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Item 7. Management’s Discussion and Analysis

2025-02-12 compared with 2024-02-14 · 157 added, 228 removed, 338 unchanged (53% of the section changed)

11 unchanged sentences

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.

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

Our drilling opportunities are focused in the Appalachian Basin.

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As of December 31, 2024, our estimated proved reserves were 17.9 Tcfe, consisting of 10.6 Tcf of natural gas, 674 MMBbl of assumed recovered ethane, 519 MMBbl of C3+ NGLs and 23 MMBbl of oil.

This represents a 2% increase in estimated proved reserves from December 31, 2022.

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

As of December 31, 2023, we had 1,588 potential horizontal well locations on our existing leasehold acreage that were classified as proved, probable and possible.

We operate in the following reportable segments:

As of December 31, 2024, we had 1,137 potential horizontal well locations on our existing leasehold acreage that were classified as proved, probable and possible and excludes 339 locations based on such locations being uneconomic at the SEC reserves prices for the year ended December 31, 2024.

We have three 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”).

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

All of our operations are conducted in the United States.

See Note 17—Reportable Segments to our consolidated financial statements for additional information.

Financing Highlights

Share Repurchase Program

During 2022, our Board of Directors authorized a share repurchase program that allows us to repurchase up to $2.0 billion of outstanding common stock.

During the years ended December 31, 2022 and 2023, we repurchased 25 million and 3 million shares of our common stock, respectively, through our share repurchase program at a total cost of $874 million and $75 million, respectively.

As of December 31, 2023, we have $1.1 billion remaining under our share repurchase program.

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.

2026 Convertible Notes Conversions

During the year ended December 31, 2023, $9 million aggregate principal amount of the 2026 Convertible Notes were converted pursuant to their terms, and an additional $21 million aggregate principal amount of the 2026 Convertible Notes were induced into conversion by us.

We elected to settle these conversions and inducements by issuing 7 million shares of common stock

to the noteholders together with a cash inducement premium of $0.4 million.

See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Unsecured Credit Facility

During 2024, we achieved an investment grade credit rating from S&P Global Inc.

in addition to our investment grade credit rating from Fitch Ratings, Inc.

As a result of this investment grade credit rating, on July 30, 2024, we entered into an amended and restated senior revolving credit facility with lender commitments of $1.65 billion that matures on July 30, 2029, subject to certain extension terms and conditions (the “Unsecured Credit Facility”).

Borrowings under the amended and restated facility are unsecured and are not guaranteed by any of our subsidiaries.

See Note 7—Long-Term Debt to our consolidated financial statements for additional information.

Drilling Partnerships

2021-2024 Drilling Partnership

On February 17, 2021, we announced the formation of a drilling partnership with 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 through 2024, we agreed to the estimated IRR or our capital budget for each annual tranche, and QL agreed to participate in all four annual tranches.

We develop and manage the drilling program associated with each tranche, including the selection of wells.

Additionally, for each annual tranche, 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 development capital of 20%, 15% and 15% for wells spud in 2021, 2022 and 2023, respectively, and will fund 20% of development capital for wells spud in 2024, which funding amounts represent QL’s proportionate working interest in such wells.

Additionally, we may receive a carry in the form of a one-time payment from QL for each annual tranche if the IRR for such tranche exceeds certain specified returns, which will be determined no earlier than October 31 and no later than December 1 following the end of each tranche year.

We received a carry of $29 million for each of the 2021 and 2022 tranches during the years ended December 31, 2022 and 2023.

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

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

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

Under the terms of the arrangement, QL funded development capital of 20% for wells spud in 2021 and 2024 and 15% for wells spud in 2022 and 2023, which funding amounts represent QL’s proportionate working interest in such wells.

Additionally, we received a carry of $29 million for each of the 2021 and 2022 tranches during the years ended December 31, 2022 and 2023 and a carry of $32 million for the 2023 tranche during the year ended December 31, 2024.

See Note 3—Transactions to our consolidated financial statements for additional information.

2025 Drilling Partnership

On December 11, 2024, we entered into a drilling partnership with an unaffiliated third-party.

Under the terms of the arrangement, the third-party will participate in and fund a share of total development capital expenses for wells spud by Antero during the 2025 calendar year.

For each well spud during the 2025 calendar year, the third-party will receive a 15% working interest in such wells and will fund greater than 15% of total development capital expenses for such wells.

Subject to the preceding sentence, for any wells spud in the calendar year 2025, the third-party 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.

Additionally, for each well in the partnership, we will enter into an assignment, bill of sale and conveyance pursuant to which the third-party will be conveyed a proportionate working interest percentage in such well, which conveyances will not be subject to any reversion.

See Note 3—Transactions to our consolidated financial statements for additional information.

Market Conditions and Business Trends

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Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows.

Natural gas, NGLs and oil benchmark prices decreased significantly during 2023 as compared to 2022.

As a result, we experienced a decrease in price realizations during the year ended December 31, 2023.

Benchmark prices for natural gas and ethane decreased significantly, while benchmark prices for oil remained consistent and benchmark prices for C3+ NGLs increased during the year ended December 31, 2024 as compared to the year ended December 31, 2023.

As a result of the lower benchmark natural gas and ethane prices and higher benchmark C3+ NGLs prices during the year ended December 31, 2024, we experienced a decrease in price realizations for natural gas and ethane products and an increase in price realization for C3+ NGLs products during the same period.

We monitor the economic factors that impact natural gas, NGLs and oil prices, including domestic and foreign supply and demand indicators, domestic and foreign commodity inventories, the actions of Organization of Petroleum Exporting Countries and other large producing nations and the current conflicts in Ukraine and in the Middle East, among others.

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This volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.

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

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

Year Ended December 31,

Henry Hub ($/Mcf) (1)

Mont Belvieu Ethane ($/Bbl) (2)

Mont Belvieu C3+ NGLs ($/Bbl) (3)

West Texas Intermediate ($/Bbl) (4)

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

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

(1) NYMEX first of month average natural gas price.

(2) ICE settlement ethane OPIS futures average price for the front month contract as published on the last trading day of the month.

(3) ICE settlement propane, isobutane, normal butane and natural gasoline OPIS futures average price for the front month contract as published on the last trading day of the month.

Propane and isobutane reflect TET prices, and normal butane and natural gasoline reflect non-TET prices.

Propane, isobutane, normal butane and natural gasoline futures prices are weighted to approximate Antero Resources’ average C3+ NGLs composition.

(4) NYMEX calendar month average settled futures price.

Hedge Position

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Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased.

For the years ended December 31, 2022 and 2023, 33% and 1%, respectively, of our production was hedged through fixed price commodity swaps, and as of December 31, 2023, we had no fixed price commodity swap positions.

The tables and narrative below exclude derivative instruments attributable to Martica, our consolidated VIE, since all gains or losses from such contracts are fully attributable to the noncontrolling interests in Martica.

As of December 31, 2023, our natural gas basis swap positions settle on the pricing index to basis differential of the Columbia Gas Transmission pipeline (“TCO”) to the NYMEX Henry Hub natural gas price were as follows:

Weighted Average

Commodity / Settlement Period

Index to Basis Differential

Contracted Volume

Hedged Differential

January-December 2024

We have a call option and an embedded put option tied to NYMEX pricing for the production volumes associated with the Company’s retained interest in the VPP properties.

As of December 31, 2023, our call option and embedded put option arrangements were as follows:

Commodity / Settlement Period

Contracted Volume

January-December 2024

January-December 2025

January-December 2026

For 2023 and 2024, substantially all of our production was unhedged.

Assuming our 2025 production is the same as our production in 2024, approximately 3% of our total production for 2025 is hedged through fixed price commodity swaps.

As of December 31, 2024, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of $45 million.

See Note 11—Derivative Instruments to the consolidated financial statements for more information.

Our consolidated VIE, Martica, also maintains a portfolio of fixed swap natural gas, NGLs and oil derivatives for the benefit of the noncontrolling interests in Martica.

See Note 11—Derivative Instruments to our consolidated financial statements for additional information.

Our consolidated VIE, Martica, also maintains a portfolio of fixed price swap derivatives for the benefit of the noncontrolling interests in Martica.

As such, all gains and losses attributable to Martica’s derivative portfolio are fully attributable to the noncontrolling interests in Martica.

As of December 31, 2023, Martica’s fixed price natural gas, NGLs and oil swap positions were as follows:

Commodity / Settlement Period

Contracted Volume

January-December 2024

January-March 2025

January-December 2024

West Texas Intermediate

January-March 2025

West Texas Intermediate

As of December 31, 2024, the estimated fair value of Martica’s commodity derivative contracts was a net liability of $2 million.

See Note 11—Derivative Instruments to the consolidated financial statements for more information.

See Note 11—Derivative Instruments to our consolidated financial statements for additional information.

Economic Indicators

The economy experienced elevated inflation levels as a result of global supply and demand imbalances, where global demand outpaced supplies beginning in 2021 and continuing through 2024.

For example, CPI for all urban consumers increased 8% from December 2021 to December 2022 and an additional 4% from December 2022 to December 2023 as compared to the Federal Reserve’s stated goal of 2%.

For example, CPI for all urban consumers increased 4.1% from December 2022 to December 2023 and an additional 2.9% from December 2023 to December 2024.

In order to manage the inflation risk present in the United States’ economy, the Federal Reserve utilized monetary policy in the form of interest rate increases beginning in March 2022 in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis.

Between March 2022 and December 2023, the Federal Reserve increased the federal funds interest rate by 5.25%.

Between March 2022 and July 2023, the Federal Reserve increased the federal funds interest rate by 5.25%.

During the second half of 2024, inflation rates began to approach the Federal Reserve’s stated goal of 2%, and the Federal Reserve decreased the federal funds rate by 1.0% between September and December 2024.

While inflationary pressures in the United States’ economy have begun to subside, we continue to be impacted by the increased federal funds interest rate.

See “—Results of Operations” for more information.

See “—Results of Operations” for additional information.

The economy also continues to be impacted by the effects of global events.

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● Commodity derivatives.

We utilize derivative instruments to hedge future sales prices for a portion of our production when circumstances warrant.

We currently utilize call and embedded put options, as well as basis swap contracts that hedge the difference between the NYMEX index price and a local index price.

We may also enter into commodity fixed price swaps, collars or other similar instruments related to the price risk associated with our production.

We utilize derivative instruments to hedge future sales prices for our production when circumstances warrant.

We currently utilize call and embedded put options, collar contracts and fixed price contracts for a nominal portion of our natural gas in which we receive or pay the difference between a fixed price and the variable market price received.

Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased.

As of December 31, 2023, we had no fixed price commodity swap positions.

See Note 11—Derivative Instruments to the consolidated financial statements for more information.

Assuming our 2025 production is the same as our production in 2024, approximately 3% of our total production for 2025 is hedged through fixed price commodity swaps.

See Note 11—Derivative Instruments to our consolidated financial statements for additional information.

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

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

We also classify firm

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

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

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

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● Impairment of property and equipment.

These costs include impairment and costs associated with leases expirations, impairment of design and initial costs related to pads that are no longer planned to be placed into service and impairment of proved properties due to lower future commodity prices.

These costs include impairment and costs associated with lease expirations, impairment of design and initial costs related to pads that are no longer planned to be placed into service and impairment of proved properties due to lower future commodity prices.

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

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

See Note 9—Equity-Based Compensation to the consolidated financial statements for more information.

See Note 9—Equity-Based Compensation to our consolidated financial statements for additional information.

● Interest expense.

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

As of December 31, 2023, we had an outstanding balance on the Credit Facility of $417 million with a weighted average interest rate of 7.71%.

We finance a portion of our capital expenditures, working capital requirements and acquisitions with borrowings under our Credit Facility, which has a variable rate of interest based on the Adjusted Term SOFR Rate, the Adjusted Daily Simple SOFR (collectively, “SOFR”) or the Alternate Base Rate, in each case, plus an Applicable Rate (each term as defined in the Credit Facility).

As of December 31, 2023 and 2024, we had an outstanding balance on the Credit Facility of $417 million and $393 million, respectively, with a weighted average interest rate of 7.7% and 5.9%, respectively.

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

As of December 31, 2023, we had fixed interest rates ranging from 5.375% to 8.375% on our Senior Notes with an aggregate principal balance of $1.1 billion and 4.25% on our 2026 Convertible Notes with an aggregate principal balance of $26 million.

See Note 7—Long-Term Debt to the consolidated financial statements for more information.

● Income tax expense.

We are subject to state and U.S.

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

As of December 31, 2023 and 2024, we had fixed interest rates ranging from 5.375% to 8.375% on our Senior Notes with an aggregate principal balance of $1.1 billion.

See Note 7—Long-Term Debt to our consolidated financial statements for additional information.

● Income tax (expense) benefit.

We are subject to U.S.

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

federal income taxes.

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

federal income tax liability is primarily due to the differences in the tax and financial statement treatment of oil and gas properties, the effects of noncontrolling interests and the deferral of unsettled commodity derivative gains and losses for tax purposes until they are settled.

The difference between our financial statement income tax (expense) benefit and our current U.S.

federal income tax liability is primarily due to the differences in the tax and financial statement treatment of oil and gas properties, the effects of noncontrolling interests, the deferral of unsettled commodity derivative gains and losses for tax purposes until they are settled and research and development (“R&D”) tax credits.

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

See Note 13—Income Taxes to the consolidated financial statements for more information.

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

See Note 13—Income Taxes to our consolidated financial statements for additional information.

Results of Operations

We have three operating segments:

We have three reportable segments:

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

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

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

See Note 17—Reportable Segments to our consolidated financial statements for additional information.

Year Ended December 31, 2023 Compared to Year Ended December 31, 2024

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Unconsolidated

Midstream (1)

Revenue and other:

1 unchanged sentence

Natural gas liquids sales

Commodity derivative fair value losses

Commodity derivative fair value gains

Gathering, compression and water handling

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Accretion of asset retirement obligations

Contract termination, loss contingency and other operating expenses

Loss (gain) on sale of assets

Contract termination, loss contingency, settlements and other operating expenses

Total operating expenses

1 unchanged sentence

Equity in earnings of unconsolidated affiliates

(1) Amounts reflect those recorded in Antero Midstream Corporation’s consolidated financial statements.

Year Ended December 31, 2024

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Unconsolidated

Midstream (1)

Revenue and other:

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Production and ad valorem taxes

Exploration and mine expenses

General and administrative (excluding equity-based compensation)

3 unchanged sentences

Accretion of asset retirement obligations

Loss (gain) on sale of assets

Contract termination, loss contingency and other operating expenses

Loss on sale of assets

Contract termination, loss contingency, settlements and other operating expenses

Total operating expenses

1 unchanged sentence

Equity in earnings of unconsolidated affiliates

(1) Amounts reflect those recorded in Antero Midstream Corporation’s consolidated financial statements.

Exploration and Production Segment

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Depletion, depreciation, amortization and accretion

* Not meaningful

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

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

Our calculation of such after effects includes gains (losses) on settlements of commodity derivatives (but does not include proceeds from the derivative monetizations in 2023), which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes.

Our calculation of such after effects includes gains (losses) on settlements of commodity derivatives (but do not include payments for the derivative monetizations in 2023), which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes.

(4) The average realized price for the years ended December 31, 2023 and 2024 includes $15 million and $2 million, respectively, of proceeds related to a take-or-pay contract.

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Revenues from sales of natural gas decreased from $2.2 billion for the year ended December 31, 2023 to $1.8 billion for the year ended December 31, 2024, a decrease of $0.4 billion, or 17%.

Lower commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2023 accounted for an approximate $3.4 billion decrease in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price excluding the net proceeds from the litigation times current year production volumes).

Higher natural gas production volumes accounted for an approximate $121 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).

Revenues from sales of NGLs decreased from $2.5 billion for the year ended December 31, 2022 to $1.8 billion for the year ended December 31, 2023, a decrease of $0.7 million, or 26%.

Lower commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2023 accounted for an approximate $888 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Lower commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2024 accounted for an approximate $313 million decrease in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes).

Lower natural gas production volumes accounted for an approximate $61 million decrease in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price).

Revenues from sales of NGLs increased from $1.8 billion for the year ended December 31, 2023 to $2.1 billion for the year ended December 31, 2024, an increase of $0.3 billion, or 13%.

Higher commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2024 accounted for an approximate $153 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Higher NGLs production volumes during the year ended December 31, 2024 accounted for an approximate $77 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price).

Revenues from sale of oil decreased from $247 million for the year ended December 31, 2023 to $230 million for the year ended December 31, 2024, a decrease of $17 million, or 7%.

Lower oil production volumes during the year ended December 31, 2024 accounted for an approximate $11 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price).

Lower oil prices for the year ended December 31, 2024 (excluding the effects of derivative settlements) accounted for an approximate $6 million decrease in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes).

Higher oil production volumes during the year ended December 31, 2023 accounted for an approximate $55 million increase in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price).

Commodity derivative fair value losses.

Commodity derivative fair value gains.

Our commodity derivatives included fixed price swap contracts, swaptions, basis swap contracts, call options and embedded put options.

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

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

For the years ended December 31, 2022 and 2023, our commodity hedges resulted in derivative fair value losses of $1.6 billion and fair value gains of $166 million, respectively.

For the year ended December 31, 2022, commodity derivative fair value losses included $1.9 billion of net cash payments for settled derivative losses.

For the year ended December 31, 2023, commodity derivative fair value gains included $25 million of net cash payments for settled commodity derivative losses, as well as $202 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 or terminated prior to settlement.

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 and comprehensive income.

For the years ended December 31, 2023 and 2024, our commodity hedges resulted in derivative fair value gains of $166 million and $1 million, respectively.

For the year ended December 31, 2023, commodity derivative fair value gains included $25 million of net cash payments for settled derivative losses, as well as $202 million for payments on derivatives that were settled prior to their contractual settlement dates.

For the year ended December 31, 2024, commodity derivative fair value gains included $10 million of net cash proceeds for settled derivative gains.

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, monetized or terminated 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.

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Lease operating expense .

Lease operating expense increased from $100 million, or $0.09 per Mcfe, for the year ended December 31, 2022 to $118 million, or $0.10 per Mcfe, for the year ended December 31, 2023, an increase of $18 million or $0.01 per Mcfe, primarily due to higher oilfield service, workover and produced water handling costs.

Lease operating expense remained relatively consistent for the years ended December 31, 2023 and 2024 at $118 million and $119 million, respectively.

On a per-unit basis, lease operating expense decreased from $0.10 per Mcfe for the year ended December 31, 2023 to $0.09 per Mcfe for the year ended December 31, 2024 primarily due to lower water disposal costs and workover expense between periods.

Gathering, compression, processing and transportation expense.

Gathering, compression, processing and transportation expense remained consistent at $2.6 billion for each of the years ended December 31, 2022 and 2023.

Gathering, compression, processing and transportation expense remained relatively consistent at $2.6 billion and $2.7 billion for the years ended December 31, 2023 and 2024, respectively.

This was primarily a result of the following:

● Gathering and compression costs on a per unit basis decreased from $0.76 per Mcfe for the year ended December 31, 2022 to $0.69 per Mcfe for the year ended December 31, 2023, primarily due to lower fuel costs as a result of decreased commodity prices, partially offset by annual CPI-based based adjustments between periods.

● Processing costs on a per unit basis increased from $0.74 per Mcfe for the year ended December 31, 2022 to $0.82 per Mcfe for the year ended December 31, 2023, primarily due to increased costs for NGLs processing and transportation, which include annual CPI-based and commodity based adjustments, as well as higher terminal fees and ethane transportation.

● Transportation costs on a per unit basis decreased from $0.72 per Mcfe for the year ended December 31, 2022 to $0.62 per Mcfe and for the year ended December 31, 2023, primarily due to lower fuel costs as a result of lower commodity prices between periods.

● Gathering and compression costs on a per unit basis increased from $0.69 per Mcfe for the year ended December 31, 2023 to $0.72 per Mcfe for the year ended December 31, 2024, primarily due to the expiration of the growth incentive fee rebate program on December 31, 2023 and annual CPI-based adjustments between periods.

During the year ended December 31, 2023, we earned growth incentive fee rebates of $52 million.

● Processing costs on a per unit basis increased from $0.82 per Mcfe for the year ended December 31, 2023 to $0.85 per Mcfe for the year ended December 31, 2024, primarily due to increased costs for NGLs processing, which includes an annual CPI-based adjustment during the first quarter of 2024 and higher NGLs transportation fees.

● Transportation costs on a per unit basis decreased from $0.62 per Mcfe for the year ended December 31, 2023 to $0.59 per Mcfe and for the year ended December 31, 2024, primarily due to lower fuel costs as a result of lower natural gas prices and lower demand fees between periods.

Production and ad valorem tax expense.

Production and ad valorem taxes decreased from $287 million for the year ended December 31, 2022 to $159 million for the year ended December 31, 2023, a decrease of $128 million or 45%, primarily due to lower commodity prices between periods, partially offset by higher production volumes between periods.

Production and ad valorem taxes as a percentage of natural gas revenues increased from 5% for the year ended December 31, 2022 to 7% for the year ended December 31, 2023.

Production and ad valorem taxes increased from $159 million for the year ended December 31, 2023 to $208 million for the year ended December 31, 2024, an increase of $49 million or 31%, primarily due to higher ad valorem taxes, partially offset by lower natural gas and oil prices during the year ended December 31, 2024.

Production and ad valorem taxes as a percentage of natural gas revenues increased from 7% for the year ended December 31, 2023 to 11% for the year ended December 31, 2024, primarily as a result of higher ad valorem taxes, which 2024 West Virginia ad valorem taxes are based on commodity prices during 2022.

General and administrative expense.

General and administrative expense (excluding equity-based compensation expense) increased from $137 million for the year ended December 31, 2022 to $165 million for the year ended December 31, 2023, an increase of $28 million or 20%, primarily due to higher salary and wage expense, professional service fees, office operating costs and software license costs between periods.

We had 586 and 604 employees as of December 31, 2022 and 2023, respectively.

administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.12 per Mcfe for the year ended December 31, 2022 to $0.13 per Mcfe for the year ended December 31, 2023 as a result of our higher overall general and administrative costs, partially offset by increased production volumes between periods.

General and administrative expense (excluding equity-based compensation expense) remained relatively consistent at $165 million, or $0.13 per Mcfe and $163 million, or $0.13 per Mcfe, for the years ended December 31, 2023 and 2024, respectively.

Equity-based compensation expense .

Noncash equity-based compensation expense increased from $35 million for the year ended December 31, 2022 to $60 million for the year ended December 31, 2023, an increase of $25 million or 68%, primarily due to an increase in the annual equity awards granted during 2022 and 2023 as compared to prior years, which were temporarily and significantly reduced during 2020 and supplemented by our cash awards program .

Our equity awards vest over three or four year service periods, and our equity incentive program began returning to normal levels in 2021 .

See Note 9—Equity-Based Compensation to the consolidated financial statements for more information.

Non-cash equity-based compensation expense increased from $60 million for the year ended December 31, 2023 to $66 million for the year ended December 31, 2024, an increase of $6 million or 12%.

This increase was primarily due to higher restricted stock unit (“RSU”) award expense of $9 million between periods, partially offset by lower performance share unit (“PSU”) award expense of $3 million between periods.

See Note 9—Equity-Based Compensation to our consolidated financial statements for additional information.

Depletion, depreciation and amortization expense .

DD&A expense increased from $681 million, or $0.59 per Mcfe for the year ended December 31, 2022 to $690 million, or $0.56 per Mcfe for the year ended December 31, 2023, an increase of $9 million.

The decrease in DD&A expense per Mcfe between periods was primarily due to higher reserve volumes during the year ended December 31, 2023.

DD&A expense increased from $747 million for the year ended December 31, 2023 to $762 million for the year ended December 31, 2024, an increase of $15 million or 2%, primarily due to higher production volumes between periods.

On a per-unit basis, DD&A expense remained consistent at $0.61 per Mcfe for the years ended December 31, 2023 and 2024.

Impairment of property and equipment .

Impairment of property and equipment decreased from $150 million for the year ended December 31, 2022 to $51 million for the year ended December 31, 2023, a decrease of $99 million, or 66%, primarily related to lower impairments of expiring leases between periods and the impairment of our sand mine of $48 million during the year ended December 31, 2022.

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

Contract termination, loss contingency and other operating expenses .

Contract termination, loss contingency and other operating expenses attributable to our exploration and production segment of $25 million for the year ended December 31, 2022 were primarily due to a payment for the cancellation of the Smithburg 2 gas processing plant and the cancellation of a gas gathering agreement.

Contract termination, loss contingency and other operating expenses attributable to our exploration and production segment of $29 million for the year ended December 31, 2023 were primarily due to a loss contingency and the early termination of certain drilling and completion contracts.

Impairment of property and equipment decreased from $51 million for the year ended December 31, 2023 to $47 million for the year ended December 31, 2024, a decrease of $4 million, or 8%, primarily due to lower impairments of expiring leases between periods.

During both periods, we recognized impairments primarily related to expiring leases as well as design and initial costs related to pads we no longer plan to utilize .

Contract termination, loss contingency, settlements and other operating expenses .

Contract termination, loss contingency, settlements and other operating expenses attributable to our exploration and production segment decreased from $29 million for the year ended December 31, 2023 to $5 million for the year ended December 31, 2024.

This decrease was primarily due to a loss contingency recorded during the year ended December 31, 2023 and lower expense associated with the early termination of certain drilling and completion contracts between periods.

Marketing Segment

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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.

Net marketing expense decreased from $115 million, or $0.10 per Mcfe, for the year ended December 31, 2022 to $79 million, or $0.06 per Mcfe, for the year ended December 31, 2023, primarily due to lower firm transportation commitments, partially offset by lower marketing margin on third-party product purchases between periods.

Net marketing expense decreased from $79 million, or $0.06 per Mcfe, for the year ended December 31, 2023 to $66 million, or $0.05 per Mcfe, for the year ended December 31, 2024, primarily due to lower firm transportation commitments between periods.

Marketing revenue.

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This fluctuation primarily resulted from the following:

● Natural gas marketing revenue decreased by $187 million between periods primarily due to lower natural gas prices and marketing volumes.

Lower natural gas prices accounted for an approximate $182 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes), and lower natural gas marketing volumes accounted for a $5 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price).

● Ethane marketing revenues were $42 million for the year ended December 31, 2022.

There were no third-party ethane marketing revenues for the year ended December 31, 2023.

● Oil marketing revenue increased by $16 million between periods primarily due to higher marketing volumes, partially offset by lower oil prices.

Higher oil marketing volumes accounted for a $42 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower oil prices accounted for an approximate $26 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

● Natural gas marketing revenue decreased by $77 million between periods primarily due to lower natural gas marketing volumes and prices.

Lower natural gas marketing volumes accounted for a $68 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower natural gas prices accounted for a $9 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

● Oil marketing revenue increased by $46 million between periods primarily due to higher oil marketing volumes and prices.

Higher oil marketing volumes accounted for a $39 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher oil prices accounted for an approximate $7 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

● NGLs marketing revenues were $4 million for the year ended December 31, 2024.

There were no NGLs marketing revenues for the year ended December 31, 2023.

Marketing expense.

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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 and NGLs decreased $188 million and $28 million, respectively, between periods, partially offset by increased oil purchases of $14 million between periods.

The total costs decreased between periods primarily due to lower commodity prices and lower natural gas and NGL third-party marketing volumes, partially offset by increased oil marketing volumes.

Firm transportation costs were $149 million for the year ended December 31, 2022 and $105 million for the year ended December 31, 2023, a decrease of $44 million primarily due to the reduction in firm transportation commitments between periods.

Contract termination, loss contingency and other operating expenses.

Our marketing segment did not incur any contract termination, loss contingency and other operating expenses for the year ended December 31, 2022.

Contract termination, loss contingency and other operating expenses attributable to our marketing segment for the year ended December 31, 2023 relate to a $24 million payment for the early termination of our firm transportation commitment of 200,000 MMBtu/d on the Equitrans pipeline.

The cost of third-party natural gas purchases decreased $62 million between periods, partially offset by increased oil and NGLs purchases of $37 million and $4 million, respectively.

The total cost of third-party commodity purchases decreased primarily due to lower natural gas marketing volumes and prices between periods, partially offset by higher oil and NGLs marketing volumes during the year ended December 31, 2024.

Firm transportation costs decreased $19 million from $105 million for the year ended December 31, 2023 to $86 million for the year ended December 31, 2024, primarily due to the reduction in firm transportation commitments between periods.

Contract termination, loss contingency, settlements and other operating expenses.

Contract termination, loss contingency, settlements and other operating expenses attributable to our marketing segment for the year ended December 31, 2023 relate to a $24 million payment for the early termination of our firm transportation commitment of 200,000 MMBtu/d on the Equitrans pipeline.

Our marketing segment did not incur any contract termination, loss contingency, settlements and other operating expenses for the year ended December 31, 2024.

Antero Midstream Segment

Antero Midstream revenue.

Revenue from the Antero Midstream segment increased from $0.9 billion for the year ended December 31, 2022 to $1.0 billion for the year ended December 31, 2023, an increase of $0.1 billion, or 13%, primarily due to increased throughput and higher water handling volumes between periods, as well as higher low pressure, compression, high pressure and fresh water delivery fees as a result of an annual CPI-based adjustments and increased other fluid handling fees primarily due to increased costs partially due to inflationary pressures between periods that impact the cost plus 3% and cost of service rates.

Revenue from the Antero Midstream segment increased from $1.0 billion for the year ended December 31, 2023 to $1.1 billion for the year ended December 31, 2024, an increase of $0.1 billion, or 6%.

This increase is primarily due to higher gathering and compression revenues of $84 million, partially offset by lower water handling revenues of $20 million.

The increased gathering and compression revenues between periods is primarily a result of the expiration of the growth incentive fee rebate program on December 31, 2023, increased throughput and annual CPI-based gathering and compression rate adjustments between periods.

The decreased water handling revenues between periods is primarily due to lower fresh water delivery and other fluid handling volumes, partially offset by an increased fresh water delivery rate due to an annual CPI-based adjustment during the year ended December 31, 2024.

Antero Midstream operating expense.

Total operating expense related to the Antero Midstream segment increased from $381 million for the year ended December 31, 2022 to $430 million for the year ended December 31, 2023, an increase of $49 million, or 13%, primarily due to increased direct operating costs, equity-based compensation and depreciation expense, partially offset by decreased general and administrative expenses (excluding equity-based compensation expense) between periods.

Direct operating expenses increased between periods primarily due to 12 compressors that were acquired during the fourth quarter of 2022, higher wastewater trucking rates, increased heavy maintenance expense and an increased number of locations connected to its water blending system between periods.

Equity-based compensation increased between periods primarily due to an increase in the annual equity awards granted during the years ended December 31, 2022 and 2023 as compared to prior years, which were temporarily and significantly reduced during 2020 and supplemented by our cash awards program.

Antero Midstream’s equity awards vest over three or four year service periods, and its equity incentive program began returning to normal levels in 2021.

Depreciation expense increased between periods primarily due to assets acquired during the fourth quarter of 2022 and assets placed in service during the year ended December 31, 2023, partially offset by lower depreciation expense associated with Antero Midstream’s program to repurpose underutilized compressor units to expand existing or construct new compressor stations between periods.

General and administrative expenses (excluding equity-based compensation expense) decreased between periods primarily due to lower legal costs.

Total operating expense related to the Antero Midstream segment increased from $430 million for the year ended December 31, 2023 to $447 million for the year ended December 31, 2024, an increase of $17 million, or 4%.

This increase is primarily due to higher gathering and compression expense as a result of increased throughput during the year ended December 31, 2024, as well as higher general and administrative expense, including equity-based compensation expense, and depreciation expense between periods, partially offset by lower gains on asset sale during the year ended December 31, 2024.

Items Not Allocated to Segments

Interest expense.

Interest expense decreased from $125 million for the year ended December 31, 2022 to $118 million for the year ended December 31, 2023, a decrease of $7 million, or 6%, primarily due to our redemption or repurchase of $990 million in aggregate principal amount of certain of our Senior Notes during the year ended December 31, 2022, partially offset by higher benchmark interest rates during the year ended December 31, 2023 and higher average Credit Facility borrowings between periods.

See Note 7—Long-Term Debt to the consolidated financial statements for more information.

Loss on early extinguishment of debt.

D uring the year ended December 31, 2022, we redeemed or repurchased through our previously disclosed tender offer and open market transactions (i) the remaining $585 million aggregate principal amount of our 2025 Notes at a redemption price of 101.25% of the principal amount thereof, plus accrued and unpaid interest, (ii) $228 million of our 2026 Notes at a weighted average redemption price of 109% of the principal amount thereof, plus accrued and unpaid interest and (iii) $177 million of our 2029 Notes at a weighted average redemption price of 106% of the principal amount thereof, plus accrued and unpaid interest.

For such redemptions and repurchases, we recognized a $46 million loss on early extinguishment of debt.

There were no redemptions or repurchases of our Senior Notes during the year ended December 31, 2023.

See Note 7—Long-Term Debt to the consolidated financial statements for more information.

Income tax expense.

Income tax expense decreased from $449 million for the year ended December 31, 2022 to $76 million for the year ended December 31, 2023 primarily due to lower pre-tax income between periods.

The effective tax rate for the years ended December 31, 2022 and 2023 were 18.1% and 18.2%, respectively.

Our effective tax rate was different than the statutory rate of 21% primarily due to the effects of state income taxes, the dividends received deduction, equity-based compensation expenses, noncontrolling interests, the effects of a West Virginia apportionment tax law change enacted in 2021 and changes in Pennsylvania’s corporate income tax rate.

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

Interest expense remained consistent at $118 million for the years ended December 31, 2023 and 2024.

See Note 7—Long-Term Debt to our consolidated financial statements for additional information.

Income tax (expense) benefit.

For the year ended December 31, 2023, we had income tax expense of $64 million, with an effective tax rate of 17.6%, due to income before income taxes of $361 million.

Our effective tax rate for the year ended December 31, 2023 was different than the statutory rate of 21% primarily due to the effects of state income taxes, the dividends received deduction, equity-based compensation expenses, noncontrolling interests, the effects of a West Virginia apportionment tax law change enacted in 2021 and changes in Pennsylvania’s corporate income tax rate.

For the year ended December 31, 2024, we had an income tax benefit of $118 million primarily due to R&D tax credits of $95 million, loss before income taxes of $24 million and a reduction to our state NOL carryforward valuation allowance of $12 million.

See Note 13—Income Taxes to our consolidated financial statements for additional information.

As of December 31, 2024, we had U.S.

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Capital Resources and Liquidity

Our primary sources of liquidity have been through net cash provided by operating activities, borrowings under our Credit Facility, issuances of debt and equity securities and additional contributions from our asset sales, including our drilling partnership.

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

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

The Credit Facility has a borrowing base of $3.5 billion and current lender commitments of $1.6 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 2024.

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

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

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

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

Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased.

Our commodity hedge position can provide us with liquidity for the portion of our production that is hedged because it provides us with the relative certainty of our future expected revenues for such production despite potential declines in the price of natural gas.

However, due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased.

Assuming our 2025 production is the same as our production in 2024, approximately 3% of our total production for 2025 is hedged through fixed price commodity swaps.

Our ability to make significant acquisitions for cash would require us to utilize borrowings on the Credit Facility or obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us, or at all.

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Capital Spending and 2025 Capital Budget

For the year ended December 31, 2023, our total consolidated capital expenditures were $1.1 billion, including drilling and completion expenditures of $909 million, leasehold additions of $148 million and other capital expenditures of $15 million.

For the year ended December 31, 2024, our total consolidated capital expenditures were $721 million, including drilling and completion expenditures of $620 million, leasehold additions of $91 million and other capital expenditures of $10 million.

We completed 41 net horizontal wells during the year ended December 31, 2024.

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Based on strip prices as of December 31, 2024, we believe that net cash provided from operating activities and available borrowings under the Credit Facility will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures and commitments and contingencies for at least the next 12 months.

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

See Note 14—Commitments to the consolidated financial statements for information on our off-balance sheet arrangements.

For more information on our outstanding indebtedness, see Note 7—Long-Term Debt to our consolidated financial statements.

See Note 14—Commitments to our consolidated financial statements for information on our off-balance sheet arrangements.

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

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Operating activities.

Net cash provided by operating activities was $3.1 billion and $1.0 billion for the years ended December 31, 2022 and 2023, respectively.

Net cash provided by operating activities decreased primarily due to decreases in commodity prices, a $202 million payment for early settlement of our swaption agreement and higher contract termination, gathering, compression, processing and transportation, general and administrative (excluding equity-based compensation expense) and lease operating expenses.

These operating cash flow decreases were partially offset by higher production, lower production and ad valorem taxes, interest expense and net marketing expense, decreased payments for commodity derivative settlements and changes in working capital between periods.

Net cash provided by operating activities was $995 million and $849 million for the years ended December 31, 2023 and 2024, respectively.

Net cash provided by operating activities decreased primarily due to lower natural gas prices and changes in working capital, partially offset by increased NGLs revenue due to higher C3+ NGLs prices, lower contract termination, loss contingency and settlements expense and lower net marketing expense between periods and a $202 million payment for early settlement of our swaption agreement in the year ended December 31, 2023.

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

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Investing activities.

Net cash used in investing activities increased from $0.9 billion for the year ended December 31, 2022 to $1.1 billion for the year ended December 31, 2023, primarily due to increased drilling and completions activity and land purchases, as well as higher drilling and water costs between periods.

Net cash used in investing activities decreased from $1.1 billion for the year ended December 31, 2023 to $0.7 billion for the year ended December 31, 2024, primarily due to lower well completions between periods, decreased drilling activity as a result of a lower rig count between periods and decreased leasing activity during the year ended December 31, 2024.

During the years ended December 31, 2023 and 2024, we completed 70 wells and 41 wells, respectively.

Financing activities.

Net cash flows used in financing activities was $2.1 billion for the year ended December 31, 2022.

Net cash flows provided by financing activities was $0.1 billion for the year ended December 31, 2023.

This increase between periods is primarily due to lower Senior Note redemptions and repurchases of $1.0 billion, decreased share repurchases of $0.8 billion and higher net borrowings on our Credit Facility of $0.3 billion.

Net cash provided by financing activities was $146 million for the year ended December 31, 2023.

Net cash used in financing activities was $135 million for the year ended December 31, 2024.

This decrease in cash provided by financing activities between periods is primarily due lower net borrowings on our Credit Facility of $406 million, partially offset by decreased share repurchases of $75 million and lower distributions to the noncontrolling interests in Martica of $55 million between periods.

Year Ended December 31, 2022 Compared to Year Ended December 31, 2023

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Debt Agreements

Credit Facility

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

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

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

As of December 31, 2023, the borrowing base was $3.5 billion and lender commitments were $1.6 billion.

The next redetermination of the borrowing base is scheduled to occur in April 2024.

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

As of December 31, 2023, we had an outstanding balance under the Credit Facility of $417 million and outstanding letters of credit of $501 million.

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

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

● incur additional indebtedness;

● sell assets;

● make loans to others;

● make investments;

● enter into mergers;

● pay dividends;

● hedge future production;

● incur liens;

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

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

The current ratio and the leverage ratio are tested quarterly.

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

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

As of December 31, 2022 and 2023, we were in compliance with the applicable covenants and ratios under the Credit Facility.

See Note 7—Long Term Debt to the consolidated financial statements included in this Annual Report on Form 10-K for more information on our Credit Facility.

Senior Unsecured Notes

The following table summarizes certain material terms of our Senior Notes and 2026 Convertible Notes outstanding as of December 31, 2023:

Outstanding principal (in thousands)

Interest rate

Maturity date

July 15, 2026

February 1, 2029

March 1, 2030

September 1, 2026

Interest payment dates

Make-whole redemption date (1)

January 15, 2026

February 1, 2027

March 1, 2028

(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.

See Note 7—Long-Term Debt to the consolidated financial statements for more information.

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

Any such repurchases will depend on

prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

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

The amounts involved could be material.

See Note 7—Long-Term Debt to the consolidated financial statements for more information.

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, 2022 and 2023.

We were in compliance with all covenants and ratios applicable to our debt agreements as of December 31, 2023 and 2024.

See Note 7—Long-Term Debt to our consolidated financial statements for additional information.

Critical Accounting Estimates

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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 reported amounts in our consolidated financial statements that are not readily apparent from other sources.

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 reported amounts in our consolidated financial statements 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.

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

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.

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 7% and 25%, respectively, from year end 2024 levels before further evaluation of those properties would be required in order to determine if an impairment charge is necessary.

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We are subject to state and federal income taxes, but are currently not in a cash tax paying position with respect to federal income taxes.

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

We record a valuation allowance or reserve for an uncertain tax position when we believe all or a portion of our deferred income tax assets will not be realized.

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

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

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

Management considers the scheduled reversal of deferred income 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.

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As of December 31, 2024, we have recognized a valuation allowance of $43 million related to Colorado, Oklahoma and West Virginia state NOL carryforwards that we do not expect to realize due to expected future reduced income tax apportionment in those states.

The calculation of deferred income 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.

We believe that the estimates and assumptions related to income taxes are critical because the assumptions and estimates required to assess the likelihood that our deferred income tax assets will be recovered from future taxable income, as well as the amount and timing of a valuation allowance on our deferred income tax assets is an exercise in judgement and susceptible to change as circumstances warrant.

These assumptions affect deferred income tax liability and income tax expense and, if changed, could have a material effect on the Company's financial position and results of operations.

In addition, as of December 31, 2024, we have recorded a reserve for uncertain tax positions of $54 million related to our R&D tax credits.

The calculation of deferred income tax assets and liabilities involves uncertainties in the application of complex tax laws and regulations, as well as judgement on the amount of financial statement benefit recorded for uncertain tax positions.

We recognize in our financial statements those tax positions which we believe are more-likely-than-not to be sustained upon examination by the IRS or state revenue authorities.

We believe that the estimates and assumptions related to income taxes are critical because of the assumptions and estimates required to assess the likelihood that our deferred income tax assets will be recovered from future taxable income, as well as the judgement required to determine the amount and timing of a valuation allowance on our deferred income tax assets and reserve for uncertain tax positions.

These assumptions affect deferred income tax liability and income tax (expense) benefit and, if changed, could have a material effect on the Company's financial position and results of operations.

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