What changed in this filing

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Item 7. Management’s Discussion and Analysis

2021-02-17 compared with 2020-02-12 · 342 added, 292 removed, 327 unchanged (66% of the section changed)

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We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material.

Some of the key factors that could cause actual results to vary from our expectations include changes in natural gas, NGLs, and oil prices, the timing of planned capital expenditures, our ability to fund our development programs, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below, all of which are difficult to predict.

Some of the key factors that could cause actual results to vary from our expectations include changes in natural gas, NGLs, and oil prices, the timing of planned capital expenditures, our ability to fund our development programs, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, impacts of world health events, including the COVID-19 pandemic, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below, all of which are difficult to predict.

In light of these risks, uncertainties and assumptions, the forward- looking events discussed may not occur.

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In this section, references to “Antero,” the “Company,” “we,” “us,” and “our” refer to Antero Resources Corporation and its subsidiaries, unless otherwise indicated or the context otherwise requires.

We are an independent oil and natural gas company engaged in the exploration, development and production of natural gas, NGLs, and oil properties located in the Appalachian Basin.

We are an independent oil and natural gas company engaged in the development, production, exploration and acquisition of natural gas, NGLs, and oil properties located in the Appalachian Basin.

We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations.

Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays.

Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to profitably grow our reserves and production, primarily on our existing multi-year inventory of drilling locations.

Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to develop our reserves and production, primarily on our existing multi-year inventory of drilling locations.

We have assembled a portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and repeatability.

Our drilling opportunities are focused in the Marcellus Shale and Utica Shale of the Appalachian Basin.

As of December 31, 2019, we held approximately 451,000 net acres in the southwestern core of the Marcellus Shale, primarily in West Virginia, and approximately 91,000 net acres in the core of the Ohio Utica Shale for a total of 541,000 net acres in the Appalachian Basin.

In addition, we estimate that approximately 179,000 net acres of our Marcellus Shale leasehold may be prospective for the slightly shallower Upper Devonian Shale.

Finally, we own the deep rights on approximately 223,000 net acres of our Marcellus Shale leasehold in West Virginia that may be prospective for the dry gas Utica Shale.

Our drilling opportunities are focused in the Appalachian Basin.

As of December 31, 2020, we held approximately 515,000 net acres in the Appalachian Basin.

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

As of December 31, 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 5% increase in estimated proved reserves from December 31, 2018.

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

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

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(ii) marketing of excess firm transportation capacity;

and (iii) the gathering and processing of natural gas through our equity method investment in Antero Midstream Corporation.

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.

All of our operations are conducted in the United States.

Closing of Simplification Transaction and Midstream Stock Repurchase

On March 12, 2019, pursuant to the Simplification Agreement, (i) AMGP was converted from a limited partnership to a corporation under the laws of the State of Delaware and changed its name to Antero Midstream Corporation, and (ii) an indirect, wholly owned subsidiary of Antero Midstream was merged with and into Antero Midstream Partners, with Antero Midstream Partners surviving the merger as an indirect, wholly owned subsidiary of Antero Midstream.

In connection with the Closing, we received $297 million in cash and 158.4 million shares of Antero Midstream’s common stock, par value $0.01 per share, in consideration for 98,870,335 common units representing limited partnership interests in Antero Midstream Partners.

Prior to the Closing, our ownership of Antero Midstream Partners common units represented approximately a 53% limited partner interest in Antero Midstream Partners, and we consolidated Antero Midstream Partners’ financial position and results of operations into our consolidated financial statements.

The Transactions resulted in the exchange of limited partner interests in Antero Midstream Partners we owned for common stock of Antero Midstream representing an approximate 31% interest.

As a result, we no longer hold a controlling interest in Antero Midstream Partners and now have an interest in Antero Midstream that provides significant influence, but not control, over Antero Midstream.

Thus, effective March 13, 2019, we no longer consolidate Antero Midstream Partners in our consolidated financial statements and account for our interest in Antero Midstream using the equity method of accounting.

Because Antero Midstream Partners does not meet the requirements of a discontinued operation, Antero Midstream Partners’ results of operations continue to be included in our consolidated statement of operations and comprehensive income (loss) through March 12, 2019.

On December 16, 2019, we sold 19,377,592 shares of Antero Midstream’s common stock to Antero Midstream at a price of $5.1606 per share, which shares were thereafter cancelled by Antero Midstream, resulting in aggregate proceeds to us of $100 million.

This reduced our interest in Antero Midstream to approximately 28.7% as of December 31, 2019.

Antero Midstream owns, operates and develops midstream energy assets that service our production.

Antero Midstream’s assets consist of gathering systems and compression facilities, water handling and treatment facilities, and interests in processing and fractionation plants, through which Antero Midstream Partners and its affiliates, provides midstream services to us under long-term, fixed-fee contracts.

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.

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.

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

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

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

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

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.

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

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

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

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

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

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 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.

Sources of Our Revenues

● Natural gas, NGL and oil sale revenues.

Our revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from our natural gas during processing.

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During 2020, 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.

● Commodity derivatives.

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

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

● Marketing revenues.

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

Until March 12, 2019, substantially all revenues from our gathering and processing and water handling and treatment operations were derived from our ownership and consolidation of Antero Midstream Partners.

● 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.

Principal Components of Our Cost Structure

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These are the operating costs incurred to maintain our production.

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

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

Cost levels for these expenses can vary based on the volume of water produced, supply and demand for oilfield services, activity levels, and other factors.

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

We often enter into fixed price long- term contracts that secure transportation and processing capacity which may include minimum volume commitments, the cost for which is included in these expenses to the extent that they are not excess capacity.

We often enter into fixed price long- term contracts that secure transportation and processing capacity, which may include minimum volume commitments, the cost for which is included in these expenses to the extent that they are not associated with excess capacity.

Costs associated with excess capacity are included in marketing expenses.

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● Marketing expenses .

We purchase and sell third-party natural gas and NGLs and market excess capacity we have under long term contracts.

We purchase and sell third-party natural gas and NGLs and market our excess capacity under long-term contracts.

Marketing costs include the cost of purchased third-party natural gas and NGLs.

We also classify firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize this excess capacity as marketing expenses since we market this excess capacity to third parties.

We also classify firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize this excess capacity as marketing expenses, because we market this excess capacity to third parties.

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

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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.

We did not record any costs related to exploratory dry holes during the years ended December 31, 2018 and 2019.

● Impairment of oil and gas properties.

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We charge impairment expense for expired or soon-to-be expired leases when we determine they are impaired based on factors such as remaining lease terms, reservoir performance, commodity price outlooks and future plans to develop the acreage.

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

We did not record any impairments for proved properties during the year ended December 31, 2018.

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

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

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

● Depletion, depreciation, and amortization.

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

See Note 9 to the consolidated financial statements for more information on our general and administrative expense.

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

● Interest expense.

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As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions.

At December 31, 2019, we had a fixed interest rate of 5.375% on our 2021 notes having a principal balance of $953 million, a fixed interest rate of 5.125% on our 2022 notes having a principal balance of $923 million, a fixed interest rate of 5.625% on our 2023 notes having a principal balance of $750 million, and a fixed interest rate of 5.00% on our 2025 notes having a principal balance of $600 million.

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.

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

● Income tax expense.

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

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

At December 31, 2019, we had U.S.

federal and state NOL carryforwards of approximately $2.2 billion and $2.0 billion, respectively, some of which expire at various dates between 2032 and 2038 while others have no expiration date.

We recorded valuation allowances for deferred

tax assets at December 31, 2019 of approximately $47 million related to state loss carryforwards for which we do not believe we will realize a benefit.

The amount of deferred tax assets considered realizable, however, could change in the near term as we generate taxable income or as estimates of future taxable income are reduced.

See Note 14—Income Taxes to the consolidated financial statements for more information.

Results of Operations

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

and (3) equity method investment in Antero Midstream Corporation.

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, the results of Antero Midstream Partners were included in our consolidated financial statements.

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

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 to the consolidated financial statements for further discussion on the Transactions and Note 18 to the consolidated financial statements for disclosures on our reportable segments.

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.

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, 2019 and 2020 (in thousands):

Equity Method

Elimination of

Investment in

Transactions and

Unconsolidated

Corporation (1)

Year Ended December 31, 2019

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Natural gas liquids sales

Commodity derivative fair value losses

Gathering, compression, and water handling and treatment

Marketing derivative fair value gains

Gain on sale of assets

Other income (expense)

Commodity derivative fair value gains

Gathering, compression, water handling and treatment

Other income (loss)

Operating expenses:

Lease operating

Gathering, compression, processing, and transportation

Gathering and compression

Transportation

Production and ad valorem taxes

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Impairment of midstream assets

Accretion of asset retirement obligations

Depletion, depreciation, and amortization

Accretion of asset retirement obligations

General and administrative (excluding equity-based compensation)

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Change in fair value of contingent acquisition consideration

Contract termination and rig stacking

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.

Equity Method

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Unconsolidated

and production

Year Ended December 31, 2020

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Commodity derivative fair value gains

Gathering, compression, and water handling and treatment

Other income (loss)

Gathering, compression, water handling and treatment

Amortization of deferred revenue, VPP

Operating expenses:

Lease operating

Gathering, compression, processing, and transportation

Gathering and compression

Transportation

Production and ad valorem taxes

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Depletion, depreciation, and amortization

Loss on sale of assets

Accretion of asset retirement obligations

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Equity-based compensation

Change in fair value of contingent acquisition consideration

Contract termination and rig stacking

Operating income (loss)

Contract termination and rig stacking and other expenses

Loss on sale of assets

Operating loss

Equity in earnings (loss) of unconsolidated affiliates

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The following table sets forth selected operating data of the exploration and production segment for the year ended December 31, 2019 compared to the year ended December 31, 2020:

Year ended December 31,

Production data (1) (2) :

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Lease operating

Gathering, compression, processing, and transportation

Gathering and compression

Transportation

Production and ad valorem taxes

Marketing expense (gain), net

Marketing expense, net

Depletion, depreciation, amortization, and accretion

General and administrative (excluding equity-based compensation)

(1) Average sales prices shown in the table reflect both 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 derivative monetizations), which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes.

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

(2) 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 2018 and 2020), 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.

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

See Note 15 to the consolidated financial statements for further discussion on 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.

Natural gas sales .

Revenues from sales of natural gas remained relatively constant with a decrease of $41 million over the prior year, or 2%.

Increased natural gas production volumes accounted for an approximate $358 million increase in year-over-year natural gas sales (calculated as the change in year-to-year volumes times the prior year average price), and decreases in our prices, excluding the effects of derivative settlements, accounted for an approximate $399 million decrease in year-over-year gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes).

Revenues from sales of NGLs increased $41 million, or 4%.

An increase in NGLs production volumes accounted for an approximate $386 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 $345 million decrease in year-over-year product revenues (calculated as the change in the year-to-year average price times current year production volumes).

Revenues from production of oil decreased from $187 million for the year ended December 31, 2018 to $178 million for the year ended December 31, 2019, a decrease of $10 million, or 5% due to increases in production offset by a decrease in prices.

During the year ended December 31, 2019, our natural gas prices and revenues included proceeds of $54 million from South Jersey Gas Company and South Jersey Resources Group, LLC (collectively, “SJGC”) in the South Jersey Litigation resulting from resolution of contractual issues.

These disputes with SJGC negatively affected our natural gas prices and revenues for prior periods including the year ended December 31, 2018.

Please see Note 15 to the consolidated financial statements for more information on the South Jersey Litigation.

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).

Commodity derivative fair value gains (losses).

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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, 2018 and 2019, our commodity hedges resulted in derivative fair value losses of $88 million and derivative fair value gains of $464 million, respectively.

The commodity derivative fair value gains (losses) included $243 million and $325 million of cash proceeds on gains on settled derivatives for the years ended December 31, 2018 and 2019, respectively.

Commodity derivative fair value gains (losses) for the years ended December 31, 2018 also include cash proceeds of $370 million related to derivatives that were monetized prior to their contractual settlement dates.

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.

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.

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.

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 increased from $142 million for the year ended December 31, 2018 to $147 million for the year ended December 31, 2019, an increase of 7%.

This increase is primarily due to a 19% increase in production.

On a per unit basis, lease operating expenses decreased from $0.14 per Mcfe for the year ended December 31, 2018 to $0.13 per Mcfe for the year ended December 31, 2019.

The decrease in lease operating expenses on a per Mcfe basis is primarily due to decreased water disposal costs resulting from improved operating efficiencies and cost reductions.

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.

Gathering, compression, processing, and transportation expense.

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

On a per Mcfe basis, total gathering, compression, processing, and transportation expenses increased from $1.81 per Mcfe for the year ended December 31, 2018 to $1.92 per Mcfe for the year ended December 31, 2019.

This per Mcfe increase was primarily the result of higher processing and transportation costs as NGLs production made up a higher percentage of our overall production and the Mariner East 2 NGL pipeline went into service in January 2019.

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.

Production and ad valorem tax expense.

Total production and ad valorem taxes increased from $122 million for the year ended December 31, 2018 to $124 million for the year ended December 31, 2019 primarily as a result of an increase in production revenues.

On a per Mcfe basis, production and ad valorem taxes decreased from $0.12 per Mcfe for the year ended December 31, 2018 to $0.11 per Mcfe for the year ended December 31, 2019.

Production and ad valorem taxes as a percentage of natural gas, NGLs, and oil revenues remained relatively constant at approximately 3.4% for the years ended December 31, 2018 and 2019.

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.

Production and ad valorem taxes as a percentage of natural gas revenues remained at 6% in each of the years ended December 31, 2019 and 2020.

Exploration expense .

Exploration expense representing expenses incurred for unsuccessful lease acquisition efforts decreased from $5 million for the year ended December 31, 2018 to $1 million for the year ended December 31, 2019 as leasing activities declined.

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 .

Impairment of oil and gas properties increased from $549 million for the year ended December 31, 2018 to $1.3 billion for the year ended December 31, 2019 primarily due to impairment of proved properties in the Ohio Utica Shale.

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

If the carrying amount 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.

The carrying amount of the Utica Shale exceeded the estimated undiscounted future cash flows based on future strip commodity prices at September 30, 2019.

We estimated the fair value of the Utica Shale assets based on sales of other properties.

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

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 increased from $842 million for the year ended December 31, 2018 to $893 million for the year ended December 31, 2019 for the exploration and production segment, primarily due to an increase in production and the related depletion associated with that production.

DD&A per Mcfe decreased from $0.85 per Mcfe during the year ended December 31, 2018 to $0.76 per Mcfe during the year ended December 31, 2019 due to a reduction in the cost basis of producing properties as a result of the impairments discussed above.

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) increased from $132 million for the year ended December 31, 2018 to $139 million for the year ended December 31, 2019, primarily due to increases in legal and other expenses related to the Transactions.

On a per unit basis, general and administrative expense excluding equity-based compensation decreased by 8%, from $0.13 per Mcfe during the year ended December 31, 2018 to $0.12 per Mcfe during the year ended December 31, 2019 as the increase in expenses from 2018 to 2019 was offset by a 19% increase in production.

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.

Equity-based compensation expense .

Noncash equity-based compensation expense decreased from $49 million for the year ended December 31, 2018 to $21 million for the year ended December 31, 2019 as a result of equity award forfeitures, non-recognition of performance share unit expense, and a large vesting of shares with higher fair values during 2018 resulting in lower expense going forward.

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.

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

See Note 9 to the consolidated financial statements for more information on equity-based compensation awards.

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.

Marketing Segment Results for the Year Ended December 31, 2019 Compared to the Year Ended December 31, 2020

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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.

Marketing revenues were $553 million and $292 million and expenses were $686 million and $550 million for the years ended December 31, 2018 and 2019, respectively, related to these activities.

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

This includes firm transportation costs of $171 million and $252 million for the year ended December 31, 2018 and 2019, respectively, which increased primarily due to costs associated with the Rockies Express Pipeline that delivers natural gas to the Chicago and Michigan markets.

Additionally, the marketing segment recorded a fair value gain of $94 million for the year ended December 31, 2018 related to several natural gas purchase and sales contracts that were determined to be derivative instruments.

See Note 11 to the consolidated financial statements for more information on these marketing derivative fair value gains.

Operating losses on our marketing activities were $227 million (excluding the derivative fair value gains), or $0.23 per Mcfe, and $258 million, or $0.22 per Mcfe, for the years ended December 31, 2018 and 2019, respectively.

Based on current projected 2020 annual production guidance, we estimate that we could incur annual net marketing costs of $0.10 per Mcfe to $0.12 per Mcfe in 2020 for unutilized transportation capacity depending on the amount of unutilized capacity that can be marketed to third parties or utilized to transport third party gas and capture positive basis spreads net of variable transportation costs.

Our net marketing expense is expected to decrease in years subsequent to 2020 depending on our utilization of our transportation capacity, which will be affected by our future production and how much, if any, future excess transportation can be marketed to third parties.

Our production outlook beyond 2020 assumes production growth and higher utilization of our transportation capacity.

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

Throughout 2018 and during the period from January 1, 2019 through March 12, 2019, the results of Antero Midstream Partners were included in our consolidated financial statements.

Effective March 13, 2019, the results of Antero Midstream Partners

were no longer consolidated in our results.

See Note 3 to the consolidated financial statements for further discussion on the Transactions.

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 decreased from $1.0 billion for the year ended December 31, 2018, to $793 million, which included amortization of customer relationships of $57 million, for the year ended December 31, 2019, a decrease of $236 million, or 23%.

The decrease in operating revenue was primarily due to a decrease in fresh water deliveries, which was partially offset by an increase in other fluid handling services for the year ended December 31, 2019.

Total operating expenses related to the segment increased from $426 million for the year ended December 31, 2018 to $1.2 billion for the year ended December 31, 2019.

The increase was primarily due impairments of $463 million on Antero Midstream’s wastewater treatment facility, related goodwill and customer relationships, and $298 million related to the water handling segment goodwill as a result of the annual impairment test.

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.

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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 delivers 219 million barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020.

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.

Impairment of equity investment .

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

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

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.

Interest expense decreased from $287 million for the year ended December 31, 2018 to $228 million for the year ended December 31, 2019 due to decreased interest rates on Credit Facility borrowings and decreased borrowings outstanding during 2019.

Interest expense includes approximately $13 million and $11 million of non-cash amortization of deferred financing costs for the years ended December 31, 2018 and 2019, respectively.

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.

Income tax benefit.

Income tax benefit decreased from $129 million for the year ended December 31, 2018 to $74 million for the year ended December 31, 2019, primarily due to the reduction in noncontrolling interest and the impact on deferred tax of changes in our blended statutory rate.

For the year ended December 31, 2019, our overall effective tax rate was different than the statutory rate of 21% primarily due to the effects of noncontrolling interest and state taxes.

See Note 13 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K for information regarding our income tax provision for the years ended December 31, 2018 and 2019.

At December 31, 2018 and December 31, 2019, we had U.S.

federal and state NOL carryforwards of approximately $2.2 billion and $2.0, respectively.

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.

As of December 31, 2019 and 2020, we had U.S.

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

Many of these NOLs expire at various dates between 2032 and 2040 while others have no expiration date.

Future interpretations relating to the passage of the Tax Cuts and Jobs Act that vary from our current interpretation, and possible changes to state tax laws in response to the recently enacted federal legislation, may have a significant effect on our future taxable position.

Potential future legislation or the imposition of new or increased taxes may have a significant effect on our future taxable position.

The impact of any such change would be recorded in the period in which such interpretation is received or legislation is enacted.

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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, and distributions/dividends from unconsolidated affiliates.

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 use of cash has been for the exploration, development, and acquisition of oil and natural gas properties.

As we pursue the development of our reserves, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities, and liquidity requirements.

As we develop our reserves, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities, and liquidity requirements.

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

As of December 31, 2019, we had 2,385 potential horizontal well locations in our proved, probable, and possible reserve base, which will take many years to develop.

More specifically, our proved undeveloped reserves will require an estimated $2.6 billion of development capital over the next five years in order to fully develop the properties associated with our proved reserves.

Based on strip prices as of December 31, 2019, we believe that cash flows from operations will be sufficient to finance such future development costs.

For a discussion of the risks related to development of our proved undeveloped reserves, see “Item 1A.

Risk Factors—The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.

Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.”

In addition, we may from time to time repurchase shares of our common stock under our share repurchase program.

Under our share repurchase program, we repurchased and retired 13,390,617 common shares for $39 million during the year ended December 31, 2019.

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

Any such repurchases will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

During the fourth quarter of 2019, we repurchased $225 million principal amount of debt at a 17% weighted average discount, including a portion of our 5.375% senior notes due November 1, 2021 and our 5.125% senior notes due December 1, 2022.

We recognized a gain of approximately $36 million on the early extinguishment of the debt repurchased.

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

The borrowing base is redetermined annually based on certain factors including our reserves, natural gas, NGLs, and oil commodity prices, and the value of our hedge portfolio.

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 2021.

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

Our commodity hedge position provides us with additional liquidity as 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, NGLs, or oil.

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.

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

For the year ended December 31, 2019, our total consolidated capital expenditures were approximately $1.4 billion, including drilling and completion expenditures of $1.3 billion, leasehold additions of $89 million, gathering and compression expenditures of $48 million, water handling and treatment expenditures of $24 million, and other capital expenditures of $7 million.

Our capital budget for 2020 is $1.2 billion.

Our budget includes:

$1.15 billion for drilling and completion and $50 million for leasehold expenditures.

2020 Capital Spending and 2021 Capital Budget

For the year ended December 31, 2020, our total consolidated capital expenditures were approximately $785 million, including drilling and completion expenditures of $735 million, leasehold additions of $48 million, and other capital expenditures of $2 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.

We do not budget for acquisitions.

During 2020, we plan to operate an average of four drilling rigs and three to four completion crews and we plan to complete 120 to 130 horizontal wells in the Marcellus and Utica Shales in 2020.

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.

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

Furthermore, in December 2019, we announced an asset sale program pursuant to which we expect to execute between $750 million and $1.0 billion asset monetization opportunities through 2020, which can include hedge restructuring and dispositions of lease acreage, minerals, producing properties or our shares of Antero Midstream common stock.

We expect to use the proceeds from

this program to reduce indebtedness.

We initiated this program by selling $100 million of our shares of Antero Midstream common stock in December 2019.

Based on strip prices as of December 31, 2019, we believe that funds from operating cash flows, available borrowings under the Credit Facility, capital market transactions, distributions/dividends from unconsolidated affiliates and proceeds from our asset sale program 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.

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.”

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Net cash used in investing activities

Net cash provided by financing activities

Net cash provided by (used in) financing activities

Effect of deconsolidation of Antero Midstream Partners LP

Net decrease in cash and cash equivalents

Our consolidated cash flow statements for the years ended December 31, 2017, 2018 and 2019 includes 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, 2017, 2018 and 2019 are not representative of our expected future cash flows.

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

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.

Year Ended December 31, 2019 Compared to Year Ended December 31, 2020

Cash Flows Provided by Operating Activities

Net cash provided by operating activities was $2.1 billion and $1.1 billion for the years ended December 31, 2018 and 2019, respectively.

Cash flow from operations decreased from 2018 to 2019 primarily due to an increase in gathering, compression, processing, and transportation costs due to the deconsolidation of Antero Midstream Partners and a $370 million decrease in proceeds from derivative monetizations and settlements of as compared to the prior period.

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.

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

Prices for natural gas, NGLs, and oil are primarily determined by prevailing market conditions.

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

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.

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

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Quantitative and Qualitative Disclosures About Market Risk.”

Cash Flows Used in Investing Activities

Cash flows used in investing activities decreased from $2.4 billion for the year ended December 31, 2018 to $1.0 billion for the year ended December 31, 2019, primarily due to a decrease in capital expenditures of $788 million during the year ended December 31, 2019 as compared to the same period in 2018, and $297 million in proceeds received in connection with the Transactions in the year ended December 31, 2019.

See Note 3 to the consolidated financial statements for further discussion on the Transactions.

In addition, cash flows in investing activities included expenditures of Antero Midstream Partners related to construction of midstream and water handling and treatment infrastructure and investments in joint ventures through March 12, 2019.

Effective March 13, 2019, these expenditures are no longer consolidated in our results.

Excluding Antero Midstream Partners, capital expenditures were $1.7 billion and $1.3 billion for the years ended December 31, 2018 and 2019, respectively.

Total capital expenditures for oil and gas properties decreased from $1.5 billion during the year ended December 31, 2018 to $1.2 billion during the year ended December 31, 2019 due to a decrease in drilling and completion activity, increased efficiency and

cost reductions.

Capital expenditures for water handling and treatment systems decreased $73 million from $98 million for the year ended December 31, 2018 to $24 million for the year ended December 31, 2019, and capital expenditures for gathering and compression systems decreased $396 million from $444 million to $48 million for the year ended December 31, 2019.

The decreases in capital expenditures for both the water handling and treatment systems, and the gathering and compression systems are due to the year ended December 31, 2019 only including Antero Midstream Partners’ activity through the deconsolidation date of March 12, 2019 as compared to the year ended December 31, 2018 including Antero Midstream Partners’ activity for the entire period.

Additionally, investments in joint ventures by Antero Midstream Partners decreased $111 million from $136 million during the year ended December 31, 2018 to $25 million during the year ended December 31, 2019 due to the deconsolidation as of March 12, 2019.

Our consolidated exploration and production capital budget for 2020 is $1.2 billion.

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 to levels that do not generate an acceptable level of corporate returns, or costs increase to levels that do not generate an acceptable level of corporate returns, we could choose to 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.

We routinely monitor and adjust our capital expenditures in response to changes in commodity prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows, and other factors both within and outside our control.

Cash Flows Provided by Financing Activities

During the years ended December 31, 2018 and 2019, net cash flows provided by financing activities were $240 million, and $558 million, respectively.

The increase of $318 million was primarily as a result of capital market transactions and changes in long term debt including an issuance of senior notes of $650 million partially offset by a repayment of senior notes of $191 million.

In addition, under the share repurchase program launched in the fourth quarter of 2018, Antero repurchased and retired 9,144,796 common shares for $129 million during the year ended December 31, 2018 and 13,390,617 common shares for $39 million during the year ended December 31, 2019.

Net borrowings on the Credit Facility decreased from $660 million for the year ended December 31, 2018 to $232 million for the year ended December 31, 2019, primarily due to the additional funding provided by the issuance of senior notes described above.

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.

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.

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

Year Ended December 31, 2018 Compared to Year Ended December 31, 2019

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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 annual redeterminations.

At December 31, 2019, the borrowing base was $4.5 billion and lender commitments were $2.64 billion.

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

As of December 31, 2020, the borrowing base was $2.85 billion and lender commitments were $2.64 billion.

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

At 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.

At December 31, 2018, we had $405 million of borrowings and $685 million of letters of credit outstanding under the Credit Facility, with a weighted average interest rate of 3.95%.

The maturity date of the Credit Facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the earliest stated redemption date of any series of Antero’s senior notes, then outstanding.

Under the Credit Facility, “Investment Grade Period” is a period that, as long as no event of default has occurred, commences when Antero elects to give notice to the Administrative Agent that Antero has received at least one of either (i) a BBB- or better rating from Standard & Poor’s or (ii) a Baa3 or better rating from Moody’s (an “Investment Grade Rating”).

An Investment Grade Period can end at Antero’s election.

During any period that is not an Investment Grade Period, the Credit Facility is ratably secured by mortgages on substantially all of Antero’s properties and guarantees from Antero’s restricted subsidiaries, as applicable.

During an Investment Grade Period, the liens securing the obligations under the Credit Facility shall be automatically released (subject to the provisions of the Credit Facility).

The Credit Facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to

working capital and interest coverage ratios.

Interest is payable at a variable rate based on LIBOR or the prime rate, determined by Antero’s election at the time of borrowing.

During an Investment Grade Period, the margin applicable to the Credit Facility borrowings is determined with reference to Antero’s credit rating and ranges from 0.125% to 0.50% lower than rates during a period that is not an Investment Grade Period, depending on Antero’s credit rating and utilization under the Credit Facility.

During any period that is not an Investment Grade Period, the margin applicable to the Credit Facility borrowings is determined with reference to utilization under the Credit Facility.

For information concerning the effect of changes in interest rates on interest payments under these facilities, see “Item 7A.

Quantitative and Qualitative Disclosure About Market Risk.”

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:

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

During any period that is not an Investment Grade Period, the Credit Facility requires Antero and its restricted subsidiaries to maintain the following two financial ratios as of the end of each fiscal quarter:

● a current ratio, which is the ratio of our current assets (including any unused borrowing base under the facilities and excluding derivative assets) to our current liabilities (excluding derivative liabilities), of not less than 1.0 to 1.0;

● an interest coverage ratio, which is the ratio of EBITDAX (as defined by the credit facility agreement) to interest expense over the most recent four quarters, of not less than 2.5 to 1.0.

During an Investment Grade Period, the Credit Facility requires Antero and its restricted subsidiaries to maintain the following three financial ratios as of the end of each fiscal quarter:

● a ratio of total Indebtedness (as defined by the credit facility agreement) to EBITDAX (as defined by the credit facility agreement) of not more than 4.25 to 1.00;

● a ratio of PV-9 reflected in the most recently delivered reserve report to its total Indebtedness of not less than 1.50 to 1.00, but only if Antero does not have both (i) an unsecured rating from Moody’s of Baa3 or better and (ii) an unsecured rating from S&P of BBB- or better.

We were in compliance with the applicable covenants and ratios as of December 31, 2018 and December 31, 2019.

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.

At December 31, 2019, our current ratio was 5.25 to 1.0 (based on the $4.5 billion borrowing base under the Credit Facility) and our interest coverage ratio was 5.95 to 1.0.

Antero Resources Senior Notes.

On November 5, 2013, We issued the 2021 notes at par.

The 2021 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility.

The 2021 notes rank pari passu to our other outstanding senior notes.

The 2021 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by our wholly owned subsidiaries and certain of its future restricted subsidiaries.

Interest on the 2021 notes is

payable on May 1 and November 1 of each year.

We may redeem all or part of the 2021 notes at any time at a redemption price of 100.00%.

If we undergo a change of control followed by a rating decline, the holders of the 2021 notes will have the right to require us to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2021 notes, plus accrued and unpaid interest.

On May 6, 2014, we issued the 2022 notes at par.

On September 18, 2014, we issued an additional $500 million of the 2022 notes at 100.5% of par.

The 2022 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility.

The 2022 notes rank pari passu to our other outstanding senior notes.

The 2022 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by our wholly owned subsidiaries and certain of its future restricted subsidiaries.

Interest on the 2022 notes is payable on June 1 and December 1 of each year.

We may redeem all or part of the 2022 notes at any time at redemption prices ranging from 101.281% currently to 100.00% on or after June 1, 2020.

If we undergo a change of control followed by a rating decline, the holders of the 2022 notes will have the right to require us to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2022 notes, plus accrued and unpaid interest.

On March 17, 2015, we issued $750 million of 5.625% senior notes due June 1, 2023 (the “2023 notes”) at par.

The 2023 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility.

The 2023 notes rank pari passu to our other outstanding senior notes.

The 2023 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by our wholly owned subsidiaries and certain of its future restricted subsidiaries.

Interest on the 2023 notes is payable on June 1 and December 1 of each year.

We may redeem all or part of the 2023 notes at any time at redemption prices ranging from 102.813% to 100.00% on or after June 1, 2021.

If we undergo a change of control followed by a rating decline, the holders of the 2023 notes will have the right to require us to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2023 notes, plus accrued and unpaid interest.

On December 21, 2016, we issued $600 million of 5.00% senior notes due March 1, 2025 (the “2025 notes”) at par.

The 2025 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility.

The 2025 notes rank pari passu to our other outstanding senior notes.

The 2025 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ wholly owned subsidiaries and certain of its future restricted subsidiaries.

Interest on the 2025 notes is payable on March 1 and September 1 of each year.

We may redeem all or part of the 2025 notes at any time on or after March 1, 2020 at redemption prices ranging from 103.750% on or after March 1, 2020 to 100.00% on or after March 1, 2023.

In addition, on or before March 1, 2020, we may redeem up to 35% of the aggregate principal amount of the 2025 notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.00% of the principal amount of the 2025 notes, plus accrued and unpaid interest.

At any time prior to March 1, 2020, we may also redeem the 2025 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2025 notes plus a “make-whole” premium and accrued and unpaid interest.

If we undergo a change of control following a ratings decline, the holders of the 2025 notes will have the right to require us to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2025 notes, plus accrued and unpaid interest.

We used the proceeds from the issuances of the senior notes to repay borrowings outstanding under the Credit Facility, redeem previously issued senior notes, and for development of our oil and natural gas properties.

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, 2018 and 2019.

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.

Senior Unsecured Notes

The following table summarizes certain material terms of our senior unsecured notes and convertible notes outstanding as of December 31, 2020:

Convertible Notes

Outstanding principal (in thousands)

Interest rate

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

Interest payment dates

Make-whole redemption date (1)

January 15, 2026

February 1, 2027

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.

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.

Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, and other factors.

Any such repurchases will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

The amounts involved could be material.

During the fourth quarter of 2019, we repurchased $225 million principal amount of debt at a 17% weighted average discount, including a portion of our 2021 notes and our 2022 notes.

The Company recognized a gain of approximately $36 million on the early extinguishment of the debt repurchased.

Treasury Management Facility.

We have a revolving note with a lender that provides for up to $25 million of cash management obligations in order to facilitate our daily treasury management.

Borrowings under the revolving note are secured by the collateral for the Credit Facility.

Borrowings under the revolving note bear interest at the lender’s prime rate plus 1.0%.

The note matures on June 1, 2020.

At December 31, 2018, there was $5.4 million included in “Other current liabilities” on the Company’s Consolidated Balance Sheet, and at December 31, 2019, there were no outstanding borrowings under this revolving note.

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.

We were in compliance with such covenants as of December 31, 2019 and 2020.

Contractual Obligations

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

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.

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,

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Processing, gathering, and compression services (6)

Drilling and completion

Land payment obligations (7)

(1) Includes outstanding principal amounts at December 31, 2019.

(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 maturity date of the Credit Facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the earliest stated redemption of any series of our senior notes then outstanding.

(2) Our senior notes include the 2021 notes, the 2022 notes, the 2023 notes, and the 2025 notes.

(3) Includes contracts for services provided by drilling rigs and completion fleets, processing, gathering and compression services agreements, and office and equipment leases that expire at various dates from January 2020 through November 2021.

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 12 to the consolidated financial statements for more information on our operating and finance leases.

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;

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.

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

This includes fees to be paid to the Joint Venture owned by Antero Midstream and MarkWest.

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.

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

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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.

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

assumptions had been used.

We evaluate our estimates and assumptions on a regular basis.

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We provide an expanded discussion of our more significant accounting policies, estimates and judgments below.

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

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

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

financial statements.

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

Successful Efforts Method

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The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, natural gas, NGLs, and oil prices, cost changes, technological advances, new geological or geophysical data, or other economic

Accordingly, reserve estimates are generally different from the quantities of natural gas, NGLs, and oil that are ultimately recovered.

We cannot predict the amounts or timing of future reserve revisions.

If such revisions are significant, they could significantly affect the future amortization rates of capitalized costs and result in asset impairments that may be material.

Any significant revisions could affect the future amortization rates of capitalized costs and result in a material asset impairment.

Impairment of Proved Properties

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

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

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

Based on current future commodity prices, we currently do not anticipate having to record any impairment charge for our proved properties in the near future.

We estimate that if strip prices were to decline by approximately 3.25% per from future pricing levels at December 31, 2019, 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 3.25% from year-end 2019 levels before further evaluation of those properties would be required in order to determine if an impairment charge would be necessary under GAAP.

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.

Fair Value Measurement

The Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification Topic 820, Fair Value Measurements and Disclosures , clarifies the definition of fair value, establishes a framework for measuring fair value, and sets forth disclosure requirements about fair value measurements.

The FASB ASC Topic 820, Fair Value Measurements and Disclosures , clarifies the definition of fair value, establishes a framework for measuring fair value, and sets forth disclosure requirements about fair value measurements.

This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., the initial recognition of asset retirement obligations and impairments of long- lived assets).

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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.

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

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

We evaluate our equity method investment for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value.

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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 9 to the consolidated financial statements for further discussion on our equity method investments.

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

The fair value of the equity method investment in Antero Midstream was based on the quoted market common stock price of Antero Midstream at December 31, 2019 (Level 1).

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).

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 and the utilization of NOL carryforwards.

Our deferred tax assets and liabilities result from temporary differences between tax and financial statement income, primarily from

derivatives, oil and gas properties, and net operating loss carryforwards.

We have generated net operating loss carryforwards, some of which expire at various dates from 2032 to 2038 while others have no expiration date, which resulted in the recognition of significant deferred tax assets.

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.

As of December 31, 2020, we have U.S.

federal and state NOLs expiring at various dates from 2032 to 2040 while others have no expiration date, which resulted in the recognition of significant deferred tax assets.

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

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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.

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 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, 2019, we have recognized a valuation allowance of $47 million for net operating loss carryforwards we do not expect to realize that are primarily attributable to states in which we no longer operate.

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.

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

In August 2018, the FASB issued ASU No.

2018-13, “Fair Value Measurement:

Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement,” which provides changes to certain fair value disclosure requirements.

This ASU is effective for annual reporting periods beginning after December 15, 2019 and interim periods within those annual periods, with early adoption permitted.

The adoption of this update is not expected to have a material impact on our consolidated financial statements.

On August 5, 2020, the FASB issued Accounting Standards Update 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.

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

Off-Balance Sheet Arrangements

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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