What changed in this filing

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Item 7. Management’s Discussion and Analysis

2023-02-15 compared with 2022-02-16 · 273 added, 267 removed, 360 unchanged (60% of the section changed)

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All of our operations are conducted in the United States.

COVID-19 Pandemic

Since the start of the COVID-19 pandemic, governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, among other actions, which caused a significant decrease in activity in the global economy and the demand for oil, and to a lesser extent, natural gas and NGLs.

As vaccines have become widely available, social distancing guidelines, travel restrictions and stay-at-home orders have eased, activity in the global economy has increased and demand for oil, natural gas and NGLs and related commodity pricing, has improved.

However, new variants of the virus could cause further commodity market volatility and resulting financial market instability, and these are variables beyond our control that may adversely impact our generation of funds from operating cash flows, distributions from unconsolidated affiliates, available borrowings under our Credit Facility and our ability to access the capital markets.

As a producer of natural gas, NGLs and oil, we are recognized as an essential business under various federal, state and local regulations related to the COVID-19 pandemic.

As such, we have continued to operate throughout the pandemic as permitted under

these regulations while taking steps to protect the health and safety of our workers.

We have implemented protocols to reduce the risk of an outbreak within our field operations and corporate offices, and these protocols have not reduced Antero Resources’ production and our throughput in a significant manner.

A substantial portion of our non-field level employees currently operate in remote work from home arrangements, and we have been able to maintain a consistent level of effectiveness through these arrangements, including maintaining our day-to-day operations, our financial reporting systems and our internal control over financial reporting.

We continue to monitor the COVID-19 environment in order to (i) protect the health and safety of our employees and contract workers and (ii) to determine when a return to in-office working arrangements will be appropriate .

Our supply chain has not experienced any significant interruptions as a result of the COVID-19 pandemic.

The lack of a market or available storage for any one NGL product or oil could result in our having to delay or discontinue well completions and commercial production or shut in production for other products because we cannot curtail the production of individual products in a meaningful way without reducing production of other products.

Potential impacts of these constraints may include partial shut-in of production, although we are not able to determine the extent of shut-ins or for how long they may last.

However, because some of our wells produce rich gas, which is processed, and some produce dry gas, which does not require processing, we can change the mix of products that we produce and wells that we complete to adjust our production to address takeaway capacity constraints for certain products.

For example, we can shut-in rich gas wells and still produce from our dry gas wells if processing or storage capacity of NGL products becomes limited or constrained.

Prior to the COVID-19 pandemic, we had developed a diverse set of buyers and destinations, as well as in-field and off-site storage capacity for our condensate volumes.

As a result of the pandemic, we have expanded our customer base and our condensate storage capacity within the Appalachian Basin.

Our natural gas, NGLs and oil producing properties are located in the liquids-rich Appalachian Basin.

We maintain an active hedging program designed to mitigate volatility in commodity prices and to protect certain of our expected future cash flows for our future operations and capital spending plans.

All of our hedges are financial hedges and do not have physical delivery requirements.

As such, any decreases in anticipated production, such as a result of decreased development activity, would not impact our ability to realize the benefits of or reduce the obligations for our hedges.

For the year ending December 31, 2022, we have hedged through fixed price contracts the sale of 422 Bcf of natural gas at a weighted average price of $2.50 per MMBtu, a swaption agreement for 156 Bcf of natural gas production at a weighted average index price of $2.77 per MMBtu and basis swaps for 22 Bcf with a weighted average pricing differential of $0.515 per MMBtu.

In addition, our borrowing capacity is directly impacted by the amount of financial assurance that we are required to provide in the form of letters of credit to third parties, primarily pipeline capacity providers.

The amount of financial assurance we provided has not increased during the COVID-19 pandemic and, thus far, we have not experienced any losses due to counterparty risk.

However, our ability to limit any additional financial assurance we are required to provide, as well as to protect ourselves from the counterparty risk of our financial hedges, may be limited in the future.

Since the onset of the COVID-19 pandemic, we have timely serviced our debt and other obligations.

On October 26, 2021, we entered into the New Credit Facility with a borrowing base of $3.5 billion and lender commitments of $1.5 billion.

Lender commitments were reduced by $1.1 billion from the previous commitments of $2.64 billion to better align with our expected future liquidity needs.

As of December 31, 2021, we had no borrowings under our New Credit Facility and had outstanding letters of credit of $531 million .

We have not materially modified the terms of any other agreements.

See Note 8—Long-Term Debt to the consolidated financial statements and “—Capital Resources and Liquidity—Debt Agreements—Credit Facility.”

As the global economy continues to recover from the effects of the COVID-19 pandemic, economic indicators have continued to strengthen.

However, the economy has begun to experience elevated inflation levels as a result of global supply and demand imbalances resulting from the COVID-19 pandemic.

For example, the United States Bureau of Labor and Statistics (“BLS”) consumer price index for all urban consumers increased 7% from December 31, 2020 to December 31, 2021 as compared to the average historical 10-year rate of 2%.

Additionally, employment activity has also begun to strengthen as demonstrated by the United States BLS unemployment rate declining from a high of 15% in April 2020 to 4% in December 2021.

Inflationary pressures and labor shortages could result in increases to our operating and capital costs that are not fixed, renegotiation of contracts and/or supply agreements and higher labor costs, among others.

T hese economic variables are beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.

Recent Developments and Highlights

Credit Facility

On October 26, 2021, we entered into an amended and restated senior secured revolving credit facility, the New Credit Facility with a borrowing base of $3.5 billion and lender commitments of $1.5 billion and matures on the earlier of (i) October 26,

2026 or (ii) the day that is 180 days prior to the earliest stated redemption date of any series of our then outstanding senior notes.

Lender commitments were reduced by $1.1 billion from the previous commitments of $2.64 billion to better align with our expected future liquidity needs.

See Note 8—Long-Term Debt to the consolidated financial statements and “—Capital Resources and Liquidity—Debt Agreements—Credit Facility” for more information.

Issuance of Senior Notes

On January 4, 2021, we issued $500 million of 8.375% senior notes due July 15, 2026 (the “2026 Notes”) at par.

On January 26, 2021, we issued $700 million of 7.625% senior notes due February 1, 2029 (the “2029 Notes”) at par.

The 2026 Notes and 2029 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility.

The 2026 Notes and 2029 Notes rank pari passu to our other outstanding senior notes.

The 2026 Notes and 2029 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by our wholly owned subsidiaries and certain of our future restricted subsidiaries.

See “—Debt Agreements—Senior Unsecured Notes” below and Note 8—Long-Term Debt to the consolidated financial statements for more information.

Financing Highlights

Debt Repurchase Program

We fully redeemed all of our outstanding 5.125% senior notes due December 1, 2022 (the “2022 Notes”) at par, plus accrued and unpaid interest in the first quarter of 2021.

During the second quarter of 2021, we fully redeemed all of our outstanding 5.625% senior notes due June 1, 2023 (the “2023 Notes”) at par, plus accrued and unpaid interest.

On July 1, 2021, we redeemed $175 million of the principal amount of our 2026 Notes at a redemption price of 108.375% of the principal amount thereof, plus accrued and unpaid interest.

Immediately following the redemption, there were $325 million aggregate principal amount of 2026 Notes outstanding.

On November 2, 2021, we redeemed $116 million of the principal amount of our 2029 Notes at a redemption price of 107.625% of the principal amount thereof, plus accrued and unpaid interest.

Immediately following the redemption, there were $584 million aggregate principal amount of 2029 Notes outstanding.

On January 27, 2022, we announced that we will redeem all $585 million of the aggregate principal amount of our 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 on March 1, 2022.

Immediately following the redemption, the 2025 Notes will be fully retired.

The $7 million premium to the principal amount to be redeemed, along with the write-off of unamortized debt issuance costs, will be included in our loss on early debt extinguishment during the first quarter of 2022.

Convertible Notes Equitizations

On January 12, 2021, we completed a registered direct offering (the “January Share Offering”) of an aggregate of 31.4 million shares of our common stock at a price of $6.35 per share to certain holders of our 4.25% convertible senior notes due 2026 (the “2026 Convertible Notes”).

We used the proceeds from the January Share Offering and approximately $63 million of borrowings under the Prior Credit Facility to repurchase from such holders $150 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions (the “January Convertible Note Repurchase,” and, collectively with the January Share Offering, the “January Equitization Transactions”).

On May 13, 2021, we completed a registered direct offering (the “May Share Offering”) of an aggregate of 11.6 million shares of our common stock at a price of $11.01 per share to certain holders of our 2026 Convertible Notes.

We used the proceeds from the May Share Offering and approximately $26 million of borrowings under the Prior Credit Facility to repurchase from such holders $56 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions (the “May Convertible Note Repurchase,” and, collectively with the May Share Offering, the “May Equitization Transactions”).

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.

Capital Return Program

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.

The exact number of shares to be repurchased by us is not guaranteed and the program may be suspended, modified or discontinued at any time without prior notice.

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

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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 each subsequent year through 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.

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% of development capital for wells spud in 2021 and (i) is expected to fund 15% of development capital for wells spud in 2022 and (ii) between 15% and 20% of development capital for wells spud in each of 2023 and 2024, which funding amounts represent QL’s proportionate working interest in such wells.

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.

If we present a capital budget for an annual tranche with an estimated IRR equal to or exceeding a specified return that QL in good faith believes is less than such specified return and QL elects not to participate, we will not be obligated to offer QL the opportunity to participate in subsequent annual tranches.

See Note 3—Transactions to the consolidated financial statements for more information.

Overriding Royalty Interest Additional Contributions

On June 15, 2020, we announced the consummation of a transaction with an affiliate of Sixth Street Partners, LLC (“Sixth Street”) relating to certain overriding royalty interests across our existing asset base (the “ORRIs”).

In connection with the transaction, we contributed the ORRIs to a newly formed subsidiary, Martica, and Sixth Street at the initial closing contributed $300 million in cash (subject to customary adjustments) and agreed to contribute up to an additional $102 million in cash if certain production thresholds attributable to the ORRIs were achieved in the third quarter of 2020 and first quarter of 2021.

All cash contributed by Sixth Street was distributed to us.

We met the applicable production thresholds related to the third quarter of 2020 and first quarter of 2021 as of September 31, 2020 and March 31, 2021, respectively.

We received a $51 million cash distribution during each of the years ended December 31, 2020 and 2021.

See Note 4—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.

The following table details the average benchmark natural gas and oil prices:

Year Ended December 31,

Henry Hub (1) ($/Mcf)

West Texas Intermediate (2) ($/Bbl)

(1) New York Mercantile Exchange first of month average natural gas price.

(2) Energy Information Administration calendar month average settled futures price.

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:

Commodity / Settlement Period

Contracted Volume

January-December 2023

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:

Weighted Average

Commodity / Settlement Period

Index to Basis Differential

Contracted Volume

Hedged Differential

January-December 2023

January-December 2024

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:

Commodity / Settlement Period

Contracted Volume

January-December 2023

January-December 2024

January-December 2025

January-December 2026

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.

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.

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:

Commodity / Settlement Period

Contracted Volume

January-December 2023

January-December 2024

January-March 2025

Natural Gasoline

January-December 2023

Mont Belvieu Natural Gasoline-OPIS Non-TET

January-December 2023

West Texas Intermediate

January-December 2024

West Texas Intermediate

January-March 2025

West Texas Intermediate

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

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

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● Commodity derivatives.

To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we utilize derivative instruments to hedge future sales prices on a significant portion of our production.

We enter into primarily fixed price natural gas, NGLs and oil swap 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.

At the end of each accounting period, we estimate the fair value of these swaps and, because we have not elected hedge accounting, we recognize changes in the fair value of these derivative

instruments in earnings.

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—Derivative 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.

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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.

● Gathering, compression, water handling and treatment revenues.

Gathering, compression, water handling and treatment revenues are derived from our ownership interest in Antero Midstream.

● Gathering, compression and water handling revenues.

Gathering, compression and water handling revenues are derived from our ownership interest in Antero Midstream.

Principal Components of Our Cost Structure

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These are the operating costs incurred to maintain our production.

Such costs include produced water hauling, water handling, water disposal, labor-related costs to monitor producing wells, maintenance, repairs and workover expenses.

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.

● Gathering, compression, processing and transportation.

These costs include the costs to purchase services from Antero Midstream and fees paid to other third parties who operate low- and high- pressure gathering systems that transport our gas.

They also include costs to process and extract NGLs from our produced gas and to transport our natural gas, NGLs and oil to market.

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.

● Water handling.

Water handling expenses relate to the direct operating costs attributable to fresh water and other fluid handling services.

● Production and ad valorem taxes.

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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 utilize this excess capacity as marketing expenses, because we market this excess capacity to third parties.

We also classify firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully

utilize this excess capacity as marketing expenses, because we market this excess capacity to third-parties.

We enter into long-term firm transportation agreements for a significant portion of our current and expected future production in order to secure capacity on major pipelines.

● Exploration expense.

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.

● Impairment of oil and gas properties.

● Exploration and mine expenses.

● 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 also record impairment charges for proved properties on a geological reservoir basis when events or changes in circumstances indicate that a property’s carrying amount may not be recoverable.

We record impairment charges for proved properties on a geological reservoir basis when events or changes in circumstances indicate that a property’s 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.

● Depletion, depreciation and amortization.

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● Interest expense.

We finance a portion of our capital expenditures, working capital requirements and acquisitions with borrowings under the Prior Credit Facility, which had a variable rate of interest based on LIBOR or the Alternate Base Rate and borrowings under the New Credit Facility, which has a variable rate of interest based on SOFR ( defined below in “ —Capital Resources and Liquidity—Debt Agreements—Credit Facility”) or the Alternate Base Rate.

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 “ —Capital Resources and Liquidity—Debt Agreements—Credit Facility”) 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, 2021, we had fixed interest rates of (i) 5.00% on our 2025 Notes having a principal balance of $585 million, (ii) 8.375% on our 2026 Notes having a principal balance of $325 million, (iii) 7.625% on our 2029 Notes having a principal balance of $584 million, (iv) 5.375% on our 2030 Notes having a principal balance of $600 million and (v) 4.25% on our 2026 Convertible Notes having a principal balance of $82 million.

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—Long-Term Debt to the consolidated financial statements for more information.

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We are subject to state and U.S.

federal income taxes but are currently not in a cash tax paying position with respect to 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 U.S.

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 do pay some state income or franchise taxes where state income or franchise taxes are determined on a basis other than income.

We have recorded deferred income tax expense to the extent our deferred tax liabilities exceed our deferred tax assets.

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(i) the exploration, development and production of natural gas, NGLs and oil;

(ii) marketing and utilization of excess firm transportation capacity gathering and processing;

(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.

All intersegment transactions were eliminated upon consolidation, including revenues from water handling and treatment services provided by Antero Midstream , which we capitalized as proved property development costs.

See Note 18—Reportable Segments to the consolidated financial statements for disclosures on our reportable segments.

Revenues from Antero Midstream’s operations were primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream .

All intersegment transactions were eliminated upon consolidation, including revenues from water handling services provided by Antero Midstream , which we capitalized as proved property development costs.

Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity.

See Note 17—Reportable Segments to the consolidated financial statements for more information.

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

The operating results of our reportable segments were as follows for the years ended December 31, 2020 and 2021 (in thousands):

The operating results of our reportable segments were as follows (in thousands):

Year Ended December 31, 2021

Equity Method

Elimination of

Investment in

Transactions and

Elimination of

Unconsolidated

2 unchanged sentences

Natural gas liquids sales

Commodity derivative fair value gains

Gathering, compression, water handling and treatment

Commodity derivative fair value losses

Gathering, compression and water handling

Amortization of deferred revenue, VPP

5 unchanged sentences

Transportation

Water handling

Production and ad valorem taxes

Exploration and mine expenses

General and administrative (excluding equity-based compensation)

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Depletion, depreciation and amortization

Impairment of oil and gas properties

Impairment of midstream assets

Impairment of property and equipment

Accretion of asset retirement obligations

Contract termination and rig stacking and other expenses

Loss on sale of assets

Contract termination and other expenses

Loss (gain) on sale of assets

Total operating expenses

Operating loss

Equity in earnings (loss) of unconsolidated affiliates

Operating income (loss)

Equity in earnings of unconsolidated affiliates

Year Ended December 31, 2022

Equity Method

Elimination of

Investment in

Transactions and

Elimination of

Unconsolidated

3 unchanged sentences

Commodity derivative fair value losses

Gathering, compression, water handling and treatment

Gathering, compression and water handling

Amortization of deferred revenue, VPP

5 unchanged sentences

Transportation

Water handling

Production and ad valorem taxes

Exploration and mine expenses

General and administrative (excluding equity-based compensation)

1 unchanged sentence

Depletion, depreciation and amortization

Impairment of oil and gas properties

Impairment of property and equipment

Accretion of asset retirement obligations

Contract termination and rig stacking and other expenses

Gain on sale of assets

Loss (gain) on sale of assets

Contract termination and other expenses

Total operating expenses

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Equity in earnings of unconsolidated affiliates

Exploration and Production Segment Results for the Year Ended December 31, 2020 Compared to the Year Ended December 31, 2021

The following table sets forth selected operating data of the exploration and production segment for the year ended December 31, 2020 compared to the year ended December 31, 2021:

Exploration and Production Segment

The following table sets forth selected operating data of the exploration and production segment:

Year Ended December 31,

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(3) Average prices reflect the before and after effects of our settled commodity derivatives.

Our calculation of such after effects includes gains on settlements of commodity derivatives (but does not include proceeds from the derivative monetizations in 2020 and 2021), which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes.

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.

(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.

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Excluding the effect of the litigation proceeds received, the average realized price for natural gas would have been $4.06 per Mcf.

(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.

Natural gas sales .

Revenues from sales of natural gas increased from $1.8 billion for the year ended December 31, 2020 to $3.4 billion, which included net litigation proceeds of $85 million, for the year ended December 31, 2021, an increase of $1.6 billion, or 90%.

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 net litigation proceeds, lower natural gas production volumes during the year ended December 31, 2021 accounted for an approximate $101 million decrease in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price excluding the net proceeds from the litigation), and increases in commodity prices (excluding the effects of derivative settlements) accounted for an approximate $1.6 billion increase in year-over-year gas sales revenue (calculated as the change in the year-to-year average price excluding the net proceeds from the litigation times current year production volumes).

Revenues from sales of NGLs increased from $1.2 billion for the year ended December 31, 2020 to $2.1 billion for the year ended December 31, 2021, an increase of $0.9 billion, or 85%.

Lower NGLs production volumes during the year ended December 31, 2021 accounted for an approximate $0.2 billion decrease in year-over-year NGL revenues (calculated as the change in year-to-year volumes times the prior year average price), and increases in commodity prices, excluding the effects of derivative settlements, accounted for an approximate $1.1 billion increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

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).

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).

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).

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%.

Lower oil production volumes during the year ended December 31, 2021 accounted for a $23 million decrease in year-over-year oil sales revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our oil prices, excluding the effects of derivative settlements, accounted for an approximate $112 million increase in year-over-year oil sales revenues (calculated as the change in the year-to-year average price times current year production volumes).

Commodity derivative fair value gains (losses).

To achieve more predictable cash flows, and to reduce our exposure to price fluctuations, we enter into fixed for variable price swap contracts, swaptions, basis swap contracts and collar contracts when management believes that favorable future sales prices for our production can be secured.

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 year ended December 31, 2020, our commodity hedges resulted in derivative fair value gains of $80 million.

For the year ended December 31, 2021, our commodity hedges resulted in derivative fair value loss of $1.9 billion.

Commodity derivative fair value gains included $795 million of net cash proceeds for gains on settled derivatives for the year ended December 31, 2020 as well as cash proceeds of $9 million related to derivatives that were monetized prior to their contractual settlement dates.

For the year ended December 31, 2021, commodity derivative fair value losses included $1.2 billion of net cash payments on commodity derivative losses as well as $5 million for payments on derivatives that were settled prior to their contractual settlement dates.

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.

We expect continued volatility in commodity prices and the related fair value of our derivative instruments in the future.

Additionally, the percentage of our production that is currently hedged for 2022 and beyond is lower than historic levels.

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 increased from $15 million for the year ended December 31, 2020 to $45 million for the year ended December 31, 2021 as a result of the VPP closing in August 2020.

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.

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Lease operating expense .

Lease operating expense decreased from $99 million for the year ended December 31, 2020 to $97 million for the year ended December 31, 2021, a decrease of $2 million or 2% primarily due to lower production volumes.

On a per unit basis, lease operating expenses remained consistent at $0.08 per Mcfe for the years ended December 31, 2020 and 2021.

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 remained consistent at $2.5 billion for the years ended December 31, 2020 and 2021.

This is primarily a result of higher overall costs between periods, which were fully offset by lower production volumes between periods.

Gathering and compression costs increased from $0.64 per Mcfe for the year ended December 31, 2020 to $0.73 per Mcfe for the year ended December 31, 2021, primarily due to higher fuel costs as a result of increased natural gas prices and $48 million in incentive fee rebates from Antero Midstream Corporation earned during the year ended December 31, 2020 compared to $12 million in incentive fee rebates from Antero Midstream earned during the year ended December 31, 2021.

Processing costs decreased from $0.69 per Mcfe for the year ended December 31, 2020 to $0.66 per Mcfe for the year ended December 31, 2021, due to a decrease in C3+ NGL volumes as compared to total production volumes between periods, partially offset by increased NGL pipeline and terminaling fees from higher NGL volumes taken in-kind between periods.

Transportation costs increased from $0.60 per Mcfe for the year ended December 31, 2020 to $0.70 per Mcfe and for the year ended December 31, 2021, primarily due to increased utilization on higher tariff pipelines to the Midwest and Gulf Coast between periods.

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:

● 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.

● 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.

● 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.

Production and ad valorem tax expense.

Total production and ad valorem taxes increased from $107 million for the year ended December 31, 2020 to $198 million for the year ended December 31, 2021, an increase of $91 million or 85%, primarily due to higher commodity prices between periods and $5 million for the litigation proceeds.

On a per Mcfe basis, production and ad valorem

taxes increased from $0.08 per Mcfe for the year ended December 31, 2020 to $0.17 per Mcfe for the year ended December 31, 2021.

Production and ad valorem taxes as a percentage of natural gas revenues remained at 6% in each of the years ended December 31, 2020 and 2021.

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.

General and administrative expense.

General and administrative expense (excluding equity-based compensation expense) increased from $111 million for the year ended December 31, 2020 to $125 million for the year ended December 31, 2021, an increase of $14 million or 12%, primarily due to higher salary and wage expense between periods, which includes our annual incentive program that was temporarily and significantly reduced during 2020.

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.

On a per unit basis, general and administrative expense excluding equity-based compensation increased by 25%, from $0.08 per Mcfe during the year ended December 31, 2020 to $0.10 per Mcfe during the year ended December 31, 2021 as a result of higher overall costs and lower production volumes between periods.

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 decreased from $23 million for the year ended December 31, 2020 to $20 million for the year ended December, 2021, a decrease of $3 million or 12%, primarily due to equity award forfeitures partially offset by new awards granted to employees.

When an equity award is forfeited, expense previously recognized for the award is reversed.

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 $862 million for the year ended December 31, 2020 to $742 million for the year ended December 31, 2021, a decrease of $120 million or 14%.

DD&A per Mcfe decreased from $0.66 per Mcfe during the year ended December 31, 2020 to $0.62 per Mcfe during the year ended December 31, 2021 primarily due to increases in proved reserves as a result of higher commodity prices between periods.

Impairment of oil and gas properties .

Impairment of oil and gas properties decreased from $224 million for the year ended December 31, 2020 to $91 million for the year ended December 31, 2021, a decrease of $133 million, or 60%, primarily related to lower impairments of expiring leases between periods.

During both periods, we recognized impairments primarily related to expiring leases and initial costs related to pads we no longer plan to place into service .

Marketing Segment Results for the Year Ended December 31, 2020 Compared to the Year Ended December 31, 2021

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 decreased from $159 million, or $0.12 per Mcfe, for the year ended December 31, 2020 to $93 million, or $0.08 per Mcfe, for the year ended December 31, 2021.

The decrease was driven by higher marketing volumes, which mitigated some of our excess firm transportation expense, and the reduction of our firm transportation commitments between periods.

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 increased from $311 million for the year ended December 31, 2020 to $719 million for the year ended December 31, 2021, an increase of $408 million, or 131%, primarily due to increased commodity prices and marketing volumes between periods.

Higher natural gas marketing volumes accounted for a $120 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our natural gas prices accounted for an approximate $248 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

Higher oil marketing volumes accounted for a $7 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our oil prices accounted for an approximate $22 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 $4 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our ethane prices accounted for an approximate $21 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 NGL marketing volumes between periods also contributed to increased marketing revenues during the year ended December 31, 2021.

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 increased from $469 million for the year ended December 31, 2020 to $812 million for the year ended December 31, 2021, an increase of $343 million, or 73%.

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, NGL and oil purchases increased approximately $309 million, $20 million and $24 million, respectively, between periods primarily due to higher commodity prices and increased marketing volumes between periods.

transportation costs were $218 million for the year ended December 31, 2020 and $208 million for the year ended December 31, 2021, a decrease of $10 million due to the reduction in firm transportation commitments between periods.

Antero Midstream Segment Results for the Year Ended December 31, 2020 Compared to the Year Ended December 31, 2021

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

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 decreased from $901 million, which included amortization of customer relationships of $71 million, for the year ended December 31, 2020 to $898 million, which included amortization of customer relationships of $71 million, for the year ended December 31, 2021, a decrease of $3 million, primarily due to lower water handling revenue as a result of decreased well completions period-over-period, partially offset by higher low pressure revenues due to lower fee rebates earned by us as well as higher compression revenues as a result of increased throughput between periods.

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 segment decreased from $1.0 billion for the year ended December 31, 2020 to $342 million for the year ended December 31, 2021 primarily due to impairments recorded by Antero Midstream during the year ended December 31, 2020 of $98 million on its freshwater pipelines and equipment and impairment of goodwill of $575 million.

Antero Midstream’s impairment expense was $5 million for the year ended December 31, 2021 due to canceled project write-downs as well as a lower of cost or market adjustment for pipe inventory.

Discussion of Items Not Allocated to Segments for the Year Ended December 31, 2020 Compared to the Year Ended December 31, 2021

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 $200 million for the year ended December 31, 2020 to $182 million for the year ended December 31, 2021, a decrease of $18 million, or 9%, primarily due to the reduction in debt as a result of repurchases of our unsecured senior notes, paydown of our Credit Facility and increased interest income between periods, partially offset by interest that accrued on the (i) 2026 Convertible Notes, which were issued in August 2020 and (ii) 2026 Notes, 2029 Notes and 2030 Notes, each of which was issued after December 31, 2020.

Interest expense includes approximately $12 million of amortization of debt issuance costs and debt discounts and premiums for each of the years ended December 31, 2020 and 2021.

Gain (loss) on early extinguishment of debt.

During the year ended December 31, 2020, we recognized a gain on early extinguishment of debt of $176 million related to $1.4 billion principal amount of debt that we repurchased at a weighted average discount of 13%.

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 (i) the remaining balance of $661 million of our 2022 Notes at par, plus accrued and unpaid interest;

(ii) the remaining balance of $574 million of our 2023 Notes at par, plus accrued and unpaid interest;

(iii) $175 million of our 2026 Notes at a redemption price of 108.375% of par, plus accrued and unpaid interest;

and (iv) $116 million of our 2029 Notes at a redemption price of 107.625% of par, plus accrued and unpaid interest.

For such redemptions, we recognized a $32 million loss on early extinguishment of debt.

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.

D uring 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 equitization.

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.

Impairment of equity method investment .

In 2020, we determined that events and circumstances indicated that the carrying value of our investment in Antero Midstream had experienced an other-than-temporary decline, and we recorded impairment of $611 million.

The fair value of the equity method investment in Antero Midstream was based on the quoted market share price of Antero Midstream as of March 31, 2020.

Income tax benefit.

Income tax benefit decreased from $397 million, with an effective tax rate of 24%, for the year ended December 31, 2020 to $74 million, with an effective tax rate of 32%, for the year ended December 31, 2021, primarily due to a lower book loss between periods and the effects of a West Virginia apportionment tax law change enacted in 2021.

For the year ended December 31, 2021, 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, non-deductible equity-based compensation expenses and the effects of a West Virginia apportionment tax law change enacted in 2021.

See Note 14—Income Taxes to our consolidated financial statements more

for information regarding our income tax provision for the years ended December 31, 2020 and 2021.

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.

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 net operating loss (“NOL”) carryforwards of approximately $2.3 billion.

Many of these NOLs expire at various dates between 2025 and 2041 while others have no expiration date.

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.

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Capital Resources and Liquidity

Our primary sources of liquidity have been through net cash provided by operating activities including proceeds from derivatives, borrowings under our Credit Facility, issuances of debt and equity securities, dividends from unconsolidated affiliates and proceeds from our asset sale program.

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 growing our proved reserves and production will be highly dependent on net cash provided by operating activities and the capital resources available to us.

For information about the impacts of COVID-19 on our capital resources and liquidity, see “—COVID-19 Pandemic.”

The New Credit Facility has a borrowing base of $3.5 billion and current lender commitments of $1.5 billion.

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 New Credit Facility, see “Item 1A.

Risk Factors—The borrowing base under the New 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 New Credit Facility.”

Our commodity hedge position provides us with additional liquidity because it provides us with the relative certainty of receiving a significant portion of our future expected revenues from operations despite potential declines in the price of natural gas.

For the year ended December 31, 2021, approximately 70% of our volumes were hedged through fixed price commodity swap.

Assuming our 2022 production is the same as our production in 2021, approximately 54% of our production for 2022 will be hedged through fixed price commodity swap.

Our ability to make significant additional acquisitions for cash would require us to utilize borrowings on the New 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 New Credit Facility is funded by a syndicate of 15 banks.

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.

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 New Credit Facility.

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 2022 is $740 million to $775 million.

Our net capital budget for 2023 is $1.025 billion to $1.075 billion.

Our budget includes:

a range of $675 million to $700 million for drilling and completion and a range of $65 million to $75 million for leasehold expenditures.

a range of $875 million to $925 million for drilling and completion and $150 million for leasehold expenditures.

We do not budget for acquisitions.

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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.

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, 2021, we believe that net cash provided from operating activities and available borrowings under the New Credit Facility will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies for at least the next 12 months.

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

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.

The following table summarizes our cash flows for the years ended December 31, 2020 and 2021:

The following table summarizes our cash flows (in thousands):

Year Ended December 31,

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Operating Activities.

Net cash provided by operating activities was $736 million and $1.7 billion for the years ended December 31, 2020 and 2021, respectively.

Net cash provided by operating activities increased primarily due to increases in commodity prices both before and after the effects of settled commodity derivatives, decreased net marketing expense as well as decreased cash utilized for working capital, partially offset by decreased production and increased ad valorem taxes between periods.

Our net operating cash flows are sensitive to many variables, the most significant of which is the volatility of natural gas, NGLs and oil prices, as well as volatility in the cash flows attributable to settlement of our commodity derivatives.

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.

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Investing Activities.

Net cash flows used in investing activities increased from $530 million for the year ended December 31, 2020 to $711 million for the year ended December 31, 2021, due to $216 million in proceeds from the VPP and $125 million in settlement of the water earnout impacting the year ended December 31, 2020, partially offset by a decrease in capital expenditures of $158 million during the year ended December 31, 2021 as compared to the same period in 2020.

Total additions to unproved properties and drilling and completion costs decreased from $871 million during the year ended December 31, 2020 to $680 million during the year ended December 31, 2021 primarily due to a decrease in drilling and completion activity, increased drilling and completion efficiencies and service cost deflation.

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 $206 million for the year ended December 31, 2020 to $949 million for the year ended December 31, 2021.

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 2022 Notes, which were fully retired, (ii) redeem $574 million aggregate principal amount of our 2023 Notes, 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 Prior Credit Facility 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 interest in Martica.

During the year ended December 31, 2020, we repurchased (i) $1.1 billion aggregate principal amount of debt at a weighted average discount of 17% for $900 million of cash and (ii) $43 million of our common stock at weighted average price of $1.54 per share.

During the year ended December 31, 2020, we issued $288 million principal amount of 2026 Convertible Notes.

Additionally, we also received $351 million for the sale of a noncontrolling interest in Martica and distributed $36 million to the noncontrolling interest in Martica during the year ended December 31, 2020.

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.

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

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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 New Credit Facility.

Borrowings under the New Credit Facility are subject to borrowing base limitations based on the collateral value of our assets and are subject to regular semi-annual redeterminations.

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 New Credit Facility is the earlier of (i) October 26, 2026 and (ii) the date that is 180 days prior to the earliest stated redemption date of any series of Antero’s then outstanding senior notes.

As of December 31, 2021, we had no borrowings and $531 million of letters of credit outstanding under the New Credit Facility.

The New 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 New Credit Facility).

The New Credit Facility contains restrictive covenants that may limit our ability to, among other things:

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:

● incur additional indebtedness;

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● engage in certain other transactions without the prior consent of the lenders.

The New Credit Facility also requires us to maintain the following financial ratios (subject to certain exceptions):

The current ratio and the leverage ratio shall be tested quarterly commencing with the quarter ending December 31, 2021.

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.

● a minimum consolidated current ratio of 1.00 to 1.00 at the end of each fiscal quarter;

● a maximum leverage ratio of total debt to EBITDAX for the trailing four quarter period of 4.00 to 1.00 at the end of each fiscal quarter.

We were in compliance with the applicable covenants and ratios as of December 31, 2020 and 2021 under the Prior Credit Facility and New Credit Facility, respectively.

As of December 31, 2021, our current ratio was 3.42 to 1.00 and our leverage ratio was 1.35 to 1.00.

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

2025 Notes (1)

Outstanding principal (in thousands)

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Maturity date

March 1, 2025

July 15, 2026

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Make-whole redemption date (1)

March 1, 2023

January 15, 2026

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March 1, 2028

(1) On January 27, 2022, we announced that we will redeem all $585 million of the aggregate principal amount of our 2025 Notes at a redemption price of 101.25% of the principal amount thereof, plus accrued and unpaid interest on March 1, 2022.

Immediately following the redemption, the 2025 Notes will be fully retired.

The $7 million premium to the principal amount to be redeemed, along with the write-off of umaortized debt issuance costs, will be included in our loss on early debt extinguishment during the first quarter of 2022.

(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.

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(2) The indenture governing the 2026 Convertible Notes does not allow us to optionally redeem the 2026 Convertible Notes prior to the maturity date.

See Note 8—Long Term Debt to the consolidated financial statements for more information on our senior notes.

We may, from time to time, seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions, or otherwise.

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, 2021, we repurchased or redeemed $1.7 billion principal amount of debt, including portions of our 2022 Notes, 2023 Notes, 2025 Notes, 2026 Notes and 2029 Notes.

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.

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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.

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.

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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 results of drilling at that time, whether the costs should continue to be capitalized pending further well testing and results, or charged to expense.

The Company reviews exploration costs related to wells in progress at the end of each quarter and makes a determination, based on known

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.

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We did not record any impairments for proved properties during the years ended December 31, 2020, 2021 and 2022.

During the year ended December 31, 2019, the Utica Shale carrying value exceeded the estimated fair value of the Utica Shale assets based on sales of other properties.

As a result, we recorded an impairment of $881 million related to proved oil and gas properties in the Utica Shale during the year ended December 31, 2019.

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 approximately 25% and 35%, respectively, from year-end 2021 levels before further evaluation of those properties would be required in order to determine if an impairment charge would be necessary under GAAP.

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 market.

However, we are unable to predict commodity prices with any greater precision than the futures

Fair Value Measurement

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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).

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.

The difference between our financial statement income tax expense and our U.S.

federal income tax liability is primarily due to the differences in the tax and financial statement treatment of oil and gas properties, derivative instruments and the 2026 Convertible Notes.

Our deferred tax assets and liabilities result from temporary differences between tax and financial statement income, primarily from derivative instruments, oil and gas properties and NOL carryforwards.

As of December 31, 2021, we have U.S.

federal and state NOLs expiring at various dates from 2025 to 2041 while others have no expiration date, which resulted in the recognition of significant deferred tax assets.

There were no impairments of the equity method investment in Antero Midstream during the years ended December 31, 2021 and 2022.

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.

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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, 2021, we have recognized a valuation allowance of $50 million for NOLs we do not expect to realize that are primarily attributable to states in which we no longer operate and due to changes in West Virginia apportionment tax law.

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

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

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

Convertible Instruments

In August 2020, the FASB issued Accounting Standards Update (“ASU”) No.

2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity , which eliminates the cash conversion model in ASC 470-20, Debt with Conversion and Other Options , that require separate accounting for conversion features, and instead, allows the debt instrument and conversion features to be accounted for as a single debt instrument.

It is effective for interim and annual reporting periods beginning after December 15, 2021.

We will adopt the standard effective January 1, 2022 under the modified retrospective transition method.

Upon adoption of this new standard, we will reclassify $24 million, net of deferred income taxes and equity issuance costs, from additional paid-in capital and increase long-term debt by $27 million, reduce deferred income tax liability by $6 million and reduce accumulated deficit by $3 million as of January 1, 2022.

Additionally, annual interest expense for the 2026 Convertible Notes beginning January 1, 2022 will be based on an effective interest rate of 4.9% as compared to 15.3% for the year ended December 31, 2021.

We do not believe that adoption of the standard will impact our operational strategies or development prospects.

In December 2019, the FASB issued ASU No.

2019-12, Simplifying the Accounting for Income Taxes .

This ASU removes certain exceptions to the general principles in ASC 740, Income Taxes (“ASC 740”) and also simplifies portions of ASC 740 by clarifying and amending existing guidance.

It is effective for interim and annual reporting periods beginning after December 15, 2020.

We adopted this ASU on January 1, 2021, and it did not have a material impact on our consolidated financial statements.

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

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis