What changed in this filing

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Item 7. Management’s Discussion and Analysis

2022-02-16 compared with 2021-02-17 · 305 added, 347 removed, 322 unchanged (67% of the section changed)

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In addition, we estimate that approximately 174,000 net acres of our leasehold may be prospective for the slightly shallower Upper Devonian Shale.

As of December 31, 2020, our estimated proved reserves were approximately 17.6 Tcfe, consisting of 10.0 Tcf of natural gas, 745 MMBbl of assumed recovered ethane, 491 MMBbl of C3+ NGLs, and 32 MMBbl of oil.

This represents a 7% decrease in estimated proved reserves from December 31, 2019.

As of December 31, 2021, our estimated proved reserves were 17.7 Tcfe, consisting of 10.2 Tcf of natural gas, 718 MMBbl of assumed recovered ethane, 501 MMBbl of C3+ NGLs and 36 MMBbl of oil.

This represents a 0.5% increase in estimated proved reserves from December 31, 2020.

These reserve estimates have been prepared by our internal reserve engineers and management and audited by our independent reserve engineers.

As of December 31, 2021, we had approximately 2,083 potential horizontal well locations on our existing leasehold acreage that were classified as proved, probable and possible.

We operate in the following industry segments:

We operate in the following reportable segments:

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

(ii) marketing of excess firm transportation capacity;

and (iii) midstream services through our equity method investment in Antero Midstream Corporation.

As described below and elsewhere in this Annual Report on Form 10-K, effective March 13, 2019, we no longer consolidate the results of Antero Midstream Partners.

and (iii) midstream services through our equity method investment in Antero Midstream Corporation (“Antero Midstream”).

All of our operations are conducted in the United States.

Recent Developments and Highlights

COVID-19 Pandemic

In March 2020, the World Health Organization declared the COVID-19 outbreak a pandemic.

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

Also, in March 2020, Saudi Arabia and Russia failed to agree to cut production of oil along with the Organization of the Petroleum Exporting Countries (“OPEC”), and Saudi Arabia significantly reduced the price at which it sells oil and announced plans to increase production, which contributed to a sharp drop in the price of oil.

While OPEC, Russia and other allied producers reached an agreement in April 2020 to reduce production, oil prices have remained low.

The imbalance between the supply of and demand for oil, as well as the uncertainty around the extent and timing of an economic recovery, have caused extreme market volatility and a substantial adverse

effect on commodity prices.

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.

We have continued to operate as permitted under these regulations while taking steps to protect the health and safety of our employees and contract workers.

We have implemented protocols to reduce the risk of an outbreak within our field operations, and these protocols have not reduced production or efficiency in a significant manner.

A substantial portion of our non-field level employees continue to 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.

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

Although the decline in oil prices has negatively impacted our oil revenue, oil sales represented approximately 3% of our total revenue for the year ended December 31, 2020.

While natural gas prices also declined during the first half of 2020, benchmark Henry Hub prices recovered during the third quarter and averaged $2.32/Mcf in the last half of 2020.

Similarly, C3+ NGL prices also improved during the second half of 2020 as gasoline demand increased, supporting prices for normal butane (nC4), isobutane (iC4), and pentane (C5), all of which are used for gasoline.

The COVID-19 pandemic reduced gasoline demand, which forced C5 prices below propane prices for much of April 2020 to under $0.40 per gallon, has since rebounded with benchmark C5 price in January 2021 in the range of $1.05 to $1.25 per gallon.

In addition, we have hedged through fixed price contracts the sale of 2.2 Bcf per day of natural gas at a weighted average price of $2.77 per MMBtu in 2021.

Our hedges cover a substantial majority of our expected natural gas production in 2021.

We also have fixed priced contracts for the sale of 19,000 barrels per day of ethane at a weighted average price of $0.20 per gallon and 3,000 barrels per day of oil at a weighted average price of $55.16 per barrel for 2021.

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

As such, any decreases in anticipated production, whether as a result of decreased development activity, shut-ins, or through transactions under our asset sale plan, will not impact our ability to realize the benefits of the hedges.

Our natural gas and NGLs are primarily used in manufacturing, power generation and heating rather than transportation.

While we have seen a decrease in the overall demand for these products, demand for natural gas and NGLs has not declined as much as demand for oil, and there has not been as substantial an oversupply of natural gas and NGLs as there has been of oil.

Furthermore, the decrease in demand for oil has significantly reduced the number of rigs drilling for oil in the continental U.S.

and, as a result, estimates of future gas supply associated with oil production have declined.

Additionally, the restart of economic activity in Asia and Europe, coupled with lower LPG production from refineries in the U.S., Europe, and Asia during the second quarter, provided support for international LPG prices relative to oil.

Further, reductions in OPEC+ and North American oil production and the associated NGL volumes are expected to have a supportive effect on propane and butane prices into 2021.

During the fourth quarter of 2020, we shipped 43% of our total C3+ NGL net production on Mariner East 2 for export and realized a $0.11 per gallon premium to Mont Belvieu pricing on these volumes at Marcus Hook, PA.

We sold the remaining 57% of C3+ NGL net production at a $0.06 per gallon discount to Mont Belvieu pricing at Hopedale, OH.

We expect to sell at least 48% of our C3+ NGL full-year production in 2021 at Marcus Hook for export at a premium to Mont Belvieu.

Condensate differentials to WTI were approximately $12/Bbl during the fourth quarter.

Pre-hedge oil realizations were negatively impacted during the second quarter and beginning of the third quarter as Antero sold volumes at a material discount to WTI in order to keep from shutting in production volumes.

This period of weak condensate demand driven by the pandemic coincided with an active well completion period for Antero that brought on large condensate volumes.

The negative impact from wider oil differentials was more than offset by the benefit of maintaining full natural gas and NGL volumes through this period.

Antero expects its full year 2021 realized oil price differential to be at the high end of the $9.00/Bbl to $11.00/Bbl range, as the differential normalized during the fourth quarter of 2020.

Our supply chain also has not experienced any significant interruptions.

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.

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

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

Also, 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, and such capacity is still largely available to us.

In addition, as discussed in “—Capital Resources and Liquidity—2020 Capital Spending and 2021 Capital Budget” below, we announced a 21% reduction in our drilling and completion capital budget for 2021 compared to 2020.

During the fourth quarter, our ongoing emphasis on completion efficiencies and drilling longer laterals resulted in material improvements in well costs.

Well costs averaged approximately $680 per lateral foot during the fourth quarter, benefiting from these efficiency improvements and lateral lengths that averaged over 15,000 feet.

Well costs were approximately $690 per foot when normalized for a 12,000 foot lateral length.

We expect well costs to average $660 per foot during the first quarter of 2021, based on a 12,000 foot lateral.

We continue to monitor our five-year drilling plan and will make further revisions as appropriate.

During the first quarter of 2020 and the two preceding quarters, we recognized various impairment charges related to the decline in commodity prices and the value of our investment in Antero Midstream Corporation.

At this time, we do not anticipate any further impairment charges in our equity method investment in Antero Midstream Corporation because the value of our equity method investment has increased since the end of the first quarter of 2020.

Additional impairment charges related to our assets may occur if we experience disruptions in production, additional or sustained declines in the forward commodity price strip from December 31, 2020, unresolved storage capacity restraints or other consequences caused by the COVID-19 pandemic.

In October 2020, the borrowing base supporting our Credit Facility was subject to its semi-annual redetermination and was re-affirmed at $2.85 billion.

Lender commitments remained unchanged at $2.64 billion, providing us with a consistent amount of available borrowings.

Our next semi-annual borrowing base redetermination is in April 2021, which could impact our available borrowings and liquidity.

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

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

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, and we have not implemented or requested any concessions or materially modified the terms of any agreements.

The COVID-19 pandemic, commodity market volatility and resulting financial market instability are variables beyond our control and 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.

Financing Highlights

Debt Repurchase Program

During the year ended December 31, 2020, we repurchased $1.4 billion principal amount of our senior notes through open market repurchases, tender offers and redemptions at a weighted average discount of 13%.

We recognized a gain of $176 million for the year ended December 31, 2020 on the early extinguishment of the debt repurchased.

As a result, our 5.375% senior notes due November 1, 2021 (the “2021 Notes”) were fully retired as of November 30, 2020.

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

See Note 8—Long-Term Debt to the consolidated financial statements for more information.

Asset Sales Program

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

In connection with the transaction, we contributed the ORRIs to a newly formed subsidiary, Martica Holdings LLC (“Martica”).

At the initial closing, Sixth Street contributed $300 million in cash (subject to customary adjustments) and agreed to contribute up to an additional $102 million in cash if certain production thresholds attributable to the ORRIs are 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 production threshold related to the third quarter of 2020 and received a $51 million cash distribution during the year ended December 31, 2020.

See Note 4—Transactions to the consolidated financial statements for more information.

On August 10, 2020, we completed a volumetric production payment transaction and received net proceeds of approximately $216 million (the "VPP").

In connection with the VPP, we entered into a purchase and sale agreement, together with a conveyance agreement and production and marketing agreement, with J.P.

Morgan Ventures Energy Corporation ("JPM-VEC") to convey, effective July 1, 2020, an overriding royalty interest in dry gas producing properties in West Virginia (the "VPP Properties") equal to

136,589,000 MMBtu over the expected seven-year term of the VPP.

See Note 4—Transactions to the consolidated financial statements for more information.

On February 17, 2021, we announced the formation of a drilling partnership with QL Capital Partners (“QL”), an affiliate of Quantum Energy Partners.

Under the terms of the arrangement, QL will fund 20% of total development capital spending in 2021 and is expected to fund between 15% and 20% of total development capital spending on an annual basis from 2022 through 2024.

All of the wells spud during each calendar year period will be a separate annual 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.

For each tranche other than 2021, we will propose a capital budget and estimated internal rate of return (“IRR”) for all wells to be spud during the year and, subject to the mutual agreement of the parties that the estimated IRR for each tranche exceeds a specified return, QL will be obligated to participate in such tranche.

For each annual tranche in which QL participates, QL will receive a proportionate working interest percentage in each well spud in such tranche.

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 tranches.

No earlier than December 31 following the expiration of each tranche year, we will calculate the tranche IRR for such tranche year and, if the tranche IRR exceeds certain specified returns, we will receive a carry in the form of a one-time payment from QL for such annual tranche.

Issuance of Convertible Senior Notes and Senior Notes

On August 21, 2020, we issued $250 million in aggregate principal amount of 4.25% senior unsecured convertible notes (the “2026 Convertible Notes”).

On September 2, 2020, we issued an additional $37.5 million of the 2026 Convertible Notes.

The initial conversion rate is 230.2026 shares of our common stock per $1,000 principal amount of 2026 Convertible Notes, subject to adjustment upon the occurrence of specified events.

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

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.

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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.

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

Convertible Notes Equitization

On January 12, 2021, we completed a registered direct offering (the “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 2026 Convertible Notes.

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

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

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”).

See Note 8—Long-Term Debt to the consolidated financial statements for more information.

Share Repurchase Program

Our board-approved share repurchase program expired on March 31, 2020.

Prior to the program’s expiration, we repurchased and retired 28,193,237 common shares at a weighted average price per share of $1.54 for approximately $43 million during the first quarter of 2020.

Capital Return 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.

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.

Drilling Partnership

On February 17, 2021, we announced the formation of a drilling partnership with QL Capital Partners (“QL”), an affiliate of Quantum Energy Partners, for our 2021 through 2024 drilling program.

Under the terms of the arrangement, each year in which QL participates represents an annual tranche, and QL will be conveyed a working interest in any wells spud by us during such tranche year.

For 2021 and 2022, 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 and 2022 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.

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.

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.

Capital costs in excess of, and cost savings below, a specified percentage of budgeted amounts for each annual tranche will be for our account.

Subject to the preceding sentence, for any wells included in a tranche, QL is obligated and responsible for its working interest share of costs and liabilities, and is entitled to its working interest share of revenues, associated with such wells for the life of such wells.

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

Overriding Royalty Interest Additional Contributions

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 .

Sources of Our Revenues

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During 2021, our production revenues were comprised of approximately 59% from the sale of natural gas and 41% from the sale of NGLs and oil.

Natural gas, NGLs, and oil prices are inherently volatile and are influenced by many factors

outside of our control.

Natural gas, NGLs and oil prices are inherently volatile and are influenced by many factors outside of our control.

All of our production is derived from natural gas wells, some of which also produce NGLs which are extracted through processing, and oil.

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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 New York Mercantile Exchange (“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.

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.

We expect continued volatility in the prices we receive for our production and the fair value of our derivative instruments.

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● Gathering, compression, water handling and treatment revenues.

Gathering, compression, water handling and treatment revenues are derived from our ownership interest in Antero Midstream Partners through March 12, 2019 and Antero Midstream thereafter.

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

Principal Components of Our Cost Structure

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● Exploration expense.

These are primarily costs related to unsuccessful leasing efforts, as well as geological and geophysical costs, including seismic costs, and costs of unsuccessful exploratory dry holes.

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.

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● Depletion, depreciation, and amortization.

Depletion, depreciation, and amortization (“DD&A”), includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas, NGLs, and oil.

DD&A includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas, NGLs and oil.

As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts and allocate these costs using the units of production method.

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General and administrative expense also includes noncash equity-based compensation expense.

See Note 10—Equity-Based Compensation and Retention Awards to the consolidated financial statements for more information.

See Note 10—Equity-Based Compensation and Cash Awards to the consolidated financial statements for more information.

● Interest expense.

We finance a portion of our capital expenditures, working capital requirements, and acquisitions with borrowings under the Credit Facility, which has a variable rate of interest based on LIBOR or the prime rate.

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.

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, 2020, we had a fixed interest rate of 5.125% on our 2022 Notes having a principal balance of $661 million, a fixed interest rate of 5.625% on our 2023 Notes having a principal balance of $574 million, a fixed interest rate of 5.00% on our 2025 Notes having a principal balance of $590 million, and a fixed interest rate of 4.25% on our 2026 Convertible Notes having a principal balance of $287.5 million.

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.

See Note 8—Long-Term Debt to the consolidated financial statements for more information.

● Income tax expense.

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 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 for tax purposes until they are settled.

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.

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, 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.

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We have three operating segments:

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

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

and (3) midstream services through our equity method investment in Antero Midstream Corporation.

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

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

Through March 12, 2019, we included the results of Antero Midstream Partners in our consolidated financial statements.

Effective March 13, 2019, we no longer consolidate the results of Antero Midstream Partners in our results;

however, our segment disclosures include the segments of our unconsolidated affiliates, due to their significance to our operations.

See Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for further discussion on the simplification transactions and Note 18—Segment Information to the consolidated financial statements for disclosures on our reportable segments.

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

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

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.

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.

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

Year Ended December 31, 2020

Equity Method

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Unconsolidated

Corporation (1)

Year Ended December 31, 2019

Revenue and other:

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Gathering, compression, water handling and treatment

Amortization of deferred revenue, VPP

Other income (loss)

Total revenue

Operating expenses:

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Production and ad valorem taxes

General and administrative (excluding equity-based compensation)

Equity-based compensation

Depletion, depreciation, and amortization

Impairment of oil and gas properties

Impairment of midstream assets

Depletion, depreciation, and amortization

Accretion of asset retirement obligations

General and administrative (excluding equity-based compensation)

Equity-based compensation

Change in fair value of contingent acquisition consideration

Contract termination and rig stacking

Contract termination and rig stacking and other expenses

Loss on sale of assets

Operating income (loss)

Equity in earnings of unconsolidated affiliates

(1) Includes the consolidated results of Antero Midstream Partners through March 12, 2019 and results of the Company’s equity method investment in Antero Midstream Corporation effective March 13, 2019.

Total operating expenses

Operating loss

Equity in earnings (loss) of unconsolidated affiliates

Year Ended December 31, 2021

Equity Method

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Unconsolidated

Year Ended December 31, 2020

Revenue and other:

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Natural gas liquids sales

Commodity derivative fair value gains

Commodity derivative fair value losses

Gathering, compression, water handling and treatment

Amortization of deferred revenue, VPP

Other income (loss)

Total revenue

Operating expenses:

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Production and ad valorem taxes

Impairment of oil and gas properties

Impairment of midstream assets

Depletion, depreciation, and amortization

Accretion of asset retirement obligations

General and administrative (excluding equity-based compensation)

Equity-based compensation

Depletion, depreciation, and amortization

Impairment of oil and gas properties

Accretion of asset retirement obligations

Contract termination and rig stacking and other expenses

Loss on sale of assets

Operating loss

Equity in earnings (loss) of unconsolidated affiliates

Gain on sale of assets

Total operating expenses

Operating income (loss)

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:

Year Ended December 31,

Production data (1) (2) :

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(1) Production data excludes volumes related to the VPP.

(2) Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts.

This ratio is an estimate of the equivalent energy content of the products and may not reflect their relative economic value.

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

Our calculation of such after effects includes gains on settlements of commodity derivatives (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.

Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts.

This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value.

(3) The average realized price for 2019 includes $54 million of the proceeds related to the South Jersey Litigation.

See Note 16—Contingencies to the consolidated financial statements for further discussion on the South Jersey Litigation.

Excluding the effect of the proceeds of the South Jersey Litigation settlement, the average realized price would have been $2.67 per Mcf.

(4) The average realized price for the year ended December 31, 2021 includes $85 million of net litigation proceeds related to a favorable litigation judgment.

See Note 16—Contingencies to the consolidated financial statements for further discussion on the litigation proceeds.

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

Natural gas sales .

Revenues from sales of natural gas decreased from $2.2 billion, which included litigation proceeds of $54 million, for the year ended December 31, 2019 to $1.8 billion for the year ended December 31, 2020, a decrease of $437 million.

Please see Note 16— Contingencies to the consolidated financial statements for more information.

Excluding litigation proceeds, higher natural gas production volumes during the year ended December 31, 2020 accounted for an approximate $143 million increase in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price excluding the proceeds from the South Jersey Litigation), and decreases in our prices (excluding the effects of derivative settlements and proceeds from the South Jersey Litigation) accounted for an approximate $526 million decrease in year-over-year gas sales revenue (calculated as the change in the year-to-year average price excluding the proceeds from the South Jersey Litigation times current year production volumes).

Revenues from sales of NGLs decreased from $1.22 billion for the year ended December 31, 2019 to $1.16 billion for the year ended December 31, 2020, a decrease of $57 million, or 5%.

Higher NGLs production volumes accounted for an approximate $277 million increase in year-over-year NGLs sales revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our prices, excluding the effects of derivative settlements, accounted for an approximate $334 million decrease in year-over-year NGL sales revenues (calculated as the change in the year-to-year average price times current year production volumes).

Revenues from production of oil decreased from $178 million for the year ended December 31, 2019 to $112 million for the year ended December 31, 2020, a decrease of $66 million.

Increased oil production volumes accounted for a $38 million increase 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 prices, excluding the effects of derivative settlements, accounted for an approximate $104 million decrease in year-over-year oil sales revenues (calculated as the change in the year-to-year average price times current year production volumes).

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%.

See Note 16—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).

Revenues from sale of oil increased from $112 million for the year ended December 31, 2020 to $201 million for the year ended December 31, 2021, an increase of $89 million, or 79%.

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, basis swap contracts and collar contracts when management believes that favorable future sales prices for our production can be secured.

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.

Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment.

Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations.

For the years ended December 31, 2019 and 2020, our commodity hedges resulted in derivative fair value gains of $464 million and $80 million, respectively.

The commodity derivative fair value gains included $325 million and $795 million of cash proceeds on gains on settled derivatives for the years ended December 31, 2019 and 2020, respectively.

Commodity derivative fair value gains (losses) for the year ended December 31, 2020 also include cash proceeds of $9 million related to derivatives that were monetized prior to their contractual settlement dates.

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.

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.

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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.

See “—Capital Resources and Liquidity—Overview” for more information.

Amortization of deferred revenue, VPP.

The year ended December 31, 2020 includes amortization of $15 million of deferred revenues associated with the VPP, which relate to the production volumes delivered under the terms of the agreement during such period at approximately $1.61 per MMBtu.

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.

Under the terms of the agreement, the production volumes are delivered at approximately $1.61 per MMBtu over the contractual term.

See Note 4—Transactions to the consolidated financial statements for more information on this transaction.

Other income .

Other income remained relatively consistent at $4 million and $3 million for the years ended December 31, 2019 and 2020, respectively.

Lease operating expense .

Lease operating expense for the exploration and production segment decreased from $146 million for the year ended December 31, 2019 to $99 million for the year ended December 31, 2020, a decrease of $47 million or 32%.

On a per unit basis, lease operating expenses decreased from $0.13 per Mcfe for the year ended December 31, 2019 to $0.08 per Mcfe for the year ended December 31, 2020 primarily due to lower water handling costs resulting from improved operating efficiencies, including the reuse of produced and flowback water in completion operations.

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.

Gathering, compression, processing, and transportation expense.

Gathering, compression, processing, and transportation expense increased from $2.2 billion for the year ended December 31, 2019 to $2.5 billion for the year ended December 31, 2020.

This is primarily a result of the 11% increase in production.

Gathering and compression costs decreased from $0.70 per Mcfe for the year ended December 31, 2019 to $0.64 per Mcfe for the year ended December 31, 2020 primarily due to lower fuel costs as a result of decreased natural gas prices and $48 million in incentive fee rebates from Antero Midstream Corporation.

Processing costs increased from $0.66 per Mcfe to $0.69 per Mcfe for the years ended December 31, 2019 and 2020, respectively, primarily due to increased NGL production in our production mix.

Processing costs, however, decreased per NGL barrel year-over-year.

Transportation costs increased from $0.56 per Mcfe to $0.60 per Mcfe for the years ended December 31, 2019 and 2020, respectively, primarily due to increased rates on the Rockies Express pipeline, which were effective October 2019 and demand charges for Mountaineer Xpress pipeline.

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.

Production and ad valorem tax expense.

Total production and ad valorem taxes decreased from $125 million for the year ended December 31, 2019 to $107 million for the year ended December 31, 2020, a decrease of $18 million or 15%, primarily due to lower commodity prices between periods.

On a per Mcfe basis, production and ad valorem taxes decreased from $0.11 per Mcfe for

the year ended December 31, 2019 to $0.08 per Mcfe for the year ended December 31, 2020.

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.

Exploration expense .

Exploration expense representing expenses incurred for unsuccessful lease acquisition efforts remained relatively flat at $1 million for each of the years ended December 31, 2019 and 2020.

Impairment of oil and gas properties .

During the year ended December 31, 2019, we recognized an $881 million impairment to write-down our Utica Shale proved properties to fair value because the carrying value of such properties exceeded the estimated undiscounted cash flows based on future strip commodity prices as of September 30, 2019.

We also recorded $419 million and $224 million of impairments for the years ended December 31, 2019 and 2020, respectively, related to expiring leases and the design and initial costs related to pads we no longer plan to place into service.

Depletion, depreciation, and amortization expense .

DD&A expense decreased from $893 million for the year ended December 31, 2019 to $862 million for the year ended December 31, 2020 for the exploration and production segment, a decrease of $31 million or 4%.

DD&A per Mcfe decreased from $0.76 per Mcfe during the year ended December 31, 2019 to $0.66 per Mcfe during the year ended December 31, 2020 due to a reduction in the cost basis of producing properties as a result of the impairments discussed above as well as due to increases in proved reserves between periods.

General and administrative expense.

General and administrative expense (excluding equity-based compensation expense) decreased from $139 million for the year ended December 31, 2019 to $111 million for the year ended December 31, 2020, a decrease of $28 million or 20%, primarily due to decreases in employee related expenses in the year ended December 31, 2020 as a result of ongoing cost savings initiatives including lower headcount between periods.

We had 547 employees as of December 31, 2019 and 522 employees as of December 31, 2020.

On a per unit basis, general and administrative expense excluding equity-based compensation decreased by 33%, from $0.12 per Mcfe during the year ended December 31, 2019 to $0.08 per Mcfe during the year ended December 31, 2020 as a result of higher production volumes and lower overall costs between periods.

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.

We had 522 and 519 employees as of December 31, 2020 and 2021, 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.

Equity-based compensation expense .

Noncash equity-based compensation expense increased from $21 million for the year ended December 31, 2019 to $23 million for the year ended December 31, 2020, an increase of $2 million or 8%, primarily due to new awards granted to officers and employees in 2020 partially offset by equity award forfeitures during 2020.

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.

See Note 10—Equity-Based Compensation and Retention Awards to the consolidated financial statements for more information on equity-based compensation awards.

Contract termination and rig stacking.

We incurred contract termination and rig stacking costs of $14 million during each of the years ended December 31, 2019 and 2020.

Contract termination and rig stacking costs represent fees incurred upon the delay or cancellation of drilling and completion contracts with third-party contractors in order to align our drilling and completion activity level with our capital budget.

See Note 10—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

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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.

Our net marketing expense decreased from $258 million, or $0.22 per Mcfe, for the year ended December 31, 2019 to $159 million, or $0.12 per Mcfe, for the year ended December 31, 2020.

The decrease was driven by higher marketing volumes and the mitigation of some of our excess firm transportation expense.

Marketing revenues increased from $292 million for the year ended December 31, 2019 to $311 million for the year ended December 31, 2020, an increase of $19 million, or 6%, primarily due to increased marketing volumes.

Marketing expenses decreased from $550 million for the year ended December 31, 2019 to $469 million for the year ended December 31, 2020, a decrease of $81 million, or 15%.

Marketing expenses include firm transportation costs related to current excess firm capacity as well as the cost of third-party purchased gas and NGLs.

Firm transportation costs included in the expenses above were $250 million and $146 million for the years ended December 31, 2019 and 2020, respectively.

Antero Midstream Corporation Segment Results for the Year Ended December 31, 2019 Compared to the Year Ended December 31, 2020

During the period from January 1, 2019 through March 12, 2019, we included the results of Antero Midstream Partners in our consolidated financial statements.

Effective March 13, 2019, we no longer consolidate the results of Antero Midstream Partners in our results.

See Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for further discussion on the Transactions.

We now account for our interest in Antero Midstream Corporation as an equity method investment.

Antero Midstream Corporation.

Revenue from the Antero Midstream Corporation segment increased from $793 million, which included amortization of customer relationships of $57 million, for the year ended December 31, 2019 to $901 million, which included amortization of customer relationships of $71 million, for the year ended December 31, 2020, an increase of $108 million, or 14%.

The increase in operating revenue was primarily due to an increase in gathering and compression volumes partially offset by a decrease in fresh water delivery volumes for the year ended December 31, 2020.

Total operating expenses related to the segment decreased from $1.2 billion for the year ended December 31, 2019 to $1.0 billion for the year ended December 31, 2020 primarily due to a decrease in total impairments of $88 million period over period.

In addition, Antero Midstream Partners had equity in earnings of unconsolidated affiliates of $51 million and $86 million for the years ended December 31, 2019 and 2020, respectively.

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.

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 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 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

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.

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

Water earnout.

In conjunction with the acquisition of the water handling and treatment assets, Antero Midstream agreed to pay us (a) $125 million in cash if Antero Midstream delivered 176 million barrels or more of fresh water during the period between January 1, 2017 and December 31, 2019 and (b) an additional $125 million in cash if Antero Midstream delivered 219 million barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020.

As of December 31, 2019, Antero Midstream had delivered more than the 176 million barrels, which entitled us to $125 million pursuant to clause (a) above, and, as a result, we recognized other income associated with the settlement on the water earnout.

The cash proceeds were received in January 2020.

As of December 31, 2020, Antero Midstream did not deliver more than 219 million barrels, and, as a result, no additional proceeds were earned with respect to the water earnout.

Impairment of equity method investment .

In 2019 and 2020, we determined that events and circumstances indicated that the carrying value of our investment in Antero Midstream Corporation had experienced an other-than-temporary decline and we recorded impairments of $468 million and $611 million, respectively.

The fair value of the equity method investment in Antero Midstream Corporation was based on the quoted market share price of Antero Midstream Corporation as of December 31, 2019 and March 31, 2020, respectively.

Interest expense.

Our interest expense exclusive of interest expense related to Antero Midstream Partners’ indebtedness decreased from $228 million for the year ended December 31, 2019 to $200 million for the year ended December 31, 2020, a decrease of $28 million, or 12%, primarily due to the reduction in debt as a result of our debt repurchases of unsecured senior notes at prices below their stated value, partially offset by interest that accrued on the newly issued 2026 Convertible Notes and higher borrowings on our Credit Facility between periods.

Interest expense includes approximately $11 million and $12 million of non-cash amortization of debt issuance costs and debt discounts and premiums for the years ended December 31, 2019 and 2020, respectively.

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%.

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 $61 million, which represents the difference between the fair value of the liability component of the 2026 Convertible Notes and the carrying value of such notes.

Additionally, during the 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.

See Note 8—Long-Term Debt to the consolidated financial statements for more information.

Loss on convertible note 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.

See Note 8—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 increased from $74 million, with an effective tax rate of 20%, for the year ended December 31, 2019 to $397 million, with an effective tax rate of 24%, for the year ended December 31, 2020 primarily due to an increased book loss year over year.

For the year ended December 31, 2020, 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 and non-deductible equity-based compensation expenses.

See Note 14—Income Taxes to our consolidated financial statements more for information regarding our income tax provision for the years ended December 31, 2019 and 2020.

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.

As of December 31, 2020 and 2021, we had U.S.

federal and state NOL carryforwards of approximately $2.3 billion and $2.0 billion, respectively.

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.

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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 the Credit Facility, issuances of debt and equity securities, distributions/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 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 use of cash has been for the exploration, development and acquisition of oil and natural gas properties.

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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.

The Credit Facility has a borrowing base of $2.85 billion and current lender commitments of $2.64 billion.

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.

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 2022.

For a discussion of the risks of a decrease in the borrowing base under the Credit Facility, see “Item 1A.

Risk Factors—The borrowing base under the Credit Facility may be reduced if commodity prices decline, which could hinder or prevent us from meeting our future capital needs.

We may also be required to post additional collateral as financial assurance of our performance under certain contractual arrangements, which could adversely impact available liquidity under our Credit Facility.”

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.

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.

Our ability to make significant additional 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 25 banks.

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.

We believe that the participants in the syndicate have the capability to fund up to their current commitment.

If one or more banks should not be able to do so, we may not have the full availability of the Credit Facility.

If one or more banks should not be able to do so, we may not have the full availability of the New Credit Facility.

2021 Capital Spending and 2022 Capital Budget

For the year ended December 31, 2021, our total consolidated capital expenditures were approximately $749 million, including drilling and completion expenditures of $627 million, leasehold additions of $79 million and other capital expenditures of $43 million.

Our net capital budget for 2021 is $635 million.

Our budget includes $590 million for drilling and completions and $45 million for leasehold expenditures.

Our net capital budget for 2022 is $740 million to $775 million.

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.

We do not budget for acquisitions.

During 2021, we plan to operate an average of three drilling rigs and two completion crews and we plan to complete 65 to 70 horizontal wells in the Appalachian Basin in 2021.

During 2022, we plan to complete 60 to 65 net horizontal wells in the Appalachian Basin.

We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices.

Our capital budget may be adjusted as business conditions warrant as the amount, timing and allocation of capital expenditures is largely discretionary and within our control.

If natural gas, NGLs, and oil prices decline, or costs increase, to levels that do not generate an acceptable level of corporate returns, we may defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity, and to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows.

Based on strip prices as of December 31, 2020, we believe that net cash provided from operating activities, available borrowings under the Credit Facility and capital market transactions 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 and Contractual Obligations.”

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, 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.

For more information on our outstanding indebtedness, see “—Debt Agreements.”

As of December 31, 2021, we did not have any off-balance sheet arrangements other than contractual commitments for firm transportation, gas processing and fractionation, gathering and compression services and land payment obligations.

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

Year Ended December 31,

(in thousands)

Net cash provided by operating activities

Net cash used in investing activities

Net cash provided by (used in) financing activities

Effect of deconsolidation of Antero Midstream Partners LP

Net increase (decrease) in cash and cash equivalents

Our consolidated cash flow statements for the years ended December 31, 2018 and 2019 include the cash flows related to Antero Midstream Partners for periods prior to March 13, 2019.

Effective March 13, 2019, the Company's cash flows include only the operating, investing and financing activities related to Antero and therefore, the cash flows for the years ended December 31, 2018 and 2019 may not be representative of our expected future cash flows.

See Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for more information.

Net cash used in financing activities

Net increase in cash and cash equivalents

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

Operating Activities.

Net cash provided by operating activities was $1.1 billion and $736 million for the years ended December 31, 2019 and 2020, respectively.

Cash flow from operations decreased primarily due to decreases in commodity prices both before and after the effects of settled commodity derivatives and increases in gathering, compression, processing, and transportation costs.

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.

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Regional and worldwide economic activity, weather, infrastructure capacity to reach markets, storage capacity and other variables influence the market conditions for these products.

For example, the impact of the COVID-19 outbreak has reduced global demand for natural gas, NGLs, and oil.

For example, the impact of the COVID-19 outbreak reduced global demand for natural gas, NGLs and oil.

These factors are beyond our control and are difficult to predict.

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Investing Activities.

Cash flows used in investing activities decreased from $1.0 billion for the year ended December 31, 2019 to $530 million for the year ended December 31, 2020, primarily due to a decrease in capital expenditures of $548 million during the year ended December 31, 2020 as compared to the same period in 2019, $297 million in proceeds received in connection with the Transactions in the year ended December 31, 2019, $100 million in proceeds received in connection with the sale of shares of Antero Midstream Corporation common stock in the year ended December 31, 2019, $125 million in settlement of the water earnout impacting the year ended December 31, 2020 and $216 million in proceeds received from the VPP in the year ended December 31, 2020.

See Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for further discussion on the Transactions.

In addition, the year ended December 31, 2019 included Antero Midstream Partners’ investments in joint ventures of $25 million and capital expenditures for water handling and treatment systems and gas gathering and compression systems of $73 million.

Due to the deconsolidation of Antero Midstream Partners on March 12, 2019, cash flows used in investing activities for the year ended December 31, 2020 do not include costs attributable to Antero Midstream Partner’s investing activity.

See Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements.

Excluding Antero Midstream Partners, capital expenditures were $1.3 billion and $874 million for the years ended December 31, 2019 and 2020, respectively.

Total additions to unproved properties and drilling and completion costs decreased from $1.3 billion during the year ended December 31, 2019 to $826 million during the year ended December 31, 2020 primarily due to a decrease in drilling and completion activity, increased drilling and completion efficiencies and service cost deflation.

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.

Financing Activities.

Net cash flows provided by financing activities was $558 million for the year ended December 31, 2019, compared to net cash flows used in financing activities of $206 million for the year ended December 31, 2020.

Net borrowings on our Credit Facility and Antero Midstream Partners’ credit facility increased from $232 million during the year ended December 31, 2019 to $465 million during the year ended December 31, 2020.

During the year ended December 31, 2020, approximately $1.2 billion was used to repurchase all of our 2021 Notes and repurchase a portion of our 2022 Notes, 2023 Notes and 2025 Notes, which were partially funded with borrowings on our Credit Facility, compared to $191 million used to repurchase senior notes in the year ended December 31, 2019.

In addition, we repurchased and retired 28,193,237 shares of common stock for approximately $43 million during the year ended December 31, 2020 compared to repurchases of 13,390,617 shares of common stock for approximately $39 million during the year ended December 31, 2019.

During the year ended December 31, 2019, Antero Midstream Partners issued $650 million of senior notes prior to the Transactions and 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 during the year ended December 31, 2020.

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.

See Note 4—Transactions and Note 8—Long-Term Debt for more information on these transactions, respectively.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity” in our Annual Report on Form 10-K for the year ended December 31, 2020 for a discussion of the cash flows for the year ended December 31, 2019 compared to the year ended December 31, 2020.

Debt Agreements and Contractual Obligations

Debt Agreements

Senior Secured Revolving Credit Facility

The Credit Facility is with a consortium of bank lenders.

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.

Credit Facility

We have a senior secured revolving credit facility with a consortium of bank lenders.

On October 26, 2021, we entered into an amended and restated senior secured revolving credit facility, the 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.

As of December 31, 2021, the borrowing base was $3.5 billion and lender commitments were $1.5 billion.

The next redetermination of the borrowing base is scheduled to occur by the end of April 2021.

The Credit Facility is scheduled to mature on October 26, 2022.

As of December 31, 2020, we had $1.0 billion of borrowings with a weighted average interest rate of 3.26% and $730 million of letters of credit outstanding under the Credit Facility.

As of December 31, 2019, we had $552 million of borrowings, with a weighted average interest rate of 3.28%, and $623 million of letters of credit outstanding under the Credit Facility.

The Credit Facility provides for borrowing under either an Adjusted LIBO Rate 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:

The next redetermination of the borrowing base is scheduled to occur in April 2022.

The maturity date of the New Credit Facility is the earlier of (i) October 26, 2026 and (ii) the date that is 180 days prior to the earliest stated redemption date of any series of Antero’s 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:

● incur additional indebtedness;

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

However, many of these covenants will terminate during any Investment Grade Period (as defined in the Credit Facility).

We were in compliance with the applicable covenants and ratios as of December 31, 2019 and 2020.

The actual borrowing capacity available to us may be limited by the financial ratio covenants.

As of December 31, 2020, our current ratio was 2.25 to 1.0 (based on the $2.85 billion borrowing base under the Credit Facility) and our interest coverage ratio was 7.30 to 1.0.

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

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

● a minimum consolidated current ratio of 1.00 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.

See Note 8—Long Term Debt to the consolidated financial statements included in this Annual Report on Form 10-K for more information on our Credit Facility

Senior Unsecured Notes

The following table summarizes certain material terms of our senior unsecured notes and convertible notes outstanding as of December 31, 2021:

Convertible Notes

2025 Notes (1)

Outstanding principal (in thousands)

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Maturity date

December 1, 2022

March 1, 2025

September 1, 2026

Interest payment dates

Make-whole redemption date (1)

March 1, 2023

(1) On or after these dates, we may redeem the applicable series of notes, in whole or in part, at a redemption price equal to 100% of the principal amount redeemed, together with accrued and unpaid interest up to the redemption date.

At any time prior to these dates, we may redeem the notes at a redemption price that includes an applicable premium as defined in the indentures to such notes.

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

On January 4, 2021 and January 26, 2021, we issued the 2026 Notes and 2029 Notes, respectively, at par.

We used the proceeds from the issuances of the senior notes to repay borrowings outstanding under the Credit Facility and redeem previously issued senior notes.

The following table summarizes certain material terms of the 2026 Notes and 2029 Notes:

Outstanding principal (in thousands)

Interest rate

Maturity date

July 15, 2026

February 1, 2029

March 1, 2030

September 1, 2026

Interest payment dates

Make-whole redemption date (2)

March 1, 2023

January 15, 2026

February 1, 2027

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.

(2) On or after these dates, we may redeem the applicable series of notes, in whole or in part, at a redemption price equal to 100% of the principal amount redeemed, together with accrued and unpaid interest up to the redemption date.

At any time prior to these dates, we may redeem the notes at a redemption price that includes an applicable premium as defined in the indentures to such notes.

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

(3) 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.

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The amounts involved could be material.

During the year ended December 31, 2020, we repurchased $1.4 billion principal amount of debt at a 13% weighted average discount, including all of our 2021 Notes and a portion of our 2022 Notes, 2023 Notes and 2025 Notes.

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.

The senior notes indentures each contain restrictive covenants and restrict our ability to incur additional debt unless a pro forma minimum interest coverage ratio requirement of 2.25:1 is maintained.

We were in compliance with such covenants as of December 31, 2020 and 2021.

Contractual Obligations

A summary of our contractual obligations as of December 31, 2020 is provided in the table below.

Future capital contributions to unconsolidated affiliates are excluded from the table as neither the amounts nor the timing of the obligations can be determined in advance.

Year Ended December 31,

(in millions)

Recorded contractual obligations:

Credit Facility (1)

Antero senior notes—principal (2)

Antero senior notes—interest (2)

Operating leases (3)

Finance leases (3)

Imputed interest for leases (3)

Asset retirement obligations (4)

Unrecorded contractual obligations:

Firm transportation (5)

Processing, gathering, and compression services (6)

Land payment obligations (7)

(1) Includes outstanding principal amounts as of December 31, 2020.

This table does not include future commitment fees, interest expense, or other fees on the Credit Facility because they are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments, or future interest rates to be charged.

The Credit Facility is scheduled to mature on October 26, 2022.

(2) Our senior notes include the 2022 Notes, 2023 Notes, 2025 Notes and 2026 Convertible Notes but does not include the 2026 Notes (aggregate principal amount of $500 million) or the 2029 Notes (aggregate principal amount of $700 million).

After December 31, 2020, we redeemed all of our 2022 Notes and equitized a portion of our 2026 Convertible Notes.

See Note 8—Long-Term Debt to the consolidated financial statements for more information on these transactions.

(3) Includes contracts for services provided by drilling rigs and completion fleets, processing, gathering and compression services agreements and office and equipment leases accounted for as leases.

The values in the table represent the gross amounts that we are committed to pay;

however, we will record in our financial statements our proportionate share of costs based on our working interests.

See Note 13—Leases to the consolidated financial statements for more information on our operating and finance leases.

(4) Represents the present value of our estimated asset retirement obligations.

Neither the ultimate settlement amounts nor the timing of our asset retirement.

obligations can be precisely determined in advance;

however, we believe it is likely that a very small amount of these obligations will be settled within the next five years.

(5) Includes firm transportation agreements with various pipelines in order to facilitate the delivery of our production to market.

These contracts commit us to transport minimum daily natural gas or NGLs volumes at negotiated rates, or pay for any deficiencies at specified reservation fee rates.

The amounts in this table reflect our minimum daily volumes at the reservation fee rates.

The values in the table represent the gross amounts that we are committed to pay;

however, we will record in our financial statements our proportionate share of costs based on our working interests and net of any fees for excess firm transportation marketed to third parties.

None of these agreements were determined to be leases.

(6) Contractual commitments for processing, gathering, and compression services agreements represent minimum commitments under long-term agreements not accounted for as leases.

The obligations determined to be leases are included within finance and operating leases in the table above.

(7) Includes contractual commitments for land acquisition agreements.

The values in the table represent the minimum payments due under these arrangements.

None of these agreements were determined to be leases.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP.

The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities.

The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingent assets and liabilities.

Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used.

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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.

We believe these accounting policies reflect our more significant estimates and assumptions used in the preparation of our consolidated

financial statements.

We believe these accounting policies reflect our more significant estimates and assumptions used in the preparation of our consolidated financial statements.

See Note 2—Summary of Significant Accounting Policies to the consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

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We have not incurred any such charges in the years ended December 31, 2019, 2020 and 2021.

The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units of production amortization rate.

The sale of a partial interest in a proved property is accounted for as a normal retirement, and no gain or loss is recognized as long as this treatment does not significantly affect the units of production amortization rate.

A gain or loss is recognized for all other sales of producing properties.

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Impairment of Proved Properties

We evaluate the carrying amount of our proved natural gas, NGLs, and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be

We evaluate the carrying amount of our proved natural gas, NGLs and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable.

Under GAAP for successful efforts accounting, if the carrying amount exceeds the estimated undiscounted future net cash flows (measured using futures prices at the end of a quarter), we further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeded the estimated fair value of the properties.

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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.

We estimate that if strip prices were to decline by approximately 2.5% from future pricing levels as of December 31, 2020, estimated future net revenues for our Utica properties would approximate the carrying amount of the properties and further evaluation of the fair value of those properties would be required in order to determine if an impairment charge would be necessary under GAAP.

For our Marcellus properties, strip pricing would have to decline by more than approximately 10% from year-end 2020 levels before further evaluation of those properties would be required in order to determine if an impairment charge would be necessary under GAAP.

We are unable, however, to predict commodity prices with any greater precision than the futures market.

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.

If future prices decline from December 31, 2021, 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.

Fair Value Measurement

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Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly.

In order to manage our exposure to natural gas, NGLs and oil price volatility, we enter into derivative transactions from time to time, which may include commodity swap agreements, basis swap agreements, collar agreements and other similar agreements related to the price risk associated with our production.

To the extent legal right of offset exists with a counterparty, we report derivative assets and liabilities on a net basis.

We record derivative instruments on the consolidated balance sheets as either assets or liabilities measured at fair value and records changes in the fair value of derivatives in current earnings as they occur.

Changes in the fair value of commodity derivatives, including gains or losses on settled derivatives, are classified as revenues on our consolidated statements of operations.

The fair value of derivative instruments was determined using Level 2 inputs.

Our derivatives have not been designated as hedges for accounting purposes.

We account for our investment in Antero Midstream under the equity method of accounting.

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If the fair value is less than the carrying value and management considers the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the financial statements as an impairment loss.

See Note 10—Equity-Based Compensation and Retention Awards to the consolidated financial statements for further discussion on our equity method investments.

As of December 31, 2019 and March 31, 2020, we determined that events and circumstances indicated that the carrying value had experienced an other-than-temporary decline and we recorded impairment expense of $468 million and $611 million, respectively.

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 December 31, 2019 (Level 1).

See Note 6—Equity-Method Investment to the consolidated financial statements for further discussion on our equity method investments.

As of March 31, 2020, we determined that events and circumstances indicated that the carrying value had experienced an other-than-temporary decline and we recorded impairment expense of $611 million.

The fair value of the equity method investment in Antero Midstream was based on the quoted market common stock price of Antero Midstream as of March 31, 2020 (Level 1).

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.

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 net operating loss (“NOL”) carryforwards.

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.

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

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We record a valuation allowance when we believe all or a portion of our deferred tax assets will not be realized.

the realizability of our deferred tax assets, management considers whether some portion or all of the deferred tax assets will be realized based on a more-likely-than-not standard of judgment.

In assessing the realizability of our deferred tax assets, management considers whether some portion or all of the deferred tax assets will be realized based on a more-likely-than-not standard of judgment.

The ultimate realization of deferred tax assets is dependent upon our ability to generate future taxable income during the periods in which our deferred tax assets are deductible.

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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, 2020, we have recognized a valuation allowance of $46 million for NOLs we do not expect to realize that are primarily attributable to states in which we no longer operate.

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.

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New Accounting Pronouncements

On August 5, 2020, the FASB issued Accounting Standards Update No.

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.

The new standard becomes effective on January 1, 2022, and early adoption is permitted.

We are evaluating our plans for adoption, including the adoption date and transition method.

Upon adoption of this new standard, we expect to reclassify $85 million, net of deferred income taxes and equity issuance costs, to long-term debt and deferred income tax liability, as applicable, from stockholders’ equity as of December 31, 2020, which amount is subject to adjustment for any conversions until adoption of this new standard.

Additionally, annual interest expense for the 2026 Convertible Notes will be based on an effective interest rate of 4.8% as compared to 15.1% for the year ended December 31, 2020.

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.

Off-Balance Sheet Arrangements

As of December 31, 2020, we did not have any off- balance sheet arrangements other than contractual commitments for firm transportation, gas processing and fractionation, gathering, and compression services and land payment obligations.

See “—Debt Agreements and Contractual Obligations—Contractual Obligations” for our commitments under these agreements.

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.

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