,471","\u200b","\u200b","(42,471)","\u200b","\u200b","137,466","\u200b"],["Equity-based compensation","\u200b","\u200b","35,443","\u200b","\u200b","\u2014","\u200b","\u200b","19,654","\u200b","\u200b","(19,654)","\u200b","\u200b","35,443","\u200b"],["Depletion, depreciation and amortization","\u200b","\u200b","680,600","\u200b","\u200b","\u2014","\u200b","\u200b","131,762","\u200b","\u200b","(131,762)","\u200b","\u200b","680,600","\u200b"],["Impairment of property and equipment","\u200b","\u200b","149,731","\u200b","\u200b","\u2014","\u200b","\u200b","3,702","\u200b","\u200b","(3,702)","\u200b","\u200b","149,731","\u200b"],["Accretion of asset retirement obligations","\u200b","\u200b","4,627","\u200b","\u200b","\u2014","\u200b","\u200b","222","\u200b","\u200b","(222)","\u200b","\u200b","4,627","\u200b"],["Contract termination, loss contingency and other operating expenses","\u200b","\u200b","25,099","\u200b","\u200b","\u2014","\u200b","\u200b","4,705","\u200b","\u200b","(4,705)","\u200b","\u200b","25,099","\u200b"],["Loss (gain) on sale of assets","\u200b","\u200b","471","\u200b","\u200b","\u2014","\u200b","\u200b","(2,251)","\u200b","\u200b","2,251","\u200b","\u200b","471","\u200b"],["Total operating expenses","\u200b","\u200b","4,033,227","\u200b","\u200b","531,304","\u200b","\u200b","380,519","\u200b","\u200b","(380,519)","\u200b","\u200b","4,564,531","\u200b"],["Operating income (loss)","\u200b","$","2,688,451","\u200b","\u200b","(114,546)","\u200b","\u200b","539,466","\u200b","\u200b","(539,466)","\u200b","\u200b","2,573,905","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Equity in earnings of unconsolidated affiliates","\u200b","$","72,327","\u200b","\u200b","\u2014","\u200b","\u200b","94,218","\u200b","\u200b","(94,218)","\u200b","\u200b","72,327","\u200b"]] [[/GREPCENT_TABLE]] ​ ​ 56 Table of Contents [[GREPCENT_TABLE]] [["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Year Ended December 31, 2023","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","Equity Method","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Exploration","\u200b","\u200b","\u200b","Investment in","\u200b","Elimination of","\u200b","\u200b","\u200b"],["\u200b","\u200b","and","\u200b","\u200b","\u200b","Antero","\u200b","Unconsolidated","\u200b","Consolidated","\u200b"],["\u200b","","Production","","Marketing","","Midstream","","Affiliate","","Total"],["Revenue and other:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Natural gas sales","\u200b","$","2,192,349","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","2,192,349","\u200b"],["Natural gas liquids sales","\u200b","\u200b","1,836,950","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","1,836,950","\u200b"],["Oil sales","\u200b","\u200b","247,146","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","247,146","\u200b"],["Commodity derivative fair value gains","\u200b","\u200b","166,324","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","166,324","\u200b"],["Gathering, compression and water handling","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","1,041,771","\u200b","\u200b","(1,041,771)","\u200b","\u200b","\u2014","\u200b"],["Marketing","\u200b","\u200b","\u2014","\u200b","\u200b","206,122","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","206,122","\u200b"],["Amortization of deferred revenue, VPP","\u200b","\u200b","30,552","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","30,552","\u200b"],["Other revenue and income","\u200b","\u200b","2,529","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","2,529","\u200b"],["Total revenue","\u200b","\u200b","4,475,850","\u200b","\u200b","206,122","\u200b","\u200b","1,041,771","\u200b","\u200b","(1,041,771)","\u200b","\u200b","4,681,972","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Operating expenses:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Lease operating","\u200b","\u200b","118,441","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","118,441","\u200b"],["Gathering and compression","\u200b","\u200b","858,462","\u200b","\u200b","\u2014","\u200b","\u200b","95,507","\u200b","\u200b","(95,507)","\u200b","\u200b","858,462","\u200b"],["Processing","\u200b","\u200b","1,014,181","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","1,014,181","\u200b"],["Transportation","\u200b","\u200b","769,715","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","769,715","\u200b"],["Water handling","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","117,658","\u200b","\u200b","(117,658)","\u200b","\u200b","\u2014","\u200b"],["Production and ad valorem taxes","\u200b","\u200b","158,855","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","158,855","\u200b"],["Marketing","\u200b","\u200b","\u2014","\u200b","\u200b","284,965","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","284,965","\u200b"],["Exploration and mine expenses","\u200b","\u200b","2,700","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","2,700","\u200b"],["General and administrative (excluding equity-based compensation)","\u200b","\u200b","164,997","\u200b","\u200b","\u2014","\u200b","\u200b","39,462","\u200b","\u200b","(39,462)","\u200b","\u200b","164,997","\u200b"],["Equity-based compensation","\u200b","\u200b","59,519","\u200b","\u200b","\u2014","\u200b","\u200b","31,606","\u200b","\u200b","(31,606)","\u200b","\u200b","59,519","\u200b"],["Depletion, depreciation and amortization","\u200b","\u200b","689,966","\u200b","\u200b","\u2014","\u200b","\u200b","136,059","\u200b","\u200b","(136,059)","\u200b","\u200b","689,966","\u200b"],["Impairment of property and equipment","\u200b","\u200b","51,302","\u200b","\u200b","\u2014","\u200b","\u200b","146","\u200b","\u200b","(146)","\u200b","\u200b","51,302","\u200b"],["Accretion of asset retirement obligations","\u200b","\u200b","3,244","\u200b","\u200b","\u2014","\u200b","\u200b","177","\u200b","\u200b","(177)","\u200b","\u200b","3,244","\u200b"],["Loss (gain) on sale of assets","\u200b","\u200b","(447)","\u200b","\u200b","\u2014","\u200b","\u200b","6,030","\u200b","\u200b","(6,030)","\u200b","\u200b","(447)","\u200b"],["Contract termination, loss contingency and other operating expenses","\u200b","\u200b","29,179","\u200b","\u200b","23,763","\u200b","\u200b","3,264","\u200b","\u200b","(3,264)","\u200b","\u200b","52,942","\u200b"],["Total operating expenses","\u200b","\u200b","3,920,114","\u200b","\u200b","308,728","\u200b","\u200b","429,909","\u200b","\u200b","(429,909)","\u200b","\u200b","4,228,842","\u200b"],["Operating income (loss)","\u200b","$","555,736","\u200b","\u200b","(102,606)","\u200b","\u200b","611,862","\u200b","\u200b","(611,862)","\u200b","\u200b","453,130","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Equity in earnings of unconsolidated affiliates","\u200b","$","82,952","\u200b","\u200b","\u2014","\u200b","\u200b","105,456","\u200b","\u200b","(105,456)","\u200b","\u200b","82,952","\u200b"]] [[/GREPCENT_TABLE]] ​ 57 Table of Contents Exploration and Production Segment The following table sets forth selected operating data of the exploration and production segment: ​ [[GREPCENT_TABLE]] [["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Year Ended","\u200b","Amount of","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","December 31,","\u200b","Increase","\u200b","Percent","\u200b","\u200b"],["\u200b","","2022","","2023","","(Decrease)","","Change","\u200b","\u200b"],["Production data (1) (2):","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Natural gas (Bcf)","\u200b","\u200b","798","\u200b","\u200b","815","\u200b","\u200b","17","\u200b","2","%","\u200b"],["C2 Ethane (MBbl)","\u200b","\u200b","18,818","\u200b","\u200b","24,657","\u200b","\u200b","5,839","\u200b","31","%","\u200b"],["C3+ NGLs (MBbl)","\u200b","\u200b","39,914","\u200b","\u200b","41,927","\u200b","\u200b","2,013","\u200b","5","%","\u200b"],["Oil (MBbl)","\u200b","\u200b","3,223","\u200b","\u200b","3,874","\u200b","\u200b","651","\u200b","20","%","\u200b"],["Combined (Bcfe)","\u200b","\u200b","1,170","\u200b","\u200b","1,238","\u200b","\u200b","68","\u200b","6","%","\u200b"],["Daily combined production (MMcfe/d)","\u200b","\u200b","3,204","\u200b","\u200b","3,392","\u200b","\u200b","188","\u200b","6","%","\u200b"],["Average prices before effects of derivative settlements (3):","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Natural gas (per Mcf)","\u200b","$","6.92","\u200b","\u200b","2.69","\u200b","\u200b","(4.23)","\u200b","(61)","%","\u200b"],["C2 Ethane (per Bbl) (4)","\u200b","$","20.41","\u200b","\u200b","10.14","\u200b","\u200b","(10.27)","\u200b","(50)","%","\u200b"],["C3+ NGLs (per Bbl)","\u200b","$","52.98","\u200b","\u200b","37.85","\u200b","\u200b","(15.13)","\u200b","(29)","%","\u200b"],["Oil (per Bbl)","\u200b","$","85.53","\u200b","\u200b","63.80","\u200b","\u200b","(21.73)","\u200b","(25)","%","\u200b"],["Weighted Average Combined (per Mcfe)","\u200b","$","7.09","\u200b","\u200b","3.45","\u200b","\u200b","(3.64)","\u200b","(51)","%","\u200b"],["Average realized prices after effects of derivative settlements (3):","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Natural gas (per Mcf)","\u200b","$","4.54","\u200b","\u200b","2.66","\u200b","\u200b","(1.88)","\u200b","(41)","%","\u200b"],["C2 Ethane (per Bbl) (4)","\u200b","$","20.38","\u200b","\u200b","10.14","\u200b","\u200b","(10.24)","\u200b","(50)","%","\u200b"],["C3+ NGLs (per Bbl)","\u200b","$","52.63","\u200b","\u200b","37.80","\u200b","\u200b","(14.83)","\u200b","(28)","%","\u200b"],["Oil (per Bbl)","\u200b","$","84.88","\u200b","\u200b","63.50","\u200b","\u200b","(21.38)","\u200b","(25)","%","\u200b"],["Weighted Average Combined (per Mcfe)","\u200b","$","5.46","\u200b","\u200b","3.43","\u200b","\u200b","(2.03)","\u200b","(37)","%","\u200b"],["Average costs (per Mcfe):","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Lease operating","\u200b","$","0.09","\u200b","\u200b","0.10","\u200b","\u200b","0.01","\u200b","11","%","\u200b"],["Gathering and compression","\u200b","$","0.76","\u200b","\u200b","0.69","\u200b","\u200b","(0.07)","\u200b","(9)","%","\u200b"],["Processing","\u200b","$","0.74","\u200b","\u200b","0.82","\u200b","\u200b","0.08","\u200b","11","%","\u200b"],["Transportation","\u200b","$","0.72","\u200b","\u200b","0.62","\u200b","\u200b","(0.10)","\u200b","(14)","%","\u200b"],["Production and ad valorem taxes","\u200b","$","0.25","\u200b","\u200b","0.13","\u200b","\u200b","(0.12)","\u200b","(48)","%","\u200b"],["Marketing expense, net","\u200b","$","0.10","\u200b","\u200b","0.06","\u200b","\u200b","(0.04)","\u200b","(40)","%","\u200b"],["General and administrative (excluding equity-based compensation)","\u200b","$","0.12","\u200b","\u200b","0.13","\u200b","\u200b","0.01","\u200b","8","%","\u200b"],["Depletion, depreciation, amortization and accretion","\u200b","$","0.59","\u200b","\u200b","0.56","\u200b","\u200b","(0.03)","\u200b","(5)","%","\u200b"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["(1)","Production data excludes volumes related to the VPP."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["(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."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["(3)","Average prices reflect the before and after effects of our settled commodity derivatives. Our calculation of such after effects includes gains (losses) on settlements of commodity derivatives (but does not include proceeds from the derivative monetizations in 2023), which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["(4)","The average realized price for the years ended December 31, 2022 and 2023 includes $10 million and $15 million, respectively, of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives for the years ended December 31, 2022 and 2023 would have been $19.88 per Bbl and $9.55 per Bbl, respectively."]] [[/GREPCENT_TABLE]] ​ Natural gas sales. Revenues from sales of natural gas decreased from $5.5 billion, for the year ended December 31, 2022 to $2.2 billion for the year ended December 31, 2023, a decrease of $3.3 billion, or 60%. Lower commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2023 accounted for an approximate $3.4 billion decrease 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). Higher natural gas production volumes accounted for an approximate $121 million increase in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price). NGLs sales. Revenues from sales of NGLs decreased from $2.5 billion for the year ended December 31, 2022 to $1.8 billion for the year ended December 31, 2023, a decrease of $0.7 million, or 26%. Lower commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2023 accounted for an approximate $888 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Higher NGLs production volumes during the year ended December 31, 2023 accounted for an approximate $226 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price). 58 Table of Contents Oil sales. Revenues from sale of oil decreased from $276 million for the year ended December 31, 2022 to $247 million for the year ended December 31, 2023, a decrease of $29 million, or 10%. Lower oil prices for the year ended December 31, 2023 excluding the effects of derivative settlements) accounted for an approximate $84 million decrease in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes). Higher oil production volumes during the year ended December 31, 2023 accounted for an approximate $55 million increase in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price). Commodity derivative fair value losses. Our commodity derivatives included fixed price swap contracts, swaptions, basis swap contracts, call options and embedded put options. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations and comprehensive income (loss). For the years ended December 31, 2022 and 2023, our commodity hedges resulted in derivative fair value losses of $1.6 billion and fair value gains of $166 million, respectively. For the year ended December 31, 2022, commodity derivative fair value losses included $1.9 billion of net cash payments for settled derivative losses. For the year ended December 31, 2023, commodity derivative fair value gains included $25 million of net cash payments for settled commodity derivative losses, as well as $202 million for payments on derivatives that were settled prior to their contractual settlement dates. 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 or terminated prior to settlement. Derivative asset or liability positions at the end of any accounting period may reverse to the extent future commodity prices increase or decrease from their levels at the end of the accounting period, or as gains or losses are realized through settlement. Additionally, substantially all of our production is currently unhedged for 2024 and beyond, which limits our exposure to volatility in the fair value of our derivative instruments related to commodity price changes in the future. Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP decreased from $38 million for the year ended December 31, 2022 to $31 million for the year ended December 31, 2023, a decrease of $7 million or 19%, primarily due to lower production volumes attributable to the VPP properties between periods. Amortization of the deferred revenues associated with the VPP are recognized as the production volumes are delivered at $1.61 per MMBtu over the contractual term. Lease operating expense. Lease operating expense increased from $100 million, or $0.09 per Mcfe, for the year ended December 31, 2022 to $118 million, or $0.10 per Mcfe, for the year ended December 31, 2023, an increase of $18 million or $0.01 per Mcfe, primarily due to higher oilfield service, workover and produced water handling costs. Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense remained consistent at $2.6 billion for each of the years ended December 31, 2022 and 2023. This was primarily a result of the following: [[GREPCENT_TABLE]] [["","\u25cf","Gathering and compression costs on a per unit basis decreased from $0.76 per Mcfe for the year ended December 31, 2022 to $0.69 per Mcfe for the year ended December 31, 2023, primarily due to lower fuel costs as a result of decreased commodity prices, partially offset by annual CPI-based based adjustments between periods."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","Processing costs on a per unit basis increased from $0.74 per Mcfe for the year ended December 31, 2022 to $0.82 per Mcfe for the year ended December 31, 2023, primarily due to increased costs for NGLs processing and transportation, which include annual CPI-based and commodity based adjustments, as well as higher terminal fees and ethane transportation."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","Transportation costs on a per unit basis decreased from $0.72 per Mcfe for the year ended December 31, 2022 to $0.62 per Mcfe and for the year ended December 31, 2023, primarily due to lower fuel costs as a result of lower commodity prices between periods."]] [[/GREPCENT_TABLE]] Production and ad valorem tax expense. Production and ad valorem taxes decreased from $287 million for the year ended December 31, 2022 to $159 million for the year ended December 31, 2023, a decrease of $128 million or 45%, primarily due to lower commodity prices between periods, partially offset by higher production volumes between periods. Production and ad valorem taxes as a percentage of natural gas revenues increased from 5% for the year ended December 31, 2022 to 7% for the year ended December 31, 2023. General and administrative expense. General and administrative expense (excluding equity-based compensation expense) increased from $137 million for the year ended December 31, 2022 to $165 million for the year ended December 31, 2023, an increase of $28 million or 20%, primarily due to higher salary and wage expense, professional service fees, office operating costs and software license costs between periods. We had 586 and 604 employees as of December 31, 2022 and 2023, respectively. General and 59 Table of Contents administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.12 per Mcfe for the year ended December 31, 2022 to $0.13 per Mcfe for the year ended December 31, 2023 as a result of our higher overall general and administrative costs, partially offset by increased production volumes between periods. Equity-based compensation expense. Noncash equity-based compensation expense increased from $35 million for the year ended December 31, 2022 to $60 million for the year ended December 31, 2023, an increase of $25 million or 68%, primarily due to an increase in the annual equity awards granted during 2022 and 2023 as compared to prior years, which were temporarily and significantly reduced during 2020 and supplemented by our cash awards program. Our equity awards vest over three or four year service periods, and our equity incentive program began returning to normal levels in 2021. See Note 9—Equity-Based Compensation to the consolidated financial statements for more information. Depletion, depreciation and amortization expense. DD&A expense increased from $681 million, or $0.59 per Mcfe for the year ended December 31, 2022 to $690 million, or $0.56 per Mcfe for the year ended December 31, 2023, an increase of $9 million. The decrease in DD&A expense per Mcfe between periods was primarily due to higher reserve volumes during the year ended December 31, 2023. Impairment of property and equipment. Impairment of property and equipment decreased from $150 million for the year ended December 31, 2022 to $51 million for the year ended December 31, 2023, a decrease of $99 million, or 66%, primarily related to lower impairments of expiring leases between periods and the impairment of our sand mine of $48 million during the year ended December 31, 2022. During both periods, we recognized impairments primarily related to expiring leases as well as design and initial costs related to pads we no longer plan to place into service. Contract termination, loss contingency and other operating expenses. Contract termination, loss contingency and other operating expenses attributable to our exploration and production segment of $25 million for the year ended December 31, 2022 were primarily due to a payment for the cancellation of the Smithburg 2 gas processing plant and the cancellation of a gas gathering agreement. Contract termination, loss contingency and other operating expenses attributable to our exploration and production segment of $29 million for the year ended December 31, 2023 were primarily due to a loss contingency and the early termination of certain drilling and completion contracts. 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 $115 million, or $0.10 per Mcfe, for the year ended December 31, 2022 to $79 million, or $0.06 per Mcfe, for the year ended December 31, 2023, primarily due to lower firm transportation commitments, partially offset by lower marketing margin on third-party product purchases between periods. Marketing revenue. Marketing revenue decreased from $417 million for the year ended December 31, 2022 to $206 million for the year ended December 31, 2023, a decrease of $211 million, or 51%. This fluctuation primarily resulted from the following: [[GREPCENT_TABLE]] [["","\u25cf","Natural gas marketing revenue decreased by $187 million between periods primarily due to lower natural gas prices and marketing volumes. Lower natural gas prices accounted for an approximate $182 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes), and lower natural gas marketing volumes accounted for a $5 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price)."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","Ethane marketing revenues were $42 million for the year ended December 31, 2022. There were no third-party ethane marketing revenues for the year ended December 31, 2023."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","Oil marketing revenue increased by $16 million between periods primarily due to higher marketing volumes, partially offset by lower oil prices. Higher oil marketing volumes accounted for a $42 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower oil prices accounted for an approximate $26 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes)."]] [[/GREPCENT_TABLE]] ​ 60 Table of Contents Marketing expense. Marketing expense decreased from $531 million for the year ended December 31, 2022 to $285 million for the year ended December 31, 2023, a decrease of $246 million, or 46%. 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 and NGLs decreased $188 million and $28 million, respectively, between periods, partially offset by increased oil purchases of $14 million between periods. The total costs decreased between periods primarily due to lower commodity prices and lower natural gas and NGL third-party marketing volumes, partially offset by increased oil marketing volumes. Firm transportation costs were $149 million for the year ended December 31, 2022 and $105 million for the year ended December 31, 2023, a decrease of $44 million primarily due to the reduction in firm transportation commitments between periods. Contract termination, loss contingency and other operating expenses. Our marketing segment did not incur any contract termination, loss contingency and other operating expenses for the year ended December 31, 2022. Contract termination, loss contingency and other operating expenses attributable to our marketing segment for the year ended December 31, 2023 relate to a $24 million payment for the early termination of our firm transportation commitment of 200,000 MMBtu/d on the Equitrans pipeline. Antero Midstream Segment Antero Midstream revenue.  Revenue from the Antero Midstream segment increased from $0.9 billion for the year ended December 31, 2022 to $1.0 billion for the year ended December 31, 2023, an increase of $0.1 billion, or 13%, primarily due to increased throughput and higher water handling volumes between periods, as well as higher low pressure, compression, high pressure and fresh water delivery fees as a result of an annual CPI-based adjustments and increased other fluid handling fees primarily due to increased costs partially due to inflationary pressures between periods that impact the cost plus 3% and cost of service rates. Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $381 million for the year ended December 31, 2022 to $430 million for the year ended December 31, 2023, an increase of $49 million, or 13%, primarily due to increased direct operating costs, equity-based compensation and depreciation expense, partially offset by decreased general and administrative expenses (excluding equity-based compensation expense) between periods. Direct operating expenses increased between periods primarily due to 12 compressors that were acquired during the fourth quarter of 2022, higher wastewater trucking rates, increased heavy maintenance expense and an increased number of locations connected to its water blending system between periods. Equity-based compensation increased between periods primarily due to an increase in the annual equity awards granted during the years ended December 31, 2022 and 2023 as compared to prior years, which were temporarily and significantly reduced during 2020 and supplemented by our cash awards program. Antero Midstream’s equity awards vest over three or four year service periods, and its equity incentive program began returning to normal levels in 2021. Depreciation expense increased between periods primarily due to assets acquired during the fourth quarter of 2022 and assets placed in service during the year ended December 31, 2023, partially offset by lower depreciation expense associated with Antero Midstream’s program to repurpose underutilized compressor units to expand existing or construct new compressor stations between periods. General and administrative expenses (excluding equity-based compensation expense) decreased between periods primarily due to lower legal costs. Items Not Allocated to Segments Interest expense. Interest expense decreased from $125 million for the year ended December 31, 2022 to $118 million for the year ended December 31, 2023, a decrease of $7 million, or 6%, primarily due to our redemption or repurchase of $990 million in aggregate principal amount of certain of our Senior Notes during the year ended December 31, 2022, partially offset by higher benchmark interest rates during the year ended December 31, 2023 and higher average Credit Facility borrowings between periods. See Note 7—Long-Term Debt to the consolidated financial statements for more information. Loss on early extinguishment of debt. During the year ended December 31, 2022, we redeemed or repurchased through our previously disclosed tender offer and open market transactions (i) the remaining $585 million aggregate principal amount of our 2025 Notes at a redemption price of 101.25% of the principal amount thereof, plus accrued and unpaid interest, (ii) $228 million of our 2026 Notes at a weighted average redemption price of 109% of the principal amount thereof, plus accrued and unpaid interest and (iii) $177 million of our 2029 Notes at a weighted average redemption price of 106% of the principal amount thereof, plus accrued and unpaid interest. For such redemptions and repurchases, we recognized a $46 million loss on early extinguishment of debt. There were no redemptions or repurchases of our Senior Notes during the year ended December 31, 2023. See Note 7—Long-Term Debt to the consolidated financial statements for more information. ​ Income tax expense. Income tax expense decreased from $449 million for the year ended December 31, 2022 to $76 million for the year ended December 31, 2023 primarily due to lower pre-tax income between periods. The effective tax rate for the years ended December 31, 2022 and 2023 were 18.1% and 18.2%, respectively. Our effective tax rate was different than the statutory rate of 21% primarily due to the effects of state income taxes, the dividends received deduction, equity-based compensation expenses, noncontrolling interests, the effects of a West Virginia apportionment tax law change enacted in 2021 and changes in Pennsylvania’s corporate income tax rate. See Note 13—Income Taxes to our consolidated financial statements more for information. 61 Table of Contents As of December 31, 2023, we had U.S. federal and state NOL carryforwards of $1.0 billion and $1.9 billion, respectively. Many of these NOL carryforwards expire at various dates between 2025 and 2041 while others have no expiration date. Potential future legislation or the imposition of new or increased taxes may have a significant effect on our future taxable position. The impact of any such change would be recorded in the period in which such interpretation is received or legislation is enacted. Year Ended December 31, 2021 Compared to Year Ended December 31, 2022 Refer to “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2022 for a discussion of the results of operations for the year ended December 31, 2021 compared to the year ended December 31, 2022. Capital Resources and Liquidity Overview Our primary sources of liquidity have been through net cash provided by operating activities, borrowings under our Credit Facility, issuances of debt and equity securities and additional contributions from our asset sales, including our drilling partnership. Our primary use of cash has been for the exploration, development and acquisition of oil and natural gas properties. As we develop our reserves, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future success in developing our proved reserves and production will be highly dependent on net cash provided by operating activities and the capital resources available to us. The Credit Facility has a borrowing base of $3.5 billion and current lender commitments of $1.6 billion. The borrowing base is redetermined semi-annually based on certain factors including our reserves, natural gas, NGLs and oil commodity prices, and the value of our hedge portfolio. The next redetermination of the borrowing base is scheduled to occur in April 2024. For a discussion of the risks of a decrease in the borrowing base under the Credit Facility, see “Item 1A. Risk Factors—The borrowing base under the Credit Facility may be reduced if commodity prices decline, which could hinder or prevent us from meeting our future capital needs. We may also be required to post additional collateral as financial assurance of our performance under certain contractual arrangements, which could adversely impact available liquidity under our Credit Facility.” Our commodity hedge position provides us with liquidity for a portion of our production because it provides us with the relative certainty of receiving a portion of our future expected revenues from operations despite potential declines in the price of natural gas. Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased. For the years ended December 31, 2022 and 2023, 33% and 1%, respectively, of our production was hedged through fixed price commodity swaps, and as of December 31, 2023, we had no fixed price commodity swap positions. Our ability to make significant acquisitions for cash would require us to utilize borrowings on the Credit Facility or obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us, or at all. The Credit Facility is funded by a syndicate of 16 banks. We believe that the participants in the syndicate have the capability to fund up to their current commitment. If one or more banks should not be able to do so, we may not have the full availability of the Credit Facility. 2023 Capital Spending and 2024 Capital Budget For the year ended December 31, 2023, our total consolidated capital expenditures were $1.1 billion, including drilling and completion expenditures of $909 million, leasehold additions of $148 million and other capital expenditures of $15 million. We completed 70 net horizontal wells during the year ended December 31, 2023. Our net capital budget for 2024 is $725 million to $800 million. Our budget includes: a range of $650 million to $700 million for drilling and completion and $75 million to $100 million for leasehold expenditures. We do not budget for acquisitions. During 2024, we plan to complete 45 to 50 net horizontal wells in the Appalachian Basin. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices. Our capital budget may be adjusted as business conditions warrant as the amount, timing and allocation of capital expenditures is largely discretionary and within our control. If natural gas, NGLs and oil prices decline, or costs increase, to levels that do not generate an acceptable level of corporate returns, we may defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity, and to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. Based on strip prices as of December 31, 2023, we believe that net cash provided from operating activities and available borrowings under the Credit Facility will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures and commitments and contingencies for at least the next 12 months. For more information on our outstanding indebtedness, see “—Debt Agreements.” 62 Table of Contents See Note 14—Commitments to the consolidated financial statements for information on our off-balance sheet arrangements. Cash Flows The following table summarizes our cash flows (in thousands): [[GREPCENT_TABLE]] [["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Year Ended December 31,","\u200b"],["\u200b","\u200b","2022","","2023"],["Net cash provided by operating activities","\u200b","$","3,051,342","\u200b","\u200b","994,721","\u200b"],["Net cash used in investing activities","\u200b","\u200b","(943,612)","\u200b","\u200b","(1,140,767)","\u200b"],["Net cash provided by (used in) financing activities","\u200b","\u200b","(2,107,730)","\u200b","\u200b","146,046","\u200b"],["Net increase in cash and cash equivalents","\u200b","$","\u2014","\u200b","\u200b","\u2014","\u200b"]] [[/GREPCENT_TABLE]] ​ Year Ended December 31, 2022 Compared to Year Ended December 31, 2023 Operating activities. Net cash provided by operating activities was $3.1 billion and $1.0 billion for the years ended December 31, 2022 and 2023, respectively. Net cash provided by operating activities decreased primarily due to decreases in commodity prices, a $202 million payment for early settlement of our swaption agreement and higher contract termination, gathering, compression, processing and transportation, general and administrative (excluding equity-based compensation expense) and lease operating expenses. These operating cash flow decreases were partially offset by higher production, lower production and ad valorem taxes, interest expense and net marketing expense, decreased payments for commodity derivative settlements and changes in working capital between periods. Our net operating cash flows are sensitive to many variables, the most significant of which is the volatility of natural gas, NGLs and oil prices, as well as volatility in the cash flows attributable to settlement of our commodity derivatives. Prices for natural gas, NGLs and oil are primarily determined by prevailing market conditions. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets, storage capacity and other variables influence the market conditions for these products. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.” Investing activities. Net cash used in investing activities increased from $0.9 billion for the year ended December 31, 2022 to $1.1 billion for the year ended December 31, 2023, primarily due to increased drilling and completions activity and land purchases, as well as higher drilling and water costs between periods. Financing activities. Net cash flows used in financing activities was $2.1 billion for the year ended December 31, 2022. Net cash flows provided by financing activities was $0.1 billion for the year ended December 31, 2023. This increase between periods is primarily due to lower Senior Note redemptions and repurchases of $1.0 billion, decreased share repurchases of $0.8 billion and higher net borrowings on our Credit Facility of $0.3 billion. Year Ended December 31, 2021 Compared to Year Ended December 31, 2022 Refer to “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity” in our Annual Report on Form 10-K for the year ended December 31, 2022 for a discussion of the cash flows for the year ended December 31, 2021 compared to the year ended December 31, 2022. Debt Agreements Credit Facility We have a senior secured revolving credit facility with a consortium of bank lenders. On October 26, 2021, we entered into an amended and restated senior secured revolving credit facility, the Credit Facility. Borrowings under the 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 December 31, 2023, the borrowing base was $3.5 billion and lender commitments were $1.6 billion. The next redetermination of the borrowing base is scheduled to occur in April 2024. The maturity date of the 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 then outstanding Senior Notes. As of December 31, 2023, we had an outstanding balance under the Credit Facility of $417 million and outstanding letters of credit of $501 million. 63 Table of Contents The Credit Facility provides for borrowing at either an Adjusted Term Secured Overnight Financing Rate (“SOFR”), an Adjusted Daily Simple SOFR or an Alternate Base Rate (each as defined in the Credit Facility). The Credit Facility contains restrictive covenants that may limit our ability to, among other things: [[GREPCENT_TABLE]] [["","\u25cf","incur additional indebtedness;"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","sell assets;"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","make loans to others;"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","make investments;"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","enter into mergers;"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","pay dividends;"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","hedge future production;"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","incur liens; and"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","engage in certain other transactions without the prior consent of the lenders."]] [[/GREPCENT_TABLE]] The Credit Facility also requires us to maintain the following financial ratios (subject to certain exceptions). The current ratio and the leverage ratio are tested quarterly. [[GREPCENT_TABLE]] [["","\u25cf","a minimum consolidated current ratio of 1.00 to 1.00 at the end of each fiscal quarter; and"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","\u25cf","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."]] [[/GREPCENT_TABLE]] As of December 31, 2022 and 2023, we were in compliance with the applicable covenants and ratios under the Credit Facility. See Note 7—Long Term Debt to the consolidated financial statements included in this Annual Report on Form 10-K for more information on our Credit Facility. Senior Unsecured Notes The following table summarizes certain material terms of our Senior Notes and 2026 Convertible Notes outstanding as of December 31, 2023: [[GREPCENT_TABLE]] [["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","2026","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","Convertible","\u200b"],["\u200b","","2026 Notes","\u200b","2029 Notes","\u200b","2030 Notes","\u200b","Notes","\u200b"],["Outstanding principal (in thousands)","\u200b","$","96,870","\u200b","$","407,115","\u200b","$","600,000","\u200b","$","26,386","\u200b"],["Interest rate","\u200b","\u200b","8.375","%","\u200b","7.625","%","\u200b","5.735","%","\u200b","4.25","%"],["Maturity date","\u200b","\u200b","July 15, 2026","\u200b","\u200b","February 1, 2029","\u200b","\u200b","March 1, 2030","\u200b","\u200b","September 1, 2026","\u200b"],["Interest payment dates","\u200b","\u200b","Jan. 15, July 15","\u200b","\u200b","Feb. 1, Aug. 1","\u200b","\u200b","Mar. 1, Sept. 1","\u200b","\u200b","Mar. 1, Sept. 1","\u200b"],["Make-whole redemption date (1)","\u200b","\u200b","January 15, 2026","\u200b","\u200b","February 1, 2027","\u200b","\u200b","March 1, 2028","\u200b","\u200b","N/A (2)","\u200b"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["(1)","On or after these dates, we may redeem the applicable series of notes, in whole or in part, at a redemption price equal to 100% of the principal amount redeemed, together with accrued and unpaid interest up to the redemption date. At any time prior to these dates, we may redeem the notes at a redemption price that includes an applicable premium as defined in the indentures to such notes."]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["(2)","The indenture governing the 2026 Convertible Notes does not allow us to optionally redeem the 2026 Convertible Notes prior to the maturity date."]] [[/GREPCENT_TABLE]] See Note 7—Long-Term Debt to the consolidated financial statements for more information. We may, from time to time, seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, open market purchases, privately negotiated transactions or otherwise. Any such repurchases will depend on 64 Table of Contents prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved could be material. See Note 7—Long-Term Debt to the consolidated financial statements for more information. The Senior Notes indentures each contain restrictive covenants and restrict our ability to incur additional debt unless a pro forma minimum interest coverage ratio requirement of 2.25:1 is maintained. We were in compliance with such covenants as of December 31, 2022 and 2023. Critical Accounting Estimates The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in Note 2—Summary of Significant Accounting Policies to our consolidated financial statements. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingent liabilities. Accounting estimates and assumptions are considered to be critical if there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the reported amounts in our consolidated financial statements that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. Successful Efforts Method We account for our natural gas, NGLs and oil exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, the costs incurred to acquire, drill and complete productive wells, development wells and oil and gas leases are capitalized. Items charged to expense generally include exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases and costs associated with unsuccessful lease acquisitions. Unproved properties with significant acquisition costs are assessed for impairment on a property by property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks and future plans to develop acreage. Impairment of oil and gas properties related to unproved properties for leases that have expired, or are expected to expire, was $91 million, $98 million and $51 million for the years ended December 31, 2021, 2022 and 2023, respectively. We believe that the application of the successful efforts method of accounting requires judgment to determine the proper classification of wells designated as developmental or exploratory, which designation determines the proper accounting treatment of the costs incurred. In addition, evaluating our unproved properties for impairment involves significant judgments about future development plans, which include future sales prices of natural gas, NGLs and oil and future development and production costs, as well as the amount of natural gas, NGLs and oil recoveries. Natural Gas, NGLs and Oil Reserve Quantities Our internal technical staff prepares the estimates of natural gas, NGLs and oil reserves and associated future net cash flows, which are audited by our independent reserve engineers. The SEC has defined proved reserves as the estimated quantities of natural gas, NGLs and oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved undeveloped reserves include reserves that are expected to be drilled and developed within five years; wells that are not drilled within five years from booking are reclassified from proved reserves to probable reserves. Reserves are used in our proved properties depletion calculation and in assessing the carrying value of our oil and gas properties. Our independent reserve engineers and internal technical staff must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates consider recent production levels and other technical information about each reservoir. Natural gas, NGLs and oil reserve engineering is a subjective process of estimating underground accumulations of natural gas, NGLs and oil that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, natural gas, NGLs and oil prices, cost changes, technological advances, new geological or geophysical data or other economic factors. Accordingly, reserve estimates are generally different from the quantities of natural gas, NGLs and oil that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. 65 Table of Contents We believe that the estimates and assumptions related to reserve quantities is critical because any significant revisions or changes to these estimates and assumptions could affect the future amortization rates of capitalized proved property costs and result in a material asset impairment. Impairment of Proved Properties We evaluate the carrying amount of our proved natural gas, NGLs and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount of our proved properties exceeds the estimated undiscounted future net cash flows (measured using futures prices at the balance sheet date), we further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeds the estimated fair value of the properties. We did not record any impairments for proved properties during the years ended December 31, 2021, 2022 and 2023. Based on current future commodity prices, we currently do not anticipate having to record any impairment charge for our proved properties in the near future. 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. For our Utica and Marcellus properties, strip pricing would have to decline by more than 20% and 25%, respectively, from year end 2023 levels before further evaluation of those properties would be required in order to determine if an impairment charge is necessary. If future prices decline from December 31, 2023, the fair value of our properties may be below their carrying amounts and an impairment charge may be necessary. However, we are unable to predict commodity prices with any greater precision than the futures market. We believe that the estimates and assumptions related to our undiscounted future net cash flows and the fair value of our proved properties is critical because different natural gas, NGLs and oil pricing, cost assumptions or discount rates, as applicable, may affect the recognition, timing and amount of an impairment and, if changed, could have a material effect on the Company's financial position and results of operations. Derivative Instruments In order to manage our exposure to natural gas, NGLs and oil price volatility, we may enter into derivative transactions from time to time, which agreements could include commodity fixed price swaps, basis swaps, collars or other similar instruments related to the price risk associated with our production. We record derivative instruments on the consolidated balance sheet as either assets or liabilities measured at fair value and record changes in the fair value of derivatives in current earnings as they occur. Our derivatives have not been designated as hedges for accounting purposes. Fair value measurements for our commodity derivatives require the use of assumptions and judgements including valuation techniques, future pricing, volatility, time to maturity and credit risk, among others. We regularly assess the reasonableness of these assumptions and judgements through the review of counterparty statements. However, changes to these assumptions and judgements could have a material effect on the Company's financial position and results of operations. Income Taxes Income taxes are accounted for using the asset and liability approach. Under this approach, deferred income tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. We record deferred income tax expense to the extent our deferred income tax liabilities exceed our deferred income tax assets. We record a deferred income tax benefit to the extent our deferred income tax assets exceed our deferred income tax liabilities. We are subject to state and federal income taxes, but are currently not in a cash tax paying position with respect to federal income taxes. We record a valuation allowance when we believe all or a portion of our deferred income tax assets will not be realized. In assessing the realizability of our deferred income tax assets, management considers whether some portion or all of the deferred income tax assets will be realized based on a more-likely-than-not standard of judgment. The ultimate realization of deferred income tax assets is dependent upon our ability to generate future taxable income during the periods in which our deferred income tax assets are deductible. Management considers the scheduled reversal of deferred income tax liabilities, projected future taxable income and tax planning strategies in making this assessment, estimates of which may be imprecise due to unforeseen future events or conditions outside of our control, including changes in commodity prices or changes to tax laws and regulations. The amount of deferred income tax assets considered realizable could change based upon the amounts of taxable income actually generated, or as estimates of future taxable income change. As of December 31, 2023, we have recognized a valuation allowance of $55 million related to Colorado, Oklahoma and West Virginia state NOL carryforwards that we do not expect to realize due to expected future reduced income tax apportionment in those states. 66 Table of Contents The calculation of deferred income tax assets and liabilities involves uncertainties in the application of complex tax laws and regulations. We recognize in our financial statements those tax positions which we believe are more-likely-than-not to be sustained upon examination by the Internal Revenue Service or state revenue authorities. We believe that the estimates and assumptions related to income taxes are critical because the assumptions and estimates required to assess the likelihood that our deferred income tax assets will be recovered from future taxable income, as well as the amount and timing of a valuation allowance on our deferred income tax assets is an exercise in judgement and susceptible to change as circumstances warrant. These assumptions affect deferred income tax liability and income tax expense and, if changed, could have a material effect on the Company's financial position and results of operations.