# ANTERO RESOURCES Corp (AR) FY 2022 MD&A

Verbatim Item 7 Management's Discussion and Analysis from ANTERO RESOURCES Corp's 10-K for fiscal year 2022.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1433270/000155837023001378/ar-20221231x10k.htm
Accession: 0001558370-23-001378
Filing date: 2023-02-15
Report date: 2022-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Published MD&A gate trimmed front/tail over-capture.
Confidence: high

Company profile: /company/AR/
All MD&A years: /company/AR/mda/
Previous year: /company/AR/mda/fy2021/ (FY 2021)
Next year: /company/AR/mda/fy2023/ (FY 2023)

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, 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 December 31, 2022, we held approximately 504,000 net acres in the Appalachian Basin. In addition, we estimate that approximately 174,000 net acres of our leasehold may be prospective for the slightly shallower Upper Devonian Shale.

As of December 31, 2022, our estimated proved reserves were 17.8 Tcfe, consisting of 10.3 Tcf of natural gas, 712 MMBbl of assumed recovered ethane, 505 MMBbl of C3+ NGLs and 31 MMBbl of oil. This represents a 0.2% increase in estimated proved reserves from December 31, 2021. These reserve estimates have been prepared by our internal reserve engineers and management and audited by our independent reserve engineers. As of December 31, 2022, we had approximately 1,819 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

Debt Repurchase Program

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 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, (ii) $228 million aggregate principal amount of our 8.375% senior notes due July 15, 2026 (the “2026 Notes”) at a weighted average price of 109% of the principal amount thereof, plus accrued and unpaid interest, and (iii) $177 million aggregate principal amount of our 7.625% senior notes due February 1, 2029 (the “2029 Notes”) at a weighted average price of 106% of the principal amount thereof, plus accrued and unpaid interest. See Note 7—Long-Term Debt to the consolidated financial statements for more information.

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Share Repurchase Program

On February 15, 2022, our Board of Directors authorized a share repurchase program that allows the Company to repurchase up to $1.0 billion of outstanding common stock. On October 25, 2022, our Board of Directors authorized a $1.0 billion increase to our share repurchase program to allow us to repurchase up to $2.0 billion of outstanding common stock. Through December 31, 2022, we have repurchased 25 million shares of our common stock through our share repurchase program at a total cost of $874 million. 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. Beginning in 2023, our share repurchase program will be subject to the new 1% excise tax imposed under the IRA 2022.

2026 Convertible Notes Conversions

During the year ended December 31, 2022, $20 million in aggregate principal amount of the 4.25% convertible senior notes due 2026 (the “2026 Convertible Notes”) were converted pursuant to their terms, and an additional $5 million in aggregate principal amount of the 2026 Convertible Notes were induced into conversion. We elected to settle these conversions by issuing approximately 6 million shares of common stock to the noteholders together with a cash inducement premium of $0.2 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 Capital Partners (“QL”), an affiliate of Quantum Energy Partners, for our 2021 through 2024 drilling program. Under the terms of the arrangement, each year in which QL participates represents an annual tranche, and QL will be conveyed a working interest in any wells spud by us during such tranche year. For 2021, 2022 and 2023, we agreed to the estimated internal rate of return (“IRR”) or our capital budget for each annual tranche, and QL agreed to participate in the 2021, 2022 and 2023 tranches. For 2024, we will propose a capital budget and estimated IRR for all wells to be spud during such year and, subject to the mutual agreement of the parties that the estimated IRR for the year exceeds a specified return, QL will be obligated to participate in such tranche. We develop and manage the drilling program associated with each tranche, including the selection of wells. Additionally, for each annual tranche in which QL participates, together with QL, we will enter into 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 20% and 15% of development capital for wells spud in 2021 and 2022, respectively, and will fund development capital of (i) 15% for wells spud in 2023 and (ii) if they participate in 2024, between 15% and 20% 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. During the year ended December 31, 2022, we received a carry of $29 million attributable to the 2021 tranche. 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, NGL and oil benchmark prices increased significantly during the year ended December 31, 2022 as compared to the year ended December 31, 2021. As a result, we experienced a significant increase in price realizations during the year ended December 31, 2022. We monitor the economic factors that impact natural gas, NGL and oil prices, including domestic and foreign supply and demand indicators, domestic and foreign commodity inventories, the actions of Organization of Petroleum Exporting Countries and other large producing nations and the current Russia-Ukraine conflict, among others. In the current economic environment, we expect that commodity prices for some or all of the commodities we produce could remain volatile. This volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.

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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","","2021","","2022","\u200b"],["Henry Hub (1) ($/Mcf)","\u200b","$","3.84","\u200b","\u200b","6.64","\u200b"],["West Texas Intermediate (2) ($/Bbl)","\u200b","\u200b","67.96","\u200b","\u200b","94.23","\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 as we deem necessary to manage such risks. In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. Due to our improved liquidity and leverage position as compared to past levels, the percentage of our expected production that we hedge has decreased. For the years ended December 31, 2021 and 2022, approximately 70% and 33%, respectively, of our production was hedged through fixed price commodity swaps. Assuming our 2023 production is the same as our production in 2022, approximately 1% of our production for 2023 will be hedged through fixed price commodity swaps. The tables and narrative below excludes derivative instruments attributable to Martica, our consolidated VIE, since all gains or losses from such contracts are fully attributable to the noncontrolling interests in Martica.

As of December 31, 2022, our fixed price natural gas swap positions excluding Martica 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"],["Natural Gas","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["January-December 2023","\u200b","Henry Hub","\u200b","16","Bcf","\u200b","$","2.37","/MMBtu","\u200b"]]
[[/GREPCENT_TABLE]]

​

As of December 31, 2022, 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 2023","\u200b","NYMEX to TCO","\u200b","18","Bcf","\u200b","$","0.525","/MMBtu","\u200b"],["January-December 2024","\u200b","NYMEX to TCO","\u200b","18","Bcf","\u200b","\u200b","0.530","/MMBtu","\u200b"],["\u200b","\u200b","\u200b","\u200b","36","Bcf","\u200b","\u200b","0.528","/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, 2022, 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 2023","\u200b","Henry Hub","\u200b","20","Bcf","\u200b","$","2.466","/MMBtu","\u200b","$","2.466","/MMBtu","\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","67","Bcf","\u200b","\u200b","2.521","/MMBtu","\u200b","\u200b","2.556","/MMBtu","\u200b"]]
[[/GREPCENT_TABLE]]

​

In addition, we had a swaption agreement, which entitled the counterparty the right, but not the obligation, to enter into a fixed price swap agreement for approximately 156 Bcf at a price of $2.77 per MMBtu for the year ending December 31, 2024. In

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January 2023, we executed an early settlement of this swaption agreement and made a cash payment of $202 million, which was funded by borrowings under our Credit Facility.

As of December 31, 2022, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of $384 million, which includes a liability of $248 million for the swaption agreement. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information.

Martica

Our consolidated VIE, Martica, also maintains a portfolio of fixed swap natural gas, NGL 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, 2022, Martica’s fixed price natural gas, NGL 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"],["January-December 2023","\u200b","Henry Hub","\u200b","13","Bcf","\u200b","$","2.35","/MMBtu","\u200b"],["January-December 2024","\u200b","Henry Hub","\u200b","9","Bcf","\u200b","\u200b","2.33","/MMBtu","\u200b"],["January-March 2025","\u200b","Henry Hub","\u200b","2","Bcf","\u200b","\u200b","2.53","/MMBtu","\u200b"],["\u200b","\u200b","\u200b","\u200b","24","Bcf","\u200b","\u200b","2.35","/MMBtu","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Natural Gasoline","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["January-December 2023","\u200b","Mont Belvieu Natural Gasoline-OPIS Non-TET","\u200b","90,002","Bbl","\u200b","\u200b","40.74","/Bbl","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Oil","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["January-December 2023","\u200b","West Texas Intermediate","\u200b","36,000","Bbl","\u200b","\u200b","44.88","/Bbl","\u200b"],["January-December 2024","\u200b","West Texas Intermediate","\u200b","15,699","Bbl","\u200b","\u200b","44.02","/Bbl","\u200b"],["January-March 2025","\u200b","West Texas Intermediate","\u200b","3,535","Bbl","\u200b","\u200b","45.06","/Bbl","\u200b"],["\u200b","\u200b","\u200b","\u200b","55,234","Bbl","\u200b","\u200b","44.65","/Bbl","\u200b"]]
[[/GREPCENT_TABLE]]

​

As of December 31, 2022, the estimated fair value of Martica’s commodity derivative contracts was a net liability of $47 million. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information.

Economic Indicators

The economy is experiencing elevated inflation levels as a result of global supply and demand imbalances, where global demand continues to outpace current supplies. For example, the BLS Consumer Price Index (“CPI”) for all urban consumers increased 8% from December 2021 to December 2022 as compared to the Federal Reserve’s stated goal of 2%. In order to manage the inflation risk currently present in the United States’ economy, the Federal Reserve has utilized monetary policy in the form of interest rate increases in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis.

The global economy also continues to be impacted by the effects of the COVID-19 pandemic and global events, among other factors. These events have often caused global supply chain disruptions with additional pressure due to trade sanctions on Russia and other global trade restrictions, among others. However, our supply chain has not experienced any significant interruptions as a result of the COVID-19 pandemic or global supply and demand imbalances.

Inflationary pressures, particularly as they relate to certain of our long-term contracts with CPI-based adjustments, and supply chain disruptions have and could continue to result in increases to our operating and capital costs that are not fixed. For example, our 2023 capital budget reflects an approximate 10% increase in service cost inflation as compared to the year ended December 31, 2022. Additionally, these economic variables could lead to a renegotiation of contracts and/or supply agreements, among others. These economic variables are beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.

COVID-19 Pandemic

We continue to operate throughout the COVID-19 pandemic, in some cases subject to federal, state and local regulations, and we have taken and continue to take 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 offices, and these protocols have not impacted our production, throughput or

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business activities. During 2022, we transitioned from a hybrid working arrangement for non-field employees, which involved a combination of in-office and remote work-from-home arrangements, to an in-office working arrangement for all non-field employees. 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.

Sources of Our Revenues

[[GREPCENT_TABLE]]
[["","\u25cf","Natural gas, NGL 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, our production revenues were comprised of approximately 67% from the sale of natural gas and 33% 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. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations for a portion of our production, we utilize derivative instruments to hedge future sales prices on such production. We have entered into fixed price contracts for natural gas in which we receive or pay the difference between a fixed price and the variable market price received, as well as basis swap contracts that hedge the difference between the NYMEX index price and a local index price. Additionally, we also utilize swaptions, call and put options, which may be embedded in other contracts, from time to time. Due to our improved liquidity and leverage position as compared to past levels, the percentage of our expected production that we hedge has decreased. Assuming our 2023 production is the same as our production in 2022, approximately 1% of our production for 2023 will be hedged through fixed price commodity swaps. See Note 11\u2014Derivative Instruments to the unaudited condensed 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 (not hedged prices) 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 transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully"]]
[[/GREPCENT_TABLE]]

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[[GREPCENT_TABLE]]
[["","","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 and Cash Awards 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 until October 26, 2021 had a variable rate of interest based on LIBOR or the Alternate Base Rate and on and after October 26, 2021 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 a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions. As of December 31, 2022, we had fixed interest rates of (i) 8.375% on our 2026 Notes having a principal balance of $97 million, (ii) 7.625% on our 2029 Notes having a principal balance of $407 million, (iii) 5.375% on our 2030 Notes having a principal balance of $600 million and (iv) 4.25% on our 2026 Convertible Notes having a principal balance of $57 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 tax liabilities exceed our deferred tax assets. See Note 13\u2014Income Taxes to the consolidated financial statements for more information."]]
[[/GREPCENT_TABLE]]

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.

53

Table of Contents

Year Ended December 31, 2021 Compared to Year Ended December 31, 2022

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, 2021","\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","","Affiliates","","Total"],["Revenue and other:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Natural gas sales","\u200b","$","3,442,028","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","3,442,028","\u200b"],["Natural gas liquids sales","\u200b","\u200b","2,147,499","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","2,147,499","\u200b"],["Oil sales","\u200b","\u200b","201,232","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","201,232","\u200b"],["Commodity derivative fair value losses","\u200b","\u200b","(1,936,509)","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","(1,936,509)","\u200b"],["Gathering, compression and water handling","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","968,874","\u200b","\u200b","(968,874)","\u200b","\u200b","\u2014","\u200b"],["Marketing","\u200b","\u200b","\u2014","\u200b","\u200b","718,921","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","718,921","\u200b"],["Amortization of deferred revenue, VPP","\u200b","\u200b","45,236","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","45,236","\u200b"],["Other income (loss)","\u200b","\u200b","1,025","\u200b","\u200b","\u2014","\u200b","\u200b","(70,672)","\u200b","\u200b","70,672","\u200b","\u200b","1,025","\u200b"],["Total revenue","\u200b","\u200b","3,900,511","\u200b","\u200b","718,921","\u200b","\u200b","898,202","\u200b","\u200b","(898,202)","\u200b","\u200b","4,619,432","\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","96,793","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","96,793","\u200b"],["Gathering and compression","\u200b","\u200b","874,023","\u200b","\u200b","\u2014","\u200b","\u200b","65,983","\u200b","\u200b","(65,983)","\u200b","\u200b","874,023","\u200b"],["Processing","\u200b","\u200b","791,978","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","791,978","\u200b"],["Transportation","\u200b","\u200b","833,173","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","833,173","\u200b"],["Water handling","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","91,137","\u200b","\u200b","(91,137)","\u200b","\u200b","\u2014","\u200b"],["Production and ad valorem taxes","\u200b","\u200b","197,910","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","197,910","\u200b"],["Marketing","\u200b","\u200b","\u2014","\u200b","\u200b","811,698","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","811,698","\u200b"],["Exploration and mine expenses","\u200b","\u200b","6,566","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","\u2014","\u200b","\u200b","6,566","\u200b"],["General and administrative (excluding equity-based compensation)","\u200b","\u200b","124,569","\u200b","\u200b","\u2014","\u200b","\u200b","50,299","\u200b","\u200b","(50,299)","\u200b","\u200b","124,569","\u200b"],["Equity-based compensation","\u200b","\u200b","20,437","\u200b","\u200b","\u2014","\u200b","\u200b","13,539","\u200b","\u200b","(13,539)","\u200b","\u200b","20,437","\u200b"],["Depletion, depreciation and amortization","\u200b","\u200b","742,009","\u200b","\u200b","\u2014","\u200b","\u200b","108,790","\u200b","\u200b","(108,790)","\u200b","\u200b","742,009","\u200b"],["Impairment of property and equipment","\u200b","\u200b","90,523","\u200b","\u200b","\u2014","\u200b","\u200b","5,042","\u200b","\u200b","(5,042)","\u200b","\u200b","90,523","\u200b"],["Accretion of asset retirement obligations","\u200b","\u200b","3,820","\u200b","\u200b","\u2014","\u200b","\u200b","460","\u200b","\u200b","(460)","\u200b","\u200b","3,820","\u200b"],["Contract termination and other expenses","\u200b","\u200b","4,305","\u200b","\u200b","\u2014","\u200b","\u200b","3,997","\u200b","\u200b","(3,997)","\u200b","\u200b","4,305","\u200b"],["Loss (gain) on sale of assets","\u200b","\u200b","(2,232)","\u200b","\u200b","\u2014","\u200b","\u200b","3,628","\u200b","\u200b","(3,628)","\u200b","\u200b","(2,232)","\u200b"],["Total operating expenses","\u200b","\u200b","3,783,874","\u200b","\u200b","811,698","\u200b","\u200b","342,875","\u200b","\u200b","(342,875)","\u200b","\u200b","4,595,572","\u200b"],["Operating income (loss)","\u200b","$","116,637","\u200b","\u200b","(92,777)","\u200b","\u200b","555,327","\u200b","\u200b","(555,327)","\u200b","\u200b","23,860","\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","$","77,085","\u200b","\u200b","\u2014","\u200b","\u200b","90,451","\u200b","\u200b","(90,451)","\u200b","\u200b","77,085","\u200b"]]
[[/GREPCENT_TABLE]]

​

​

54

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, 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","","Affiliates","","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","990,657","\u200b","\u200b","(990,657)","\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 income (loss)","\u200b","\u200b","5,162","\u200b","\u200b","\u2014","\u200b","\u200b","(70,672)","\u200b","\u200b","70,672","\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"],["Loss (gain) on sale of assets","\u200b","\u200b","471","\u200b","\u200b","\u2014","\u200b","\u200b","(2,251)","\u200b","\u200b","2,251","\u200b","\u200b","471","\u200b"],["Contract termination and other expenses","\u200b","\u200b","25,099","\u200b","\u200b","\u2014","\u200b","\u200b","4,705","\u200b","\u200b","(4,705)","\u200b","\u200b","25,099","\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]]

​

55

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","\u200b","\u200b","Amount of","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Year Ended December 31,","\u200b","Increase","\u200b","Percent","\u200b","\u200b"],["\u200b","","2021","","2022","","(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","826","\u200b","\u200b","798","\u200b","\u200b","(28)","\u200b","(3)","%","\u200b"],["C2 Ethane (MBbl)","\u200b","\u200b","17,262","\u200b","\u200b","18,818","\u200b","\u200b","1,556","\u200b","9","%","\u200b"],["C3+ NGLs (MBbl)","\u200b","\u200b","40,496","\u200b","\u200b","39,914","\u200b","\u200b","(582)","\u200b","(1)","%","\u200b"],["Oil (MBbl)","\u200b","\u200b","3,521","\u200b","\u200b","3,223","\u200b","\u200b","(298)","\u200b","(8)","%","\u200b"],["Combined (Bcfe)","\u200b","\u200b","1,194","\u200b","\u200b","1,170","\u200b","\u200b","(24)","\u200b","(2)","%","\u200b"],["Daily combined production (MMcfe/d)","\u200b","\u200b","3,271","\u200b","\u200b","3,204","\u200b","\u200b","(67)","\u200b","(2)","%","\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) (4)","\u200b","$","4.17","\u200b","\u200b","6.92","\u200b","\u200b","2.75","\u200b","66","%","\u200b"],["C2 Ethane (per Bbl) (5)","\u200b","$","11.99","\u200b","\u200b","20.41","\u200b","\u200b","8.42","\u200b","70","%","\u200b"],["C3+ NGLs (per Bbl)","\u200b","$","47.92","\u200b","\u200b","52.98","\u200b","\u200b","5.06","\u200b","11","%","\u200b"],["Oil (per Bbl)","\u200b","$","57.15","\u200b","\u200b","85.53","\u200b","\u200b","28.38","\u200b","50","%","\u200b"],["Weighted Average Combined (per Mcfe)","\u200b","$","4.85","\u200b","\u200b","7.09","\u200b","\u200b","2.24","\u200b","46","%","\u200b"],["Average realized prices after effects of derivative settlements (3):","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Natural gas (per Mcf)","\u200b","$","3.08","\u200b","\u200b","4.54","\u200b","\u200b","1.46","\u200b","47","%","\u200b"],["C2 Ethane (per Bbl)","\u200b","$","11.81","\u200b","\u200b","20.38","\u200b","\u200b","8.57","\u200b","73","%","\u200b"],["C3+ NGLs (per Bbl)","\u200b","$","41.32","\u200b","\u200b","52.63","\u200b","\u200b","11.31","\u200b","27","%","\u200b"],["Oil (per Bbl)","\u200b","$","52.80","\u200b","\u200b","84.88","\u200b","\u200b","32.08","\u200b","61","%","\u200b"],["Weighted Average Combined (per Mcfe)","\u200b","$","3.88","\u200b","\u200b","5.46","\u200b","\u200b","1.58","\u200b","41","%","\u200b"],["Average costs (per Mcfe):","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Lease operating","\u200b","$","0.08","\u200b","\u200b","0.09","\u200b","\u200b","0.01","\u200b","13","%","\u200b"],["Gathering and compression","\u200b","$","0.73","\u200b","\u200b","0.76","\u200b","\u200b","0.03","\u200b","4","%","\u200b"],["Processing","\u200b","$","0.66","\u200b","\u200b","0.74","\u200b","\u200b","0.08","\u200b","12","%","\u200b"],["Transportation","\u200b","$","0.70","\u200b","\u200b","0.72","\u200b","\u200b","0.02","\u200b","3","%","\u200b"],["Production and ad valorem taxes","\u200b","$","0.17","\u200b","\u200b","0.25","\u200b","\u200b","0.08","\u200b","47","%","\u200b"],["Marketing expense, net","\u200b","$","0.08","\u200b","\u200b","0.10","\u200b","\u200b","0.02","\u200b","25","%","\u200b"],["Depletion, depreciation, amortization and accretion","\u200b","$","0.62","\u200b","\u200b","0.59","\u200b","\u200b","(0.03)","\u200b","(5)","%","\u200b"],["General and administrative (excluding equity-based compensation)","\u200b","$","0.10","\u200b","\u200b","0.12","\u200b","\u200b","0.02","\u200b","20","%","\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 2021), 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 year ended December 31, 2021 includes $85 million of net litigation proceeds related to a favorable litigation judgment. See Note 15\u2014Contingencies to the 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 $4.06 per Mcf."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(5)","The average realized price for the year ended December 31, 2022 includes $10 million of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane would have been $19.88 per Bbl."]]
[[/GREPCENT_TABLE]]

Natural gas sales. Revenues from sales of natural gas increased from $3.4 billion, which included litigation proceeds of $85 million, for the year ended December 31, 2021 to $5.5 billion for the year ended December 31, 2022, an increase of $2.1 billion, or 60%. See Note 15—Contingencies to the consolidated financial statements for more information on the litigation proceeds. Excluding the litigation proceeds, higher commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2022 accounted for an approximate $2.3 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 $118 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 $2.1 billion for the year ended December 31, 2021 to $2.5 billion for the year ended December 31, 2022, an increase of $351 million, or 16%. Higher commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2022 accounted for an approximate $360 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

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production volumes during the year ended December 31, 2022 accounted for an approximate $9 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 sale of oil increased from $201 million for the year ended December 31, 2021 to $276 million for the year ended December 31, 2022, an increase of $75 million, or 37%. Higher oil prices for the year ended December 31, 2022 excluding the effects of derivative settlements) accounted for an approximate $92 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 year ended December 31, 2022 accounted for an approximate $17 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. Our commodity derivatives include variable price swap contracts, swaptions, basis swap contracts, call options and embedded put options. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations. For the years ended December 31, 2021 and 2022, our commodity hedges resulted in derivative fair value losses of $1.9 billion and $1.6 billion, respectively. For the year ended December 31, 2021, commodity derivative fair value losses included $1.2 billion of net cash payments for settled derivative losses, as well as $5 million for payments on derivatives that were settled prior to their contractual settlement dates. For the year ended December 31, 2022, commodity derivative fair value losses included $1.9 billion of net cash payments for settled 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. Additionally, substantially all of our production is currently unhedged for 2023 and beyond after giving effect to the early termination of our swaption in January 2023, which limits our exposure to volatility in the fair value of our derivative instruments in the future. See “—Capital Resources and Liquidity—Overview” for more information.

Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP decreased from $45 million for the year ended December 31, 2021 to $38 million for the year ended December 31, 2022 , a decrease of $7 million or 17%, due to lower production volumes between periods. Under the terms of the agreement, the production volumes are delivered at approximately $1.61 per MMBtu over the contractual term. See Note 3—Transactions to the consolidated financial statements for more information on this transaction.

Lease operating expense. Lease operating expense increased from $97 million, or $0.08 per Mcfe, for the year ended December 31, 2021 to $100 million, or $0.09 per Mcfe, for the year ended December 31, 2022, an increase of $3 million or $0.01 per Mcfe, primarily due to higher oilfield service and produced water handling costs.

Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense increased from $2.5 billion for the year ended December 31, 2021 to $2.6 billion for the year ended December 31, 2022, an increase of $106 million or 4%. This fluctuation primarily resulted from the following:

[[GREPCENT_TABLE]]
[["","\u25cf","Gathering and compression costs increased from $0.73 per Mcfe for the year ended December 31, 2021 to $0.76 per Mcfe for the year ended December 31, 2022, primarily due to increased compressor fuel costs as a result of higher commodity prices and an annual CPI-based adjustment between periods, partially offset by $48 million in incentive fee rebates from Antero Midstream earned during the year ended December 31, 2022 compared to $12 million in incentive fee rebates from Antero Midstream earned during the year ended December 31, 2021."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","Processing costs increased from $0.66 per Mcfe for the year ended December 31, 2021 to $0.74 per Mcfe for the year ended December 31, 2022, primarily due to increased costs for (i) ethane transportation, (ii) NGL processing, which includes an annual CPI-based adjustment in 2022, and (iii) electricity, primarily as a result of higher commodity prices, as well as increased NGL production volumes between periods."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","Transportation costs increased from $0.70 per Mcfe for the year ended December 31, 2021 to $0.72 per Mcfe and for the year ended December 31, 2022, primarily due to higher fuel costs as a result of higher commodity prices and demand fees between periods."]]
[[/GREPCENT_TABLE]]

Production and ad valorem tax expense. Total production and ad valorem taxes increased from $198 million for the year ended December 31, 2021 to $287 million for the year ended December 31, 2022, an increase of $89 million or 45%, primarily due to higher commodity prices between periods. Production and ad valorem taxes as a percentage of natural gas revenues remained relatively consistent at 5.7% and 5.2% for the years ended December 31, 2021 and 2022, respectively.

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General and administrative expense. General and administrative expense (excluding equity-based compensation expense) increased from $125 million for the year ended December 31, 2021 to $137 million for the year ended December 31, 2022, an increase of $12 million or 10%, primarily due to higher salary and wage expense, professional service fees, office operating costs and software license costs between periods. We had 519 and 586 employees as of December 31, 2021 and 2022, respectively. This higher general and administrative expense, excluding equity-based compensation together with lower production volumes between periods resulted in an increase in per unit costs from $0.10 per Mcfe during the year ended December 31, 2021 to $0.12 per Mcfe during the year ended December 31, 2022.

Equity-based compensation expense. Equity-based compensation expense increased from $20 million for the year ended December 31, 2021 to $35 million for the year ended December 31, 2022, an increase of $15 million or 73%, primarily due to an increase in the annual equity awards granted during the second quarter of 2022 as compared to prior years, which were temporarily and significantly reduced during 2020 and supplemented by our cash awards program. Our equity awards vest over three or four year service periods, and our equity incentive program began returning to normal levels in 2021. See Note 9—Equity-Based Compensation and Cash Awards to the consolidated financial statements for more information.

Depletion, depreciation and amortization expense. DD&A expense decreased from $742 million, or $0.62 per Mcfe for the year ended December 31, 2021 to $681 million, or $0.59 per Mcfe for the year ended December 31, 2022, a decrease of $61 million, or $0.03 per Mcfe, primarily as a result of increased proved reserve volumes due to higher commodity prices and lower production volumes between periods.

Impairment of property and equipment. Impairment of property and equipment increased from $91 million for the year ended December 31, 2021 to $150 million for the year ended December 31, 2022, an increase of $59 million, or 65%, primarily related to 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 expense. Contract termination expense increased from $4 million for the year ended December 31, 2021 to $25 million for the year ended December 31, 2022, an increase of $19 million primarily due to a $12 million payment for the cancellation of the Smithburg 2 gas processing plant and a $5 million payment for the cancellation of a gas gathering agreement during the year ended December 31, 2022.

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 $93 million, or $0.08 per Mcfe, for the year ended December 31, 2021 to $115 million, or $0.10 per Mcfe, for the year ended December 31, 2022, primarily due to higher marketing losses, partially offset by lower firm transportation commitments between periods.

Marketing revenue. Marketing revenue decreased from $719 million for the year ended December 31, 2021 to $417 million for the year ended December 31, 2022, a decrease of $302 million, or 42%, primarily due to lower marketing volumes between periods, partially offset by increased commodity prices between periods. Lower natural gas marketing volumes accounted for a $735 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 $416 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 $10 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 $18 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 $31 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 $26 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 $812 million for the year ended December 31, 2021 to $531 million for the year ended December 31, 2022, a decrease of $281 million, or 35%. 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 $254 million, which was partially offset by increased oil and NGL purchases of approximately $29 million and $3 million, respectively, between periods. The total costs decreased primarily due to lower

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marketing volumes between periods, partially offset by increased commodity prices. Firm transportation costs were $208 million for the year ended December 31, 2021 and $149 million for the year ended December 31, 2022, a decrease of $59 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 increased from $898 million for the year ended December 31, 2021 to $920 million for the year ended December 31, 2022, an increase of $22 million, or 2%. primarily due to increased throughput, fresh water delivery volumes and other fluid handling volumes between periods as well as higher low pressure, compression, high pressure and water handling fees as a result of an annual CPI-based adjustments, partially offset by higher low pressure gathering fee rebates earned by us between periods.

Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $343 million for the year ended December 31, 2021 to $381 million for the year ended December 31, 2022 primarily due to increased direct operating costs and depreciation expense between periods. Direct operating costs increased between periods primarily as a result of higher throughput volumes, 12 acquired compressor stations coming online in 2022, higher chemical, fuel, labor and heavy maintenance expense and higher fresh water deliveries to us in the Utica Shale. The increase in depreciation expense is primarily a result of a phased early retirement of an underutilized compressor station, which allows Antero Midstream to relocate and reuse the compressor units and equipment to (i) expand an existing compressor station and/or (ii) contribute to a new compressor station. There are certain costs associated with the underutilized compressor station that cannot be relocated or reused, and such costs will be fully depreciated during the first half of 2023.

Items Not Allocated to Segments

Interest expense. Interest expense decreased from $182 million for the year ended December 31, 2021 to $125 million for the year ended December 31, 2022, a decrease of $57 million, or 31%, primarily due to a $1.0 billion reduction in the principal amount of our senior unsecured notes debt as a result of our debt repurchase program and lower borrowings on our Credit Facility between periods, partially offset by decreased interest income and increased interest rates on our Credit Facility due to higher benchmark rates.

Loss on early extinguishment of debt. During the year ended December 31, 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 $62 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 year ended December 31, 2021, we redeemed or repurchased through open market transactions (i) the remaining balance of $661 million of our 5.125% senior notes due December 1, 2022 at par, plus accrued and unpaid interest; (ii) the remaining balance of $574 million of our 5.625% senior notes due June 1, 2023 at par, plus accrued and unpaid interest; (iii) $5 million aggregate principal amount of our 2025 Notes at a weighted average redemption price of 102% of the principal amount thereof, plus accrued and unpaid interest, (iv) $175 million of our 2026 Notes at a redemption price of 108.375% of par, plus accrued and unpaid interest; and (v) $116 million of our 2029 Notes at a redemption price of 107.625% of par, plus accrued and unpaid interest. For such redemptions and repurchases, we recognized a $31 million 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. See Note 7—Long-Term Debt to the consolidated financial statements for more information.

​

Loss on convertible note inducement and equitization. During the year ended December 31, 2021, we recognized a loss of $51 million for the January Equitization Transactions and the May Equitization Transactions, which represents the consideration paid in excess of the original terms of the 2026 Convertible Notes. During the year ended December 31, 2022, we recognized a $0.2 million loss for the inducement of $5 million in aggregate principal amount of the 2026 Convertible Notes. See Note 7—Long-Term Debt to the consolidated financial statements for more information.

Income tax benefit (expense). For the year ended December 31, 2021, we had an income tax benefit of $74 million, with an effective tax rate of 32%, due to a loss before income taxes of $228 million. For the year ended December 31, 2022, we had income tax expense of $449 million, with an effective tax rate of 18%, due to income before income taxes of $2.5 billion. For years ended December 31, 2021 and 2022, our overall 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

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13—Income Taxes to our consolidated financial statements more for information.

As of December 31, 2021 and 2022, we had U.S. federal and state NOL carryforwards of $2.3 billion and $1.0 billion, respectively. Many of these NOL carryforwards expire at various dates between 2024 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, 2020 Compared to Year Ended December 31, 2021

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, 2021 for a discussion of the results of operations for the year ended December 31, 2020 compared to the year ended December 31, 2021.

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 $1.5 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 2023. 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 past levels, the percentage of our expected production that we hedge has decreased. For the years ended December 31, 2021 and 2022, approximately 70% and 33%, respectively, of our production was hedged through fixed price commodity swaps. Assuming our 2023 production is the same as our production in 2022, approximately 1% of our production for 2023 will be hedged through fixed price commodity swaps. 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 15 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.

2022 Capital Spending and 2023 Capital Budget

For the year ended December 31, 2022, our total consolidated capital expenditures were approximately $986 million, including drilling and completion expenditures of $821 million, leasehold additions of $150 million and other capital expenditures of $15 million. Our net capital budget for 2023 is $1.025 billion to $1.075 billion. Our budget includes: a range of $875 million to $925 million for drilling and completion and $150 million for leasehold expenditures. We do not budget for acquisitions. During 2023, we plan to complete 60 to 65 net horizontal wells in the Appalachian Basin. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices.

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, 2022, 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

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obligations, capital expenditures, and commitments and contingencies for at least the next 12 months. For more information on our outstanding indebtedness, see “—Debt Agreements.”

As of December 31, 2022, we did not have any off-balance sheet arrangements other than contractual commitments for firm transportation, gas processing and fractionation, gathering and compression services and land payment obligations.

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","2021","","2022"],["Net cash provided by operating activities","\u200b","$","1,660,116","\u200b","\u200b","3,051,342","\u200b"],["Net cash used in investing activities","\u200b","\u200b","(710,784)","\u200b","\u200b","(943,612)","\u200b"],["Net cash used in financing activities","\u200b","\u200b","(949,332)","\u200b","\u200b","(2,107,730)","\u200b"],["Net increase in cash and cash equivalents","\u200b","$","\u2014","\u200b","\u200b","\u2014","\u200b"]]
[[/GREPCENT_TABLE]]

​

Year Ended December 31, 2021 Compared to Year Ended December 31, 2022

Operating Activities. Net cash provided by operating activities was $1.7 billion and $3.1 billion for the years ended December 31, 2021 and 2022, respectively. Net cash provided by operating activities increased primarily due to increases in commodity prices both before and after the effects of settled commodity derivatives, partially offset by decreased production and increased ad valorem taxes, gathering, compression, processing and transportation expenses, general and administrative expenses and losses on marketing activities between periods.

Our net operating cash flows are sensitive to many variables, the most significant of which is the volatility of natural gas, NGL 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. 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 $711 million for the year ended December 31, 2021 to $944 million for the year ended December 31, 2022, primarily due to an increase in capital expenditures of $228 million between periods. Total additions to unproved properties and drilling and completion costs increased from $680 million during the year ended December 31, 2021 to $930 million during the year ended December 31, 2022 primarily due to increased service cost inflation, drilling and completion activity and leasing activity between periods.

Financing Activities. Net cash flows used in financing activities increased from $949 million for the year ended December 31, 2020 to $2.1 billion for the year ended December 31, 2022. During the year ended December 31, 2021, we issued $500 million aggregate principal amount of 2026 Notes, $700 million aggregate principal amount of 2029 Notes and $600 million aggregate principal amount of 2030 Notes (net of $31 million of aggregate debt issuance costs), of which proceeds were used to (i) redeem $661 million aggregate principal amount of our 5.125% senior notes due December 1, 2022, which were fully retired, (ii) redeem $574 million aggregate principal amount of our 5.625% senior notes due June 1, 2023, which were fully retired, (iii) repurchase $5 million aggregate principal amount of our 2025 Notes, (iv) redeem $175 million aggregate principal amount of our 2026 Notes, (v) redeem $116 million aggregate principal of our 2029 Notes and (vi) repay all outstanding borrowings on our Credit Facility. Also, during the year ended December 31, 2021, we completed the January Share Offering and the May Share Offering and used the proceeds and approximately $89 million of borrowings under the senior secured revolving credit facility agreement in effect prior to October 26, 2021 to repurchase $206 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions. Additionally, during the year ended December 31, 2021, we received a $51 million payment from Martica and distributed $97 million to the noncontrolling interests in Martica. See Note 3—Transactions and Note 7—Long-Term Debt for more information on these transactions, respectively.

During the year ended December 31, 2022, we (i) redeemed $585 million aggregate principal amount of our 2025 Notes and repurchased $228 million of our 2026 Notes and $177 million of our 2029 Notes, (ii) repurchased 25 million shares of our common stock at a total cost of approximately $874 million, (iii) distributed $174 million to the noncontrolling interests in Martica and (iv) paid $66 million in employee withholding taxes for vested equity-based awards. Additionally, we borrowed $35 million, net, on our Credit Facility during the year ended December 31, 2022.

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Year Ended December 31, 2020 Compared to Year Ended December 31, 2021

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, 2021 for a discussion of the cash flows for the year ended December 31, 2020 compared to the year ended December 31, 2021.

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, 2022, the borrowing base was $3.5 billion and lender commitments were $1.5 billion. The next redetermination of the borrowing base is scheduled to occur in April 2023. 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, 2022, we had an outstanding balance under the Credit Facility of $35 million and outstanding letters of credit of $504 million.

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, 2021 and 2022, 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.

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Senior Unsecured Notes

The following table summarizes certain material terms of our senior unsecured notes and convertible notes outstanding as of December 31, 2022:

[[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","$","600,000","\u200b","$","56,932","\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 prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved could be material. During the year ended December 31, 2022, we repurchased or redeemed $1.0 billion aggregate principal amount of our senior unsecured notes, including all of our 2025 Notes and portions of our 2026 Notes and 2029 Notes. In addition, $25 million aggregate principal amount of our 2026 Convertible Notes were converted into approximately 6 million shares of common stock during the year ended December 31, 2022.

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, 2021 and 2022.

Critical Accounting Policies and 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. 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 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 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 below. We believe these accounting policies reflect our more significant estimates and assumptions used in the preparation of our consolidated financial statements. See Note 2—Summary of Significant Accounting Policies to the consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

Successful Efforts Method

The Company accounts for its 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 undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. 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 are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when we determine that the well does not contain reserves in commercially viable quantities. The Company reviews exploration costs related to wells in progress at the end of each quarter and makes a determination, based on known

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results of drilling at that time, whether the costs should continue to be capitalized pending further well testing and results, or charged to expense. We have not incurred any such charges in the years ended December 31, 2020, 2021 and 2022. The sale of a partial interest in a proved property is accounted for as a normal retirement, and no gain or loss is recognized as long as this treatment does not significantly affect the units of production amortization rate. A gain or loss is recognized for all other sales of producing properties.

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. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed to, the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognition of any gain or loss until the cost has been recovered. Impairment of oil and gas properties related to unproved properties for leases that have expired, or are expected to expire, was $224 million, $91 million and $98 million for the years ended December 31, 2020, 2021 and 2022, respectively.

The successful efforts method of accounting can have a significant impact on our operational results when we are entering a new exploratory area in anticipation of finding a gas and oil field that will be the focus of future development drilling activities. The initial exploratory wells may be unsuccessful and would be expensed if reserves are not found in economic quantities. Seismic costs can be substantial, which will result in additional exploration expenses when incurred. Additionally, the application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred.

Natural Gas, NGLs and Oil Reserve Quantities and Standardized Measure of Future Cash Flows

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. Current accounting guidance allows only proved natural gas, NGLs and oil reserves to be included in our financial statement disclosures. 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 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 field. 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. Any significant revisions could affect the future amortization rates of capitalized 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.  Under GAAP for successful efforts accounting, if the carrying amount exceeds the estimated undiscounted future net cash flows (measured using futures prices at the end of a quarter), we further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeded the estimated fair value of the properties. We did not record any impairments for proved properties during the years ended December 31, 2020, 2021 and 2022.

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 30% and 40%, respectively, from year-end 2022 levels before further evaluation of those properties would be required in order to determine if an impairment charge would be necessary under GAAP. If future prices decline from December 31, 2022, 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

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market.

Fair Value Measurement

The FASB ASC Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and sets forth disclosure requirements about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., the initial recognition of asset retirement obligations and impairments of long-lived assets). The fair value is the price that we estimate would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize inputs to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly.

In order to manage our exposure to natural gas, NGLs and oil price volatility, we enter into derivative transactions from time to time, which may include commodity swap agreements, basis swap agreements, collar agreements and other similar agreements related to the price risk associated with our production. To the extent legal right of offset exists with a counterparty, we report derivative assets and liabilities on a net basis. We record derivative instruments on the consolidated balance sheets as either assets or liabilities measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives, including gains or losses on settled derivatives, are classified as revenues on our consolidated statements of operations. The fair value of derivative instruments was determined using Level 2 inputs. Our derivatives have not been designated as hedges for accounting purposes.

We account for our investment in Antero Midstream under the equity method of accounting. We evaluate our equity method investment for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the fair value of the investment to the carrying value of the investment to determine whether potential impairment has occurred. If the fair value is less than the carrying value and management considers the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the financial statements as an impairment loss. See Note 5—Equity-Method Investment to the consolidated financial statements for further discussion on our equity method investments.

As of March 31, 2020, we determined that events and circumstances indicated that the carrying value had experienced an other-than-temporary decline and we recorded impairment expense of $611 million. The fair value of the equity method investment in Antero Midstream was based on the quoted market common stock price of Antero Midstream as of March 31, 2020 (Level 1). There were no impairments of the equity method investment in Antero Midstream during the years ended December 31, 2021 and 2022.

Income Taxes

Income taxes are accounted for using the asset and liability approach. Under this approach, deferred 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 tax liabilities exceed our deferred tax assets. We record a deferred income tax benefit to the extent our deferred tax assets exceed our deferred 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 tax assets will not be realized. In assessing the realizability of our deferred tax assets, management considers whether some portion or all of the deferred tax assets will be realized based on a more-likely-than-not standard of judgment. The ultimate realization of deferred tax assets is dependent upon our ability to generate future taxable income during the periods in which our deferred tax assets are deductible. Management considers the scheduled reversal of deferred 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 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, 2022, we have recognized a valuation allowance of $57 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.

The calculation of deferred tax assets and liabilities involves uncertainties in the application of complex tax laws and

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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.

New Accounting Pronouncements

See Note 2—Summary of Significant Accounting Policies to our consolidated financial statements for information on new accounting pronouncements.