ANTERO RESOURCES Corp
For the period ended Dec 31, 2024. Filed Feb 12, 2025.
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A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2024 · Filed Feb 12, 2025
AR$36.08-0.8%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2023-12-31; filed 2024-02-14.
0001558370-24-001162
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2024-12-31; filed 2025-02-12.
0001558370-25-000864
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 125 previous paragraphs and 104 current paragraphs.
49 unchanged; 43 reworded; 9 added; 30 removed; 3 previous and 3 current paragraphs rearranged.
Tables are not compared: 49 previous and 37 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (9)
Current report
Unsecured Credit Facility
Current report
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.
Current report
Drilling Partnerships
Current report
*Not meaningful
Current report
Lease operating expense. 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.
Current report
*General and administrative expense.*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.
Current report
Equity-based compensation expense. 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.
Current report
Antero Midstream operating expense. 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.
Current report
Interest expense. 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.
Removed paragraphs (30)
Previous report
Share Repurchase Program
Previous report
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.
Previous report
2026 Convertible Notes Conversions
Previous report
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
Previous report
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.
Previous report
Drilling Partnership
Previous report
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.
Previous report
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:
Previous report
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:
Previous report
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.
Previous report
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.
Previous report
*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 andsoftware license costs between periods. We had 586 and 604 employees as of December 31, 2022 and 2023, respectively. General and
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
Loss on early extinguishment of debt. During the year ended December 31, 2022, we redeemed or repurchased through our previously disclosed tender offer and open market transactions (i) the remaining $585 million 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.
Previous report
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.”
Previous report
Credit Facility
Previous report
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.
Previous report
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.
Previous report
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).
Previous report
The Credit Facility contains restrictive covenants that may limit our ability to, among other things:
Previous report
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.
Previous report
As of December 31, 2022 and 2023, we were in compliance with the applicable covenants and ratios under the Credit Facility.
Previous report
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.
Previous report
Senior Unsecured Notes
Previous report
The following table summarizes certain material terms of our Senior Notes and 2026 Convertible Notes outstanding as of December 31, 2023:
Previous report
See Note 7—Long-Term Debt to the consolidated financial statements for more information.
Previous report
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.
Reworded paragraphs (43)
Previous wording
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, 2023, we held approximately 515,000 net acres in the Appalachian Basin. In addition, we estimate that approximately 172,000 net acres of our leasehold may be prospective for the slightly shallower Upper Devonian Shale.
Current wording
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. As of December 31, 2024, we held approximately 521,000 net acres in the Appalachian Basin. In addition, we estimate that approximately 170,000 net acres of our leasehold may be prospective for the slightly shallower Upper Devonian Shale.
Previous wording
As of December 31, 2023, our estimated proved reserves were 18.1 Tcfe, consisting of 10.6 Tcf of natural gas, 690 MMBbl of assumed recovered ethane, 532 MMBbl of C3+ NGLs and 29 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.
Current wording
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. These reserve estimates have been prepared by our internal reserve engineers and management and audited by our independent reserve engineers. 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.
Previous wording
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.
Current wording
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. All of our operations are conducted in the United States. See Note 17—Reportable Segments to our consolidated financial statements for additional information.
Previous wording
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.
Current wording
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.
Previous wording
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. 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. In the current economic environment, we expect that commodity prices for some or all of the commodities we produce could remain volatile. This volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.
Current wording
Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. 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. In the current economic environment, we expect that commodity prices for some or all of the commodities we produce could remain volatile. This volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.
Previous wording
The following table details the average benchmark natural gas and oil prices:
Current wording
The following table details the average benchmark natural gas, NGLs and oil prices:
Previous wording
We are exposed to certain commodity price risks relating to our ongoing business operations, and we use derivative instruments when circumstances warrant to manage such risks. In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. Due to our improved liquidity and leverage position as compared to 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.
Current wording
We are exposed to certain commodity price risks relating to our ongoing business operations, and we use derivative instruments when circumstances warrant to manage such risks. In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased. 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 our consolidated financial statements for additional information.
Previous wording
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. 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:
Current wording
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, 2024, the estimated fair value of Martica’s commodity derivative contracts was a net liability of $2 million. See Note 11—Derivative Instruments to our consolidated financial statements for additional information.
Previous wording
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 2023. 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%. 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%. 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.
Current wording
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 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 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 additional information.
Previous wording
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; 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 by Antero Midstream. All intersegment transactions were eliminated upon consolidation, including revenues from water handling services provided by Antero Midstream, which we capitalized as proved property development costs. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity. See Note 17—Reportable Segments to the consolidated financial statements for more information.
Current wording
We have three reportable segments: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing and utilization of excess firm transportation capacity; and (iii) midstream services through our equity method investment in Antero Midstream. Revenues from Antero Midstream’s operations were primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream. All intersegment transactions were eliminated upon consolidation, including revenues from water handling services provided by Antero Midstream, which we capitalized as proved property development costs. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity. See Note 17—Reportable Segments to our consolidated financial statements for additional information.
Previous wording
Natural gas sales. Revenues from sales of natural gas decreased from $5.5 billion, for the year ended December 31, 2022 to $2.2 billion for the year ended December 31, 2023, a decrease of $3.3 billion, or 60%. 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).
Current wording
Natural gas sales. 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, 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).
Previous wording
NGLs sales. 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). Higher NGLs production volumes during the year ended December 31, 2023 accounted for an approximate $226 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price).
Current wording
NGLs sales. 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).
Previous wording
Oil sales. Revenues from sale of oil decreased from $276 million for the year ended December 31, 2022 to $247 million for the year ended December 31, 2023, a decrease of $29 million, or 10%. Lower oil prices for the year ended December 31, 2023 excluding the effects of derivative settlements) accounted for an approximate $84 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).
Current wording
Oil sales. 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).
Previous wording
Commodity derivative fair value losses. 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.
Current wording
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. 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.
Previous wording
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. 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. Additionally, substantially all of our production is currently unhedged for 2024 and beyond, which limits our exposure to volatility in the fair value of our derivative instruments related to commodity price changes in the future.
Current wording
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. Additionally, substantially all of our production is currently unhedged for 2025 and beyond, which limits our exposure to volatility in the fair value of our derivative instruments related to commodity price changes in the future.
Previous wording
Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP decreased from $38 million for the year ended December 31, 2022 to $31 million for the year ended December 31, 2023, a decrease of $7 million or 19%, primarily due to lower production volumes attributable to the VPP properties between periods. Amortization of the deferred revenues associated with the VPP are recognized as the production volumes are delivered at $1.61 per MMBtu over the contractual term.
Current wording
Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP decreased from $31 million for the year ended December 31, 2023 to $27 million for the year ended December 31, 2024, a decrease of $4 million or 11%, primarily due to lower production volumes attributable to the VPP properties between periods. Amortization of the deferred revenues associated with the VPP are recognized as the production volumes are delivered at $1.61 per MMBtu over the contractual term.
Previous wording
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. This was primarily a result of the following:
Current wording
Gathering, compression, processing and transportation expense. 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:
Previous wording
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.
Current wording
Production and ad valorem tax expense. 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.
Previous wording
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.
Current wording
Depletion, depreciation and amortization expense. 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.
Previous wording
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.
Current wording
Impairment of property and equipment. 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.
Previous wording
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.
Current wording
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.
Previous wording
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.
Current wording
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.
Previous wording
Marketing revenue. Marketing revenue decreased from $417 million for the year ended December 31, 2022 to $206 million for the year ended December 31, 2023, a decrease of $211 million, or 51%. This fluctuation primarily resulted from the following:
Current wording
Marketing revenue. Marketing revenue decreased from $206 million for the year ended December 31, 2023 to $179 million for the year ended December 31, 2024, a decrease of $27 million, or 13%. This fluctuation primarily resulted from the following:
Previous wording
Marketing expense. Marketing expense decreased from $531 million for the year ended December 31, 2022 to $285 million for the year ended December 31, 2023, a decrease of $246 million, or 46%. 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.
Current wording
Marketing expense. Marketing expense decreased from $285 million for the year ended December 31, 2023 to $245 million for the year ended December 31, 2024, a decrease of $40 million, or 14%. 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 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.
Previous wording
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.
Current wording
*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.
Previous wording
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.
Current wording
Antero Midstream revenue. 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.
Previous wording
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.
Current wording
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.
Previous wording
As of December 31, 2023, we had U.S. federal and state NOL carryforwards of $1.0 billion and $1.9 billion, respectively. Many of these NOL carryforwards 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.
Current wording
As of December 31, 2024, we had U.S. federal and state NOL carryforwards of $0.6 billion and $1.9 billion, respectively. Many of these NOL carryforwards expire at various dates between 2025 and 2044 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.
Previous wording
Our primary sources of liquidity have been through net cash provided by operating activities, borrowings under our Credit Facility, issuances of debt and equity securities and additional contributions from our asset sales, including our drilling partnership. Our primary use of cash has been for the exploration, development and acquisition of oil and natural gas properties. As we develop our reserves, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future success in developing our proved reserves and production will be highly dependent on net cash provided by operating activities and the capital resources available to us.
Current wording
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 partnerships. 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 developing our proved reserves and production will be highly dependent on net cash provided by operating activities and the capital resources available to us.
Previous wording
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. 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. Our ability to make significant acquisitions for cash would require us to utilize borrowings on the Credit Facility or obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us, or at all. The Credit Facility is funded by a syndicate of 16 banks. We believe that the participants in the syndicate have the capability to fund up to their current commitment. If one or more banks should not be able to do so, we may not have the full availability of the Credit Facility.
Current wording
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. The Credit Facility is funded by a syndicate of 13 banks. We believe that the participants in the syndicate have the capability to fund up to their current commitment. If one or more banks should not be able to do so, we may not have the full availability of the Credit Facility.
Previous wording
2023 Capital Spending and 2024 Capital Budget
Current wording
Capital Spending and 2025 Capital Budget
Previous wording
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. We completed 70 net horizontal wells during the year ended December 31, 2023. Our net capital budget for 2024 is $725 million to $800 million. Our budget includes: a range of $650 million to $700 million for drilling and completion and $75 million to $100 million for leasehold expenditures. We do not budget for acquisitions. During 2024, we plan to complete 45 to 50 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.
Current wording
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. Our net capital budget for 2025 is $725 million to $800 million. Our budget includes: a range of $650 million to $700 million for drilling and completion and $75 million to $100 million for leasehold expenditures. We do not budget for acquisitions. During 2025, 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.
Previous wording
Based on strip prices as of December 31, 2023, 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.”
Current wording
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 Note 7—Long-Term Debt to our consolidated financial statements.
Previous wording
See Note 14—Commitments to the consolidated financial statements for information on our off-balance sheet arrangements.
Current wording
See Note 14—Commitments to our consolidated financial statements for information on our off-balance sheet arrangements.
Previous wording
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.
Current wording
Operating activities. 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.
Previous wording
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.
Current wording
Investing activities. 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.
Previous wording
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.
Current wording
Financing activities. 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.
Previous wording
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
Current wording
We may, from time to time, seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, open market purchases, privately negotiated transactions or otherwise. Any such repurchases will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved could be material. 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.
Previous wording
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. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in Note 2—Summary of Significant Accounting Policies to our consolidated financial statements. 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 liabilities. Accounting estimates and assumptions are considered to be critical if 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 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.
Current wording
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. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in Note 2—Summary of Significant Accounting Policies to our consolidated financial statements. 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 liabilities. Accounting estimates and assumptions are considered to be critical if 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
Previous wording
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. Impairment of oil and gas properties related to unproved properties for leases that have expired, or are expected to expire, was $91 million, $98 million and $51 million for the years ended December 31, 2021, 2022 and 2023, respectively.
Current wording
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. Impairment of oil and gas properties related to unproved properties for leases that have expired, or are expected to expire, was $98 million, $51 million and $47 million for the years ended December 31, 2022, 2023 and 2024, respectively.
Showing the first 40 of 43 pairs. Open the source sections for the rest.
Rearranged current paragraphs (3)
Current report — wording carried from elsewhere
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, 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.
Current report — wording carried from elsewhere
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.
Current report — wording carried from elsewhere
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
Rearranged previous paragraphs (3)
Previous report — wording carried elsewhere
As of December 31, 2023, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of $32 million. See Note 11—Derivative Instruments to the consolidated financial statements for more information.
Previous report — wording carried elsewhere
As of December 31, 2023, the estimated fair value of Martica’s commodity derivative contracts was a net liability of $5 million. See Note 11—Derivative Instruments to the consolidated financial statements for more information.
Previous report — wording carried elsewhere
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.