ANTERO RESOURCES Corp (AR) FY 2021 MD&A

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in natural gas, NGLs and oil prices, the timing of planned capital expenditures, our ability to fund our development programs, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, impacts of world health events, including the COVID-19 pandemic, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements.” Also, see the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

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

Our Company

We are an independent oil and natural gas company engaged in the development, production, exploration and acquisition of natural gas, NGLs and oil properties located in the Appalachian Basin. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to develop our reserves and production, primarily on our existing multi-year inventory of drilling locations.

We have assembled a portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and repeatability. Our drilling opportunities are focused in the Appalachian Basin. As of December 31, 2021, we held approximately 502,000 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, 2021, our estimated proved reserves were 17.7 Tcfe, consisting of 10.2 Tcf of natural gas, 718 MMBbl of assumed recovered ethane, 501 MMBbl of C3+ NGLs and 36 MMBbl of oil. This represents a 0.5% increase in estimated proved reserves from December 31, 2020. These reserve estimates have been prepared by our internal reserve engineers and management and audited by our independent reserve engineers. As of December 31, 2021, we had approximately 2,083 potential horizontal well locations on our existing leasehold acreage that were classified as proved, probable and possible.

We operate in the following reportable segments: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing of excess firm transportation capacity; and (iii) midstream services through our equity method investment in Antero Midstream Corporation (“Antero Midstream”). All of our operations are conducted in the United States.

COVID-19 Pandemic

Since the start of the COVID-19 pandemic, governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, among other actions, which caused a significant decrease in activity in the global economy and the demand for oil, and to a lesser extent, natural gas and NGLs. As vaccines have become widely available, social distancing guidelines, travel restrictions and stay-at-home orders have eased, activity in the global economy has increased and demand for oil, natural gas and NGLs and related commodity pricing, has improved. However, new variants of the virus could cause further commodity market volatility and resulting financial market instability, and these are variables beyond our control that may adversely impact our generation of funds from operating cash flows, distributions from unconsolidated affiliates, available borrowings under our Credit Facility and our ability to access the capital markets.

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

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these regulations while taking steps to protect the health and safety of our workers. We have implemented protocols to reduce the risk of an outbreak within our field operations and corporate offices, and these protocols have not reduced Antero Resources’ production and our throughput in a significant manner. A substantial portion of our non-field level employees currently operate in remote work from home arrangements, and we have been able to maintain a consistent level of effectiveness through these arrangements, including maintaining our day-to-day operations, our financial reporting systems and our internal control over financial reporting. We continue to monitor the COVID-19 environment in order to (i) protect the health and safety of our employees and contract workers and (ii) to determine when a return to in-office working arrangements will be appropriate.

Our supply chain has not experienced any significant interruptions as a result of the COVID-19 pandemic. The lack of a market or available storage for any one NGL product or oil could result in our having to delay or discontinue well completions and commercial production or shut in production for other products because we cannot curtail the production of individual products in a meaningful way without reducing production of other products. Potential impacts of these constraints may include partial shut-in of production, although we are not able to determine the extent of shut-ins or for how long they may last. However, because some of our wells produce rich gas, which is processed, and some produce dry gas, which does not require processing, we can change the mix of products that we produce and wells that we complete to adjust our production to address takeaway capacity constraints for certain products. For example, we can shut-in rich gas wells and still produce from our dry gas wells if processing or storage capacity of NGL products becomes limited or constrained. Prior to the COVID-19 pandemic, we had developed a diverse set of buyers and destinations, as well as in-field and off-site storage capacity for our condensate volumes. As a result of the pandemic, we have expanded our customer base and our condensate storage capacity within the Appalachian Basin.

Our natural gas, NGLs and oil producing properties are located in the liquids-rich Appalachian Basin. We maintain an active hedging program designed to mitigate volatility in commodity prices and to protect certain of our expected future cash flows for our future operations and capital spending plans. All of our hedges are financial hedges and do not have physical delivery requirements. As such, any decreases in anticipated production, such as a result of decreased development activity, would not impact our ability to realize the benefits of or reduce the obligations for our hedges. For the year ending December 31, 2022, we have hedged through fixed price contracts the sale of 422 Bcf of natural gas at a weighted average price of $2.50 per MMBtu, a swaption agreement for 156 Bcf of natural gas production at a weighted average index price of $2.77 per MMBtu and basis swaps for 22 Bcf with a weighted average pricing differential of $0.515 per MMBtu.

In addition, our borrowing capacity is directly impacted by the amount of financial assurance that we are required to provide in the form of letters of credit to third parties, primarily pipeline capacity providers. The amount of financial assurance we provided has not increased during the COVID-19 pandemic and, thus far, we have not experienced any losses due to counterparty risk. However, our ability to limit any additional financial assurance we are required to provide, as well as to protect ourselves from the counterparty risk of our financial hedges, may be limited in the future. Since the onset of the COVID-19 pandemic, we have timely serviced our debt and other obligations.

On October 26, 2021, we entered into the New Credit Facility with a borrowing base of $3.5 billion and lender commitments of $1.5 billion. Lender commitments were reduced by $1.1 billion from the previous commitments of $2.64 billion to better align with our expected future liquidity needs. As of December 31, 2021, we had no borrowings under our New Credit Facility and had outstanding letters of credit of $531 million. We have not materially modified the terms of any other agreements. See Note 8—Long-Term Debt to the consolidated financial statements and “—Capital Resources and Liquidity—Debt Agreements—Credit Facility.”

As the global economy continues to recover from the effects of the COVID-19 pandemic, economic indicators have continued to strengthen. However, the economy has begun to experience elevated inflation levels as a result of global supply and demand imbalances resulting from the COVID-19 pandemic. For example, the United States Bureau of Labor and Statistics (“BLS”) consumer price index for all urban consumers increased 7% from December 31, 2020 to December 31, 2021 as compared to the average historical 10-year rate of 2%. Additionally, employment activity has also begun to strengthen as demonstrated by the United States BLS unemployment rate declining from a high of 15% in April 2020 to 4% in December 2021. Inflationary pressures and labor shortages could result in increases to our operating and capital costs that are not fixed, renegotiation of contracts and/or supply agreements and higher labor costs, among others. These economic variables are beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.

Recent Developments and Highlights

Credit Facility

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

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2026 or (ii) the day that is 180 days prior to the earliest stated redemption date of any series of our then outstanding senior notes.  Lender commitments were reduced by $1.1 billion from the previous commitments of $2.64 billion to better align with our expected future liquidity needs. See Note 8—Long-Term Debt to the consolidated financial statements and “—Capital Resources and Liquidity—Debt Agreements—Credit Facility” for more information.

Issuance of Senior Notes

On January 4, 2021, we issued $500 million of 8.375% senior notes due July 15, 2026 (the “2026 Notes”) at par. On January 26, 2021, we issued $700 million of 7.625% senior notes due February 1, 2029 (the “2029 Notes”) at par. The 2026 Notes and 2029 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2026 Notes and 2029 Notes rank pari passu to our other outstanding senior notes. The 2026 Notes and 2029 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by our wholly owned subsidiaries and certain of our future restricted subsidiaries. See “—Debt Agreements—Senior Unsecured Notes” below and Note 8—Long-Term Debt to the consolidated financial statements for more information.

Debt Repurchase Program

We fully redeemed all of our outstanding 5.125% senior notes due December 1, 2022 (the “2022 Notes”) at par, plus accrued and unpaid interest in the first quarter of 2021. During the second quarter of 2021, we fully redeemed all of our outstanding 5.625% senior notes due June 1, 2023 (the “2023 Notes”) at par, plus accrued and unpaid interest.

On July 1, 2021, we redeemed $175 million of the principal amount of our 2026 Notes at a redemption price of 108.375% of the principal amount thereof, plus accrued and unpaid interest. Immediately following the redemption, there were $325 million aggregate principal amount of 2026 Notes outstanding.

On November 2, 2021, we redeemed $116 million of the principal amount of our 2029 Notes at a redemption price of 107.625% of the principal amount thereof, plus accrued and unpaid interest. Immediately following the redemption, there were $584 million aggregate principal amount of 2029 Notes outstanding.

On January 27, 2022, we announced that we will redeem all $585 million of the aggregate principal amount of our 5.00% senior notes due March 1, 2025 (the “2025 Notes”) at a redemption price of 101.25% of the principal amount thereof, plus accrued and unpaid interest on March 1, 2022. Immediately following the redemption, the 2025 Notes will be fully retired. The $7 million premium to the principal amount to be redeemed, along with the write-off of unamortized debt issuance costs, will be included in our loss on early debt extinguishment during the first quarter of 2022.

Convertible Notes Equitizations

On January 12, 2021, we completed a registered direct offering (the “January Share Offering”) of an aggregate of 31.4 million shares of our common stock at a price of $6.35 per share to certain holders of our 4.25% convertible senior notes due 2026 (the “2026 Convertible Notes”). We used the proceeds from the January Share Offering and approximately $63 million of borrowings under the Prior Credit Facility to repurchase from such holders $150 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions (the “January Convertible Note Repurchase,” and, collectively with the January Share Offering, the “January Equitization Transactions”).

On May 13, 2021, we completed a registered direct offering (the “May Share Offering”) of an aggregate of 11.6 million shares of our common stock at a price of $11.01 per share to certain holders of our 2026 Convertible Notes. We used the proceeds from the May Share Offering and approximately $26 million of borrowings under the Prior Credit Facility to repurchase from such holders $56 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions (the “May Convertible Note Repurchase,” and, collectively with the May Share Offering, the “May Equitization Transactions”).  See Note 8—Long-Term Debt to the consolidated financial statements for more information.

Capital Return Program

On February 15, 2022, our Board of Directors authorized a share repurchase program that allows the Company to repurchase up to $1.0 billion of outstanding common stock. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by us at our discretion and will depend on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements.

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

Drilling Partnership

On February 17, 2021, we announced the formation of a drilling partnership with QL Capital Partners (“QL”), an affiliate of Quantum Energy Partners, for our 2021 through 2024 drilling program. Under the terms of the arrangement, each year in which QL participates represents an annual tranche, and QL will be conveyed a working interest in any wells spud by us during such tranche year. For 2021 and 2022, we agreed to the estimated internal rate of return (“IRR”) or our capital budget for each annual tranche, and QL agreed to participate in the 2021 and 2022 tranches. For each subsequent year through 2024, we will propose a capital budget and estimated IRR for all wells to be spud during such year and, subject to the mutual agreement of the parties that the estimated IRR for the year exceeds a specified return, QL will be obligated to participate in such tranche. We develop and manage the drilling program associated with each tranche, including the selection of wells. Additionally, for each annual tranche in which QL participates, together with QL, we will enter into assignments, bills of sale and conveyances pursuant to which QL will be conveyed a proportionate working interest percentage in each well spud in that year, which conveyances will not be subject to any reversion.

Under the terms of the arrangement, QL funded 20% of development capital for wells spud in 2021 and (i) is expected to fund 15% of development capital for wells spud in 2022 and (ii) between 15% and 20% of development capital for wells spud in each of 2023 and 2024, which funding amounts represent QL’s proportionate working interest in such wells. Additionally, we may receive a carry in the form of a one-time payment from QL for each annual tranche if the IRR for such tranche exceeds certain specified returns, which will be determined no earlier than October 31 and no later than December 1 following the end of each tranche year. Capital costs in excess of, and cost savings below, a specified percentage of budgeted amounts for each annual tranche will be for our account. Subject to the preceding sentence, for any wells included in a tranche, QL is obligated and responsible for its working interest share of costs and liabilities, and is entitled to its working interest share of revenues, associated with such wells for the life of such wells. If we present a capital budget for an annual tranche with an estimated IRR equal to or exceeding a specified return that QL in good faith believes is less than such specified return and QL elects not to participate, we will not be obligated to offer QL the opportunity to participate in subsequent annual tranches. See Note 3—Transactions to the consolidated financial statements for more information.

Overriding Royalty Interest Additional Contributions

On June 15, 2020, we announced the consummation of a transaction with an affiliate of Sixth Street Partners, LLC (“Sixth Street”) relating to certain overriding royalty interests across our existing asset base (the “ORRIs”).  In connection with the transaction, we contributed the ORRIs to a newly formed subsidiary, Martica, and Sixth Street at the initial closing contributed $300 million in cash (subject to customary adjustments) and agreed to contribute up to an additional $102 million in cash if certain production thresholds attributable to the ORRIs were achieved in the third quarter of 2020 and first quarter of 2021.  All cash contributed by Sixth Street was distributed to us.  We met the applicable production thresholds related to the third quarter of 2020 and first quarter of 2021 as of September 31, 2020 and March 31, 2021, respectively. We received a $51 million cash distribution during each of the years ended December 31, 2020 and 2021.  See Note 4—Transactions to the consolidated financial statements for more information.

Sources of Our Revenues

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Principal Components of Our Cost Structure

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Results of Operations

We have three operating segments: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing and utilization of excess firm transportation capacity gathering and processing; and (iii) midstream services through our equity method investment in Antero Midstream. Revenues from Antero Midstream’s operations were primarily derived from intersegment transactions for services provided to our exploration and production operations. All intersegment transactions were eliminated upon consolidation, including revenues from water handling and treatment services provided by Antero Midstream, which we capitalized as proved property development costs. See Note 18—Reportable Segments to the consolidated financial statements for disclosures on our reportable segments. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity.

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

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

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

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

Natural gas sales. Revenues from sales of natural gas increased from $1.8 billion for the year ended December 31, 2020 to $3.4 billion, which included net litigation proceeds of $85 million, for the year ended December 31, 2021, an increase of $1.6 billion, or 90%. See Note 16—Contingencies to the consolidated financial statements for more information on the litigation proceeds.

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

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NGLs sales. Revenues from sales of NGLs increased from $1.2 billion for the year ended December 31, 2020 to $2.1 billion for the year ended December 31, 2021, an increase of $0.9 billion, or 85%. Lower NGLs production volumes during the year ended December 31, 2021 accounted for an approximate $0.2 billion decrease in year-over-year NGL revenues (calculated as the change in year-to-year volumes times the prior year average price), and increases in commodity prices, excluding the effects of derivative settlements, accounted for an approximate $1.1 billion increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Oil sales. Revenues from sale of oil increased from $112 million for the year ended December 31, 2020 to $201 million for the year ended December 31, 2021, an increase of $89 million, or 79%. Lower oil production volumes during the year ended December 31, 2021 accounted for a $23 million decrease in year-over-year oil sales revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our oil prices, excluding the effects of derivative settlements, accounted for an approximate $112 million increase in year-over-year oil sales revenues (calculated as the change in the year-to-year average price times current year production volumes).

Commodity derivative fair value gains (losses). To achieve more predictable cash flows, and to reduce our exposure to price fluctuations, we enter into fixed for variable price swap contracts, swaptions, basis swap contracts and collar contracts when management believes that favorable future sales prices for our production can be secured. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations. For the year ended December 31, 2020, our commodity hedges resulted in derivative fair value gains of $80 million. For the year ended December 31, 2021, our commodity hedges resulted in derivative fair value loss of $1.9 billion. Commodity derivative fair value gains included $795 million of net cash proceeds for gains on settled derivatives for the year ended December 31, 2020 as well as cash proceeds of $9 million related to derivatives that were monetized prior to their contractual settlement dates. For the year ended December 31, 2021, commodity derivative fair value losses included $1.2 billion of net cash payments on commodity derivative losses as well as $5 million for payments on derivatives that were settled prior to their contractual settlement dates.

Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled or monetized prior to settlement. Derivative asset or liability positions at the end of any accounting period may reverse to the extent future commodity prices increase or decrease from their levels at the end of the accounting period, or as gains or losses are realized through settlement. We expect continued volatility in commodity prices and the related fair value of our derivative instruments in the future. Additionally, the percentage of our production that is currently hedged for 2022 and beyond is lower than historic levels. See “—Capital Resources and Liquidity—Overview” for more information.

Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP increased from $15 million for the year ended December 31, 2020 to $45 million for the year ended December 31, 2021 as a result of the VPP closing in August 2020. Under the terms of the agreement, the production volumes are delivered at approximately $1.61 per MMBtu over the contractual term. See Note 4—Transactions to the consolidated financial statements for more information on this transaction.

Lease operating expense. Lease operating expense decreased from $99 million for the year ended December 31, 2020 to $97 million for the year ended December 31, 2021, a decrease of $2 million or 2% primarily due to lower production volumes. On a per unit basis, lease operating expenses remained consistent at $0.08 per Mcfe for the years ended December 31, 2020 and 2021.

Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense remained consistent at $2.5 billion for the years ended December 31, 2020 and 2021. This is primarily a result of higher overall costs between periods, which were fully offset by lower production volumes between periods. Gathering and compression costs increased from $0.64 per Mcfe for the year ended December 31, 2020 to $0.73 per Mcfe for the year ended December 31, 2021, primarily due to higher fuel costs as a result of increased natural gas prices and $48 million in incentive fee rebates from Antero Midstream Corporation earned during the year ended December 31, 2020 compared to $12 million in incentive fee rebates from Antero Midstream earned during the year ended December 31, 2021. Processing costs decreased from $0.69 per Mcfe for the year ended December 31, 2020 to $0.66 per Mcfe for the year ended December 31, 2021, due to a decrease in C3+ NGL volumes as compared to total production volumes between periods, partially offset by increased NGL pipeline and terminaling fees from higher NGL volumes taken in-kind between periods. Transportation costs increased from $0.60 per Mcfe for the year ended December 31, 2020 to $0.70 per Mcfe and for the year ended December 31, 2021, primarily due to increased utilization on higher tariff pipelines to the Midwest and Gulf Coast between periods.

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

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taxes increased from $0.08 per Mcfe for the year ended December 31, 2020 to $0.17 per Mcfe for the year ended December 31, 2021. Production and ad valorem taxes as a percentage of natural gas revenues remained at 6% in each of the years ended December 31, 2020 and 2021.

General and administrative expense. General and administrative expense (excluding equity-based compensation expense) increased from $111 million for the year ended December 31, 2020 to $125 million for the year ended December 31, 2021, an increase of $14 million or 12%, primarily due to higher salary and wage expense between periods, which includes our annual incentive program that was temporarily and significantly reduced during 2020. We had 522 and 519 employees as of December 31, 2020 and 2021, respectively. On a per unit basis, general and administrative expense excluding equity-based compensation increased by 25%, from $0.08 per Mcfe during the year ended December 31, 2020 to $0.10 per Mcfe during the year ended December 31, 2021 as a result of higher overall costs and lower production volumes between periods.

Equity-based compensation expense. Equity-based compensation expense decreased from $23 million for the year ended December 31, 2020 to $20 million for the year ended December, 2021, a decrease of $3 million or 12%, primarily due to equity award forfeitures partially offset by new awards granted to employees. When an equity award is forfeited, expense previously recognized for the award is reversed. See Note 10—Equity-Based Compensation and Cash Awards to the consolidated financial statements for more information.

Depletion, depreciation, and amortization expense. DD&A expense decreased from $862 million for the year ended December 31, 2020 to $742 million for the year ended December 31, 2021, a decrease of $120 million or 14%. DD&A per Mcfe decreased from $0.66 per Mcfe during the year ended December 31, 2020 to $0.62 per Mcfe during the year ended December 31, 2021 primarily due to increases in proved reserves as a result of higher commodity prices between periods.

Impairment of oil and gas properties. Impairment of oil and gas properties decreased from $224 million for the year ended December 31, 2020 to $91 million for the year ended December 31, 2021, a decrease of $133 million, or 60%, primarily related to lower impairments of expiring leases between periods. During both periods, we recognized impairments primarily related to expiring leases and initial costs related to pads we no longer plan to place into service.

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

Where feasible, we purchase and sell third-party natural gas and NGLs and market our excess firm transportation capacity, or engage third parties to conduct these activities on our behalf, in order to optimize the revenues from these transportation agreements. We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production in order to secure guaranteed capacity to favorable markets.

Net marketing expense decreased from $159 million, or $0.12 per Mcfe, for the year ended December 31, 2020 to $93 million, or $0.08 per Mcfe, for the year ended December 31, 2021. The decrease was driven by higher marketing volumes, which mitigated some of our excess firm transportation expense, and the reduction of our firm transportation commitments between periods.

Marketing revenue. Marketing revenue increased from $311 million for the year ended December 31, 2020 to $719 million for the year ended December 31, 2021, an increase of $408 million, or 131%, primarily due to increased commodity prices and marketing volumes between periods. Higher natural gas marketing volumes accounted for a $120 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our natural gas prices accounted for an approximate $248 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). Higher oil marketing volumes accounted for a $7 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our oil prices accounted for an approximate $22 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). Lower ethane marketing volumes accounted for a $4 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our ethane prices accounted for an approximate $21 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes). Higher NGL marketing volumes between periods also contributed to increased marketing revenues during the year ended December 31, 2021.

Marketing expense. Marketing expense increased from $469 million for the year ended December 31, 2020 to $812 million for the year ended December 31, 2021, an increase of $343 million, or 73%. Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related to current excess firm capacity. The cost of third-party natural gas, NGL and oil purchases increased approximately $309 million, $20 million and $24 million, respectively, between periods primarily due to higher commodity prices and increased marketing volumes between periods. Firm

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

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

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

Antero Midstream operating expense. Total operating expense related to the segment decreased from $1.0 billion for the year ended December 31, 2020 to $342 million for the year ended December 31, 2021 primarily due to impairments recorded by Antero Midstream during the year ended December 31, 2020 of $98 million on its freshwater pipelines and equipment and impairment of goodwill of $575 million. Antero Midstream’s impairment expense was $5 million for the year ended December 31, 2021 due to canceled project write-downs as well as a lower of cost or market adjustment for pipe inventory.

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

Interest expense. Interest expense decreased from $200 million for the year ended December 31, 2020 to $182 million for the year ended December 31, 2021, a decrease of $18 million, or 9%, primarily due to the reduction in debt as a result of repurchases of our unsecured senior notes, paydown of our Credit Facility and increased interest income between periods, partially offset by interest that accrued on the (i) 2026 Convertible Notes, which were issued in August 2020 and (ii) 2026 Notes, 2029 Notes and 2030 Notes, each of which was issued after December 31, 2020. Interest expense includes approximately $12 million of amortization of debt issuance costs and debt discounts and premiums for each of the years ended December 31, 2020 and 2021.

Gain (loss) on early extinguishment of debt. During the year ended December 31, 2020, we recognized a gain on early extinguishment of debt of $176 million related to $1.4 billion principal amount of debt that we repurchased at a weighted average discount of 13%. During the year ended December 31, 2021, we equitized $206 million aggregate principal amount of our 2026 Convertible Notes in privately negotiated exchange transactions, and as a result, we recognized a loss of $61 million, which represents the difference between the fair value of the liability component of the 2026 Convertible Notes and the carrying value of such notes. Additionally, during the year ended December 31, 2021, we redeemed (i) the remaining balance of $661 million of our 2022 Notes at par, plus accrued and unpaid interest; (ii) the remaining balance of $574 million of our 2023 Notes at par, plus accrued and unpaid interest; (iii) $175 million of our 2026 Notes at a redemption price of 108.375% of par, plus accrued and unpaid interest; and (iv) $116 million of our 2029 Notes at a redemption price of 107.625% of par, plus accrued and unpaid interest. For such redemptions, we recognized a $32 million loss on early extinguishment of debt. See Note 8—Long-Term Debt to the consolidated financial statements for more information.

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Loss on convertible note equitization. During the year ended December 31, 2021, we recognized a loss of $51 million for the January Equitization Transactions and the May Equitization Transactions, which represents the consideration paid in excess of the original terms of the 2026 Convertible Notes. See Note 8—Long-Term Debt to the consolidated financial statements for more information.

Impairment of equity method investment. In 2020, we determined that events and circumstances indicated that the carrying value of our investment in Antero Midstream had experienced an other-than-temporary decline, and we recorded impairment of $611 million. The fair value of the equity method investment in Antero Midstream was based on the quoted market share price of Antero Midstream as of March 31, 2020.

Income tax benefit. Income tax benefit decreased from $397 million, with an effective tax rate of 24%, for the year ended December 31, 2020 to $74 million, with an effective tax rate of 32%, for the year ended December 31, 2021, primarily due to a lower book loss between periods and the effects of a West Virginia apportionment tax law change enacted in 2021. For the year ended December 31, 2021, our overall effective tax rate was different than the statutory rate of 21% primarily due to the effects of state income taxes, the dividends received deduction, non-deductible equity-based compensation expenses and the effects of a West Virginia apportionment tax law change enacted in 2021. See Note 14—Income Taxes to our consolidated financial statements more

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

As of December 31, 2020 and 2021, we had U.S. federal and state net operating loss (“NOL”) carryforwards of approximately $2.3 billion. Many of these NOLs expire at various dates between 2025 and 2041 while others have no expiration date. Potential future legislation or the imposition of new or increased taxes may have a significant effect on our future taxable position. The impact of any such change would be recorded in the period in which such interpretation is received or legislation is enacted.

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

Refer to “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2020 for a discussion of the results of operations for the year ended December 31, 2019 compared to the year ended December 31, 2020.

Capital Resources and Liquidity

Overview

Our primary sources of liquidity have been through net cash provided by operating activities including proceeds from derivatives, borrowings under our Credit Facility, issuances of debt and equity securities, dividends from unconsolidated affiliates and proceeds from our asset sale program. Our primary use of cash has been for the exploration, development and acquisition of oil and natural gas properties. As we develop our reserves, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future success in growing our proved reserves and production will be highly dependent on net cash provided by operating activities and the capital resources available to us. For information about the impacts of COVID-19 on our capital resources and liquidity, see “—COVID-19 Pandemic.”

The New Credit Facility has a borrowing base of $3.5 billion and current lender commitments of $1.5 billion. The borrowing base is redetermined semi-annually based on certain factors including our reserves, natural gas, NGLs and oil commodity prices, and the value of our hedge portfolio. The next redetermination of the borrowing base is scheduled to occur in April 2022. For a discussion of the risks of a decrease in the borrowing base under the New Credit Facility, see “Item 1A. Risk Factors—The borrowing base under the New Credit Facility may be reduced if commodity prices decline, which could hinder or prevent us from meeting our future capital needs. We may also be required to post additional collateral as financial assurance of our performance under certain contractual arrangements, which could adversely impact available liquidity under our New Credit Facility.”

Our commodity hedge position provides us with additional liquidity because it provides us with the relative certainty of receiving a significant portion of our future expected revenues from operations despite potential declines in the price of natural gas. For the year ended December 31, 2021, approximately 70% of our volumes were hedged through fixed price commodity swap. Assuming our 2022 production is the same as our production in 2021, approximately 54% of our production for 2022 will be hedged through fixed price commodity swap. Our ability to make significant additional acquisitions for cash would require us to utilize borrowings on the New Credit Facility or obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us, or at all. The New Credit Facility is funded by a syndicate of 15 banks. We believe that the participants in the syndicate have the capability to fund up to their current commitment. If one or more banks should not be able to do so, we may not have the full availability of the New Credit Facility.

2021 Capital Spending and 2022 Capital Budget

For the year ended December 31, 2021, our total consolidated capital expenditures were approximately $749 million, including drilling and completion expenditures of $627 million, leasehold additions of $79 million and other capital expenditures of $43 million. Our net capital budget for 2022 is $740 million to $775 million. Our budget includes: a range of $675 million to $700 million for drilling and completion and a range of $65 million to $75 million for leasehold expenditures. We do not budget for acquisitions. During 2022, we plan to complete 60 to 65 net horizontal wells in the Appalachian Basin. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices.

Our capital budget may be adjusted as business conditions warrant as the amount, timing and allocation of capital expenditures is largely discretionary and within our control. If natural gas, NGLs and oil prices decline, or costs increase, to levels that do not generate an acceptable level of corporate returns, we may defer a significant portion of our budgeted capital expenditures

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until later periods to achieve the desired balance between sources and uses of liquidity, and to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows.

Based on strip prices as of December 31, 2021, we believe that net cash provided from operating activities and available borrowings under the New Credit Facility will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies for at least the next 12 months. For more information on our outstanding indebtedness, see “—Debt Agreements.”

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

Cash Flows

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

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

Operating Activities. Net cash provided by operating activities was $736 million and $1.7 billion for the years ended December 31, 2020 and 2021, respectively. Net cash provided by operating activities increased primarily due to increases in commodity prices both before and after the effects of settled commodity derivatives, decreased net marketing expense as well as decreased cash utilized for working capital, partially offset by decreased production and increased ad valorem taxes between periods.

Our net operating cash flows are sensitive to many variables, the most significant of which is the volatility of natural gas, NGLs and oil prices, as well as volatility in the cash flows attributable to settlement of our commodity derivatives. Prices for natural gas, NGLs and oil are primarily determined by prevailing market conditions. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets, storage capacity and other variables influence the market conditions for these products. For example, the impact of the COVID-19 outbreak reduced global demand for natural gas, NGLs and oil. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

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

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

Financing Activities. Net cash flows used in financing activities increased from $206 million for the year ended December 31, 2020 to $949 million for the year ended December 31, 2021. During the year ended December 31, 2021, we issued $500 million aggregate principal amount of 2026 Notes, $700 million aggregate principal amount of 2029 Notes and $600 million aggregate principal amount of 2030 Notes (net of $31 million of aggregate debt issuance costs), of which proceeds were used to (i) redeem $661 million aggregate principal amount of our 2022 Notes, which were fully retired, (ii) redeem $574 million aggregate principal amount of our 2023 Notes, which were fully retired, (iii) repurchase $5 million aggregate principal amount of our 2025 Notes, (iv) redeem $175 million aggregate principal amount of our 2026 Notes, (v) redeem $116 million aggregate principal of our 2029 Notes and (vi) repay all outstanding borrowings on our Credit Facility. Also, during the year ended December 31, 2021, we completed the January Share Offering and the May Share Offering and used the proceeds and approximately $89 million of borrowings under the Prior Credit Facility to repurchase $206 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions. Additionally, during the year ended December 31, 2021, we received a $51 million payment from Martica and distributed $97 million to the noncontrolling interest in Martica.

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During the year ended December 31, 2020, we repurchased (i) $1.1 billion aggregate principal amount of debt at a weighted average discount of 17% for $900 million of cash and (ii) $43 million of our common stock at weighted average price of $1.54 per share. During the year ended December 31, 2020, we issued $288 million principal amount of 2026 Convertible Notes. Additionally, we also received $351 million for the sale of a noncontrolling interest in Martica and distributed $36 million to the noncontrolling interest in Martica during the year ended December 31, 2020. See Note 4—Transactions and Note 8—Long-Term Debt for more information on these transactions, respectively.

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

Refer to “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity” in our Annual Report on Form 10-K for the year ended December 31, 2020 for a discussion of the cash flows for the year ended December 31, 2019 compared to the year ended December 31, 2020.

Debt Agreements

Credit Facility

We have a senior secured revolving credit facility with a consortium of bank lenders. On October 26, 2021, we entered into an amended and restated senior secured revolving credit facility, the New Credit Facility. Borrowings under the New Credit Facility are subject to borrowing base limitations based on the collateral value of our assets and are subject to regular semi-annual redeterminations. As of December 31, 2021, the borrowing base was $3.5 billion and lender commitments were $1.5 billion. The next redetermination of the borrowing base is scheduled to occur in April 2022. The maturity date of the New Credit Facility is the earlier of (i) October 26, 2026 and (ii) the date that is 180 days prior to the earliest stated redemption date of any series of Antero’s then outstanding senior notes.

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

The New Credit Facility provides for borrowing at either an Adjusted Term Secured Overnight Financing Rate (“SOFR”), an Adjusted Daily Simple SOFR or an Alternate Base Rate (each as defined in the New Credit Facility).

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

The New Credit Facility also requires us to maintain the following financial ratios (subject to certain exceptions): The current ratio and the leverage ratio shall be tested quarterly commencing with the quarter ending December 31, 2021.

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We were in compliance with the applicable covenants and ratios as of December 31, 2020 and 2021 under the Prior Credit Facility and New Credit Facility, respectively. As of December 31, 2021, our current ratio was 3.42 to 1.00 and our leverage ratio was 1.35 to 1.00.

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

Senior Unsecured Notes

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

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

We may, from time to time, seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions, or otherwise. Any such repurchases will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved could be material. During the year ended December 31, 2021, we repurchased or redeemed $1.7 billion principal amount of debt, including portions of our 2022 Notes, 2023 Notes, 2025 Notes, 2026 Notes and 2029 Notes.

The senior notes indentures each contain restrictive covenants and restrict our ability to incur additional debt unless a pro forma minimum interest coverage ratio requirement of 2.25:1 is maintained. We were in compliance with such covenants as of December 31, 2020 and 2021.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. Our more significant accounting policies and estimates include the successful efforts method of accounting for our production activities,

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estimates of natural gas, NGLs and oil reserve quantities and standardized measure of future cash flows, and impairment of proved properties. We provide an expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in the preparation of our consolidated financial statements. See Note 2—Summary of Significant Accounting Policies to the consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

Successful Efforts Method

The Company accounts for its natural gas, NGLs and oil exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, the costs incurred to acquire, drill, and complete productive wells, development wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when we determine that the well does not contain reserves in commercially viable quantities. The Company reviews exploration costs related to wells in progress at the end of each quarter and makes a determination, based on known results of drilling at that time, whether the costs should continue to be capitalized pending further well testing and results, or charged to expense. We have not incurred any such charges in the years ended December 31, 2019, 2020 and 2021. The sale of a partial interest in a proved property is accounted for as a normal retirement, and no gain or loss is recognized as long as this treatment does not significantly affect the units of production amortization rate. A gain or loss is recognized for all other sales of producing properties.

Unproved properties with significant acquisition costs are assessed for impairment on a property by property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks and future plans to develop acreage. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed to, the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognition of any gain or loss until the cost has been recovered. Impairment of oil and gas properties related to unproved properties for leases that have expired, or are expected to expire, was $393 million, $224 million and $91 million for the years ended December 31, 2019, 2020 and 2021, respectively.

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

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

Our internal technical staff prepares the estimates of natural gas, NGLs and oil reserves and associated future net cash flows, which are audited by our independent reserve engineers. Current accounting guidance allows only proved natural gas, NGLs and oil reserves to be included in our financial statement disclosures. The SEC has defined proved reserves as the estimated quantities of natural gas, NGLs and oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved undeveloped reserves include reserves that are expected to be drilled and developed within five years; wells that are not drilled within five years from booking are reclassified from proved reserves to probable reserves. Reserves are used in our depletion calculation and in assessing the carrying value of our oil and gas properties.

Our independent reserve engineers and internal technical staff must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates consider recent production levels and other technical information about each field. Natural gas, NGLs and oil reserve engineering is a subjective process of estimating underground accumulations of natural gas, NGLs and oil that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, natural gas, NGLs and oil prices, cost changes, technological advances, new geological or geophysical data or other economic factors. Accordingly, reserve estimates are generally different from the quantities of natural gas, NGLs and oil that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. Any significant revisions could affect the future amortization rates of capitalized costs and result in a material asset impairment.

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Impairment of Proved Properties

We evaluate the carrying amount of our proved natural gas, NGLs and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable.  Under GAAP for successful efforts accounting, if the carrying amount exceeds the estimated undiscounted future net cash flows (measured using futures prices at the end of a quarter), we further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeded the estimated fair value of the properties.

We did not record any impairments for proved properties during the years ended December 31, 2020 and 2021. During the year ended December 31, 2019, the Utica Shale carrying value exceeded the estimated fair value of the Utica Shale assets based on sales of other properties. As a result, we recorded an impairment of $881 million related to proved oil and gas properties in the Utica Shale during the year ended December 31, 2019.

Based on current future commodity prices, we currently do not anticipate having to record any impairment charge for our proved properties in the near future. Estimated undiscounted future net cash flows are sensitive to commodity price swings and a decline in prices could result in the carrying amount exceeding the estimated undiscounted future net cash flows at the end of a future reporting period, which would require us to further evaluate if an impairment charge would be necessary. For our Utica and Marcellus properties, strip pricing would have to decline by more than approximately 25% and 35%, respectively, from year-end 2021 levels before further evaluation of those properties would be required in order to determine if an impairment charge would be necessary under GAAP. If future prices decline from December 31, 2021, the fair value of our properties may be below their carrying amounts and an impairment charge may be necessary. However, we are unable to predict commodity prices with any greater precision than the futures market.

Fair Value Measurement

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

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

We account for our investment in Antero Midstream under the equity method of accounting. We evaluate our equity method investment for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the fair value of the investment to the carrying value of the investment to determine whether potential impairment has occurred. If the fair value is less than the carrying value and management considers the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the financial statements as an impairment loss. See Note 6—Equity-Method Investment to the consolidated financial statements for further discussion on our equity method investments.

As of March 31, 2020, we determined that events and circumstances indicated that the carrying value had experienced an other-than-temporary decline and we recorded impairment expense of $611 million. The fair value of the equity method investment in Antero Midstream was based on the quoted market common stock price of Antero Midstream as of March 31, 2020 (Level 1).

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Income Taxes

We are subject to state and federal income taxes, but are currently not in a cash tax paying position with respect to federal income taxes. The difference between our financial statement income tax expense and our U.S. federal income tax liability is primarily due to the differences in the tax and financial statement treatment of oil and gas properties, derivative instruments and the 2026 Convertible Notes. Our deferred tax assets and liabilities result from temporary differences between tax and financial statement income, primarily from derivative instruments, oil and gas properties and NOL carryforwards. As of December 31, 2021, we have U.S. federal and state NOLs expiring at various dates from 2025 to 2041 while others have no expiration date, which resulted in the recognition of significant deferred tax assets. We record deferred income tax expense to the extent our deferred tax liabilities exceed our deferred tax assets. We record a deferred income tax benefit to the extent our deferred tax assets exceed our deferred tax liabilities.

We record a valuation allowance when we believe all or a portion of our deferred tax assets will not be realized. In assessing the realizability of our deferred tax assets, management considers whether some portion or all of the deferred tax assets will be realized based on a more-likely-than-not standard of judgment. The ultimate realization of deferred tax assets is dependent upon our ability to generate future taxable income during the periods in which our deferred tax assets are deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment, estimates of which may be imprecise due to unforeseen future events or conditions outside of our control, including changes in commodity prices or changes to tax laws and regulations. The amount of deferred tax assets considered realizable could change based upon the amounts of taxable income actually generated, or as estimates of future taxable income change. As of December 31, 2021, we have recognized a valuation allowance of $50 million for NOLs we do not expect to realize that are primarily attributable to states in which we no longer operate and due to changes in West Virginia apportionment tax law.

The calculation of deferred tax assets and liabilities involves uncertainties in the application of complex tax laws and regulations. We recognize in our financial statements those tax positions which we believe are more-likely-than-not to be sustained upon examination by the Internal Revenue Service or state revenue authorities.

New Accounting Pronouncements

Convertible Instruments

In August 2020, the FASB issued Accounting Standards Update (“ASU”) No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which eliminates the cash conversion model in ASC 470-20, Debt with Conversion and Other Options, that require separate accounting for conversion features, and instead, allows the debt instrument and conversion features to be accounted for as a single debt instrument. It is effective for interim and annual reporting periods beginning after December 15, 2021. We will adopt the standard effective January 1, 2022 under the modified retrospective transition method.

Upon adoption of this new standard, we will reclassify $24 million, net of deferred income taxes and equity issuance costs, from additional paid-in capital and increase long-term debt by $27 million, reduce deferred income tax liability by $6 million and reduce accumulated deficit by $3 million as of January 1, 2022. Additionally, annual interest expense for the 2026 Convertible Notes beginning January 1, 2022 will be based on an effective interest rate of 4.9% as compared to 15.3% for the year ended December 31, 2021. We do not believe that adoption of the standard will impact our operational strategies or development prospects.

Income Taxes

In December 2019, the FASB issued ASU No. 2019-12, Simplifying the Accounting for Income Taxes. This ASU removes certain exceptions to the general principles in ASC 740, Income Taxes (“ASC 740”) and also simplifies portions of ASC 740 by clarifying and amending existing guidance. It is effective for interim and annual reporting periods beginning after December 15, 2020. We adopted this ASU on January 1, 2021, and it did not have a material impact on our consolidated financial statements.