ANTERO RESOURCES Corp (AR)

CIK: 0001433270. SIC: 1311 Crude Petroleum & Natural Gas. Latest 10-K as of: 2026-02-11.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas

SEC company page: https://www.sec.gov/edgar/browse/?CIK=1433270. Latest filing source: 0001104659-26-013386.

Selected Fundamentals

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-11. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001433270.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-04-29. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001433270.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

Quarterly Charts

Macro Cross-References

• CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
• UNRATE - Unemployment Rate
• FEDFUNDS - Federal Funds Effective Rate
• CES0500000003 - Average Hourly Earnings of All Employees, Total Private
• DFEDTARU - Federal Funds Target Range - Upper Limit
• DFEDTARL - Federal Funds Target Range - Lower Limit
• DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
• DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
• DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
• DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
• T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
• CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
• CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
• CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
• CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
• PCEPI - Personal Consumption Expenditures: Chain-type Price Index
• PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
• PPIACO - Producer Price Index by Commodity: All Commodities
• T10YIE - 10-Year Breakeven Inflation Rate
• U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
• PAYEMS - All Employees, Total Nonfarm
• CIVPART - Labor Force Participation Rate
• EMRATIO - Employment-Population Ratio
• UNEMPLOY - Unemployed
• CE16OV - Employment Level
• ICSA - Initial Claims
• JTSJOL - Job Openings: Total Nonfarm
• JTSQUR - Quits: Total Nonfarm
• GDPC1 - Real Gross Domestic Product
• A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
• INDPRO - Industrial Production: Total Index
• TCU - Capacity Utilization: Total Index
• HOUST - New Privately-Owned Housing Units Started: Total Units
• PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
• RSAFS - Advance Retail Sales: Retail Trade
• PCE - Personal Consumption Expenditures
• DSPIC96 - Real Disposable Personal Income
• PSAVERT - Personal Saving Rate
• M2SL - M2
• BOPGSTB - U.S. International Trade in Goods and Services: Balance
• MSPUS - Median Sales Price of Houses Sold for the United States
• HSN1F - New One Family Houses Sold: United States
• RHORUSQ156N - Homeownership Rate in the United States
• TTLCONS - Total Construction Spending: Total Construction in the United States
• RRVRUSQ156N - Rental Vacancy Rate in the United States
• TOTALSL - Total Consumer Credit Owned and Securitized
• REVOLSL - Revolving Consumer Credit Owned and Securitized
• DRCCLACBS - Delinquency Rate on Credit Card Loans, All Commercial Banks
• GDP - Gross Domestic Product
• GPDI - Gross Private Domestic Investment
• GCE - Government Consumption Expenditures and Gross Investment
• PCEC - Personal Consumption Expenditures
• NETEXP - Net Exports of Goods and Services
• GFDEBTN - Federal Debt: Total Public Debt
• GFDEGDQ188S - Federal Debt: Total Public Debt as Percent of Gross Domestic Product
• FYFSD - Federal Surplus or Deficit
• FGRECPT - Federal Government Current Receipts
• FGEXPND - Federal Government: Current Expenditures
• MANEMP - All Employees, Manufacturing
• USCONS - All Employees, Construction
• USTRADE - All Employees, Retail Trade
• USFIRE - All Employees, Financial Activities
• USGOVT - All Employees, Government
• AWHAETP - Average Weekly Hours of All Employees, Total Private
• DGORDER - Manufacturers' New Orders: Durable Goods
• NEWORDER - Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
• BUSINV - Total Business Inventories
• EXPGS - Exports of Goods and Services
• IMPGS - Imports of Goods and Services
• IR - Import Price Index (End Use): All Commodities
• PPIFIS - Producer Price Index by Commodity: Final Demand

Latest quarter (10-Q)

Latest 10-Q source: 0001104659-26-051530.

Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high. Filing date: 2026-04-29. Report date: 2026-03-31.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

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

Our Company

We have assembled a portfolio of long-lived properties that are characterized by what we believe to be high repeatability and low geologic risk. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to develop our reserves and production, primarily on our existing multi-year inventory of drilling locations in the Appalachian Basin. As of March 31, 2026, we held approximately 855,000 net acres in the Appalachian Basin.

HG Acquisition

On December 5, 2025, we entered into a definitive agreement to acquire 100% of the issued and outstanding equity interests of HG Production for total cash consideration of $2.8 billion, subject to the terms and conditions thereof. The HG Acquisition included approximately 385,000 net acres in the core of the Marcellus Shale in West Virginia. This acquisition closed on February 3, 2026. The HG Acquisition was funded with borrowings under the Term Loan, net proceeds of the 2036 Notes, borrowings under the Credit Facility and restricted cash. See Note 3—Transactions to our unaudited condensed consolidated financial statements for additional information. The Company’s condensed consolidated statement of operations for the three months ended March 31, 2026 included results of operations from the assets and operations acquired in the HG Acquisition from February 3, 2026 through March 31, 2026.

In light of the nature and location of the assets and operations acquired in the HG Acquisition, we and Antero Midstream agreed in principle to certain updates to, and intend to modify, our existing commercial arrangements to provide for on-pad compression with respect to certain wells and to provide certain water services. See Note 15—Related Parties to our unaudited condensed consolidated financial statements for additional information.

Utica Shale Divestiture

On December 5, 2025, we entered into a purchase and sale agreement with the Buyer Parties to sell our Utica Shale Properties for aggregate cash consideration of $800 million, subject to the terms and conditions thereof. The Utica Shale Properties included approximately 80,000 gross (70,000 net) acres located in Ohio and proved reserves of approximately 600 Bcfe as of December 31, 2025. The Utica Shale Divestiture closed on February 23, 2026, with an effective date of July 1, 2025. The net proceeds from the Utica Shale Divestiture were used for the repayment of long-term debt. See Note 3—Transactions to our unaudited condensed consolidated financial statements for additional information.

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Financing Highlights

Issuance of 2036 Notes

On January 28, 2026, we issued $750 million of 5.400% senior notes due February 1, 2036 at a price of 99.869% of par. The 2036 Notes are unsecured and rank pari passu to our Credit Facility, Term Loan and other outstanding senior notes. The 2036 Notes are not guaranteed by any of our subsidiaries. The net proceeds from this offering were used to partially fund the HG Acquisition. See Note 3—Transactions and Note 7—Long-Term Debt to our unaudited condensed consolidated financial statements for additional information.

Term Loan

On February 3, 2026, substantially concurrently with the consummation of the HG Acquisition, we entered into an unsecured three year term loan facility in an aggregate principal amount of $1.5 billion with the lenders party thereto and Royal Bank of Canada, as administrative agent. Borrowings are unsecured and are not guaranteed by any of our subsidiaries. On February 3, 2026, we borrowed $1.5 billion in a single borrowing to partially fund the HG Acquisition. The Term Loan is scheduled to mature on February 3, 2029. See Note 3—Transactions and Note 7—Long-Term Debt to our unaudited condensed consolidated financial statements for additional information.

Redemption of 2029 Notes

During the three months ended March 31, 2026, we redeemed the remaining $365 million principal amount of the 2029 Notes at 101.271% of the principal amount thereof, plus accrued and unpaid interest, and the 2029 Notes were fully retired on such date. See Note 7—Long-Term Debt to our unaudited condensed consolidated financial statements for additional information.

Market Conditions and Business Trends

Commodity Markets

Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Benchmark prices for natural gas increased significantly, while benchmark prices for ethane and C3+ NGLs decreased and benchmark prices for oil remained relatively consistent during the three months ended March 31, 2026 as compared to the same period of 2025. As a result of the higher benchmark natural gas prices during the three months ended March 31, 2026, we experienced an increase in price realization for natural gas products, partially offset by the effects of decreased benchmark ethane and C3+ NGLs prices as compared to the three months ended March 31, 2025. 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, Venezuela 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. However, we use derivative instruments when circumstances warrant to manage our exposure to commodity price risk. See “—Hedge Position” and Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements for additional information on our derivative instruments.

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

​

​

​

​

​

​

​

​

​

​

Three Months Ended March 31,

​

​

  ​ ​

2025

  ​ ​

2026

​

Henry Hub ($/Mcf) (1)

​

$

3.65

​

​

5.04

​

Mont Belvieu Ethane ($/Bbl) (2)

​

​

11.46

​

​

9.87

​

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

​

​

43.99

​

​

36.89

​

West Texas Intermediate ($/Bbl) (4)

​

​

71.42

​

​

71.93

​

(1)

NYMEX first of month average natural gas price.

(2)

Intercontinental Exchange, Inc. (“ICE”) settlement ethane Oil Price Information Service (“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.

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Hedge Position

Antero Resources

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. For the three months ended March 31, 2025 and 2026, 4% and 42%, respectively, of our production was hedged through commodity derivatives, excluding basis swaps. Assuming our 2026 production is the same as our production in 2025, approximately 54% of our total production for 2026 is hedged through commodity derivatives, excluding basis swaps. In addition, for the three months ended March 31, 2025 and 2026, zero and 12%, respectively, of our production was hedged with basis swap commodity derivatives. Assuming our 2026 production is the same as our production in 2025, approximately 20% of our total production for 2026 is hedged with basis swap commodity derivatives. As of March 31, 2026, the estimated fair value of our commodity derivative contracts was a net asset of $202 million. See Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements for additional information.

Martica

Our consolidated VIE, Martica, previously maintained 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 were fully attributable to the noncontrolling interests in Martica. During the three months ended March 31, 2025, all of Martica’s derivative contracts expired. As of March 31, 2026, Martica had no derivative instruments. See Note 11—Derivative Instruments to our unaudited condensed 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 2026. 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 1.75% in 2024 and 2025. Annual inflation rates have remained generally consistent at approximately 3% since 2023.

The economy also continues to be impacted by the effects of global events. These events have often caused global supply chain disruptions with additional pressure due to trade sanctions, tariffs, other glob

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-11. Report date: 2025-12-31.

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

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

Our Company

We have assembled a portfolio of long-lived properties that are characterized by what we believe to be high repeatability and low geologic risk. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to develop our reserves and production, primarily on our existing multi-year inventory of drilling locations in the Appalachian Basin. As of December 31, 2025, we held approximately 537,000 net acres in the Appalachian Basin. In addition, we estimate that approximately 168,000 net acres of our leasehold may be prospective for the slightly shallower Upper Devonian Shale.

As of December 31, 2025, our estimated proved reserves were 19.1 Tcfe, consisting of 11.8 Tcf of natural gas, 679 MMBbl of assumed recovered ethane, 529 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, 2025, we had 1,279 potential horizontal well locations on our existing leasehold acreage that were classified as proved, probable and possible.

We have three reportable segments: exploration and production, our equity method investment in Antero Midstream and marketing. All of our operations are conducted in the United States. See Note 17—Reportable Segments to our consolidated financial statements for additional information.

HG Acquisition

On December 5, 2025, we entered into a definitive agreement to acquire 100% of the issued and outstanding equity interests of HG Production from HG Energy for total cash consideration of $2.8 billion, subject to the terms and conditions thereof. The HG Acquisition includes approximately 385,000 net acres in the core of the Marcellus Shale in West Virginia. Pursuant to the same agreement, Antero Midstream Partners agreed to acquire 100% of the issued and outstanding equity interests of HG Midstream from HG Energy for cash consideration of $1.1 billion, subject to the terms and conditions thereof. The HG Midstream Acquisition includes gathering pipelines and integrated water handling assets in the core of the Marcellus Shale in West Virginia. These acquisitions closed on February 3, 2026. The HG Acquisition was funded with borrowings under the Term Loan A Facility, net proceeds of the 2036 Notes (as defined below), borrowings under the Credit Facility and restricted cash. See Note 3—Transactions to our consolidated financial statements for additional information. We intend to make certain modifications to our existing commercial arrangements with Antero Midstream to provide for on-pad compression with respect to certain wells and to provide a transition period through 2026 before certain water services would be provided under the existing agreements with Antero Midstream.

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Utica Shale Divestiture

On December 5, 2025, we entered into a definitive agreement with the Buyer Parties to sell our Utica Shale Properties for aggregate cash consideration of $800 million, subject to the terms and conditions thereof. The Utica Shale Properties include approximately 80,000 gross (70,000 net) acres located in Ohio and proved reserves of approximately 600 Bcfe as of December 31, 2025. The Utica Shale Divestiture is expected to close in February 2026, subject to the satisfaction of certain customary closing conditions. The net proceeds from the Utica Shale Divestiture are expected to be used for the repayment of long-term debt. See Note 3—Transactions to our consolidated financial statements for additional information.

Financing Highlights

Credit Facility Maturity Date Extension

Effective July 30, 2025, we obtained the consent of each of the lenders under our Unsecured Credit Facility to extend the Maturity Date from July 30, 2029 to July 30, 2030. The terms of the Unsecured Credit Facility otherwise remain unchanged. Under the terms of the Unsecured Credit Facility, we may request two one-year extensions of the Maturity Date, subject to the satisfaction of certain conditions. This is the first such extension. See Note 7—Long-Term Debt to our consolidated financial statements for additional information.

Issuance of the 2036 Senior Notes

​

On January 28, 2026, we issued $750 million of 5.400% senior notes due February 1, 2036 (the “2036 Notes”) at a price of 99.869% of par. The 2036 Notes are unsecured and rank pari passu to our Unsecured Credit Facility and Term Loan A Facility and other outstanding senior notes. The 2036 Notes are not guaranteed by any of our subsidiaries. The net proceeds from this offering were used to partially fund the HG Acquisition. See Note 3—Transactions and Note 7—Long-Term Debt to our consolidated financial statements for additional information.

​

Notice of Redemption of 2029 Notes

​

On February 9, 2026, we notified the holders of our 7.625% senior notes due February 1, 2029 (the “2029 Notes”) of our intent to redeem all $365 million aggregate principal amount of our 2029 Notes on February 24, 2026, subject to certain conditions, including the closing of the Utica Shale Divestiture, at a redemption price of 101.271%, plus accrued and unpaid interest.

​

Term Loan A

​

On February 3, 2026, substantially concurrently with the consummation of the HG Acquisition, we entered into an unsecured three year term loan facility in an aggregate principal amount of $1.5 billion with the Royal Bank of Canada, RBC Capital Markets and JPMorgan Chase Bank, N.A. (collectively, the “Banks”). Borrowings are unsecured and are not guaranteed by any of our subsidiaries. On February 3, 2026, we borrowed $1.5 billion in a single borrowing to partially fund the HG Acquisition. The Term Loan A Facility is scheduled to mature on February 3, 2029. See Note 3—Transactions and See Note 7—Long-Term Debt to our consolidated financial statements for additional information.

​

Debt Repurchase Program

​

During the year ended December 31, 2025, we redeemed the remaining $97 million aggregate principal amount of our 8.375% senior notes due July 15, 2026 (the “2026 Notes”) at a redemption price of 102.094% of the principal amount thereof, plus accrued and unpaid interest. In addition, we repurchased $42 million aggregate principal amount of our 2029 Notes through open market transactions at a weighted average price of approximately 103% of the principal amount thereof, plus accrued and unpaid interest. See Note 7—Long-Term Debt to our consolidated financial statements for additional information.

​

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. Through our share repurchase program, during the year ended December 31, 2025, we repurchased and retired approximately 4 million shares of our common stock at a total cost of $136 million. As of December 31, 2025, we have approximately $914 million of capacity 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.

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Market Conditions and Business Trends

Commodity Markets

Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Benchmark prices for natural gas and ethane increased significantly, while benchmark prices for C3+ NGLs and oil decreased, during the year ended December 31, 2025 as compared to the year ended December 31, 2024. As a result of the higher benchmark natural gas and ethane prices during the year ended December 31, 2025, we experienced an increase in price realization for natural gas and ethane products, partially offset by the effects of decreased benchmark NGLs and oil prices as compared to the year ended December 31, 2024. 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, Venezuela 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. However, we use derivative instruments when circumstances warrant to manage our exposure to commodity price risk. See “—Hedge Position” and Note 11—Derivative Instruments to our consolidated financial statements for additional information on our derivative instruments.

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

​

​

​

​

​

​

​

​

​

​

Year Ended December 31,

​

​

  ​ ​

2024

  ​ ​

2025

​

Henry Hub ($/Mcf) (1)

​

$

2.27

​

​

3.43

​

Mont Belvieu Ethane ($/Bbl) (2)

​

​

8.00

​

​

10.61

​

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

​

​

40.82

​

​

37.93

​

West Texas Intermediate ($/Bbl) (4)

​

​

75.72

​

​

64.81

​

(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

Antero Resources

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. For the years ended December 31, 2024 and 2025, 4% and 8%, respectively, of our production was hedged through commodity derivatives. Assuming our 2026 production is the same as our production in 2025, approximately 42% of our total production is hedged through commodity derivatives. In addition, we also have derivative contracts in place for a portion of our 2027 production. As of December 31, 2025, the estimated fair value of our commodity derivative contracts was a net asset of $81 million. See Note 11—Derivative Instruments to our consolidated financial statements for additional information.

Martica

Our consolidated VIE, Martica, previously maintained 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 were fully attributable to the noncontrolling interests in Martica. During the three months ended March 31, 2025, all of Martica’s derivative contracts expired. As of December 31, 2025, Martica had no derivative instruments. See Note 11—Derivative Instruments to our consolidated financial statements for additional information.

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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. 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 2022 in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis. Between 2022 and 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 1.75% in 2024 and 2025. While inflationary pressures in the United States’ economy have begun to subside, it is uncertain what impact recent tariff activity by the United States and foreign governments will have on inflation. See “—Results of Operations” for additional information.

The economy also continues to be impacted by the effects of global events. These events have often caused global supply chain disruptions with additional pressure due to trade sanctions, tariffs, other global trade restrictions and conflicts, including those in the Middle East, Iran and Venezuela, among others. While our supply chain has not experienced any significant interruptions as a result of such events, there can be no assurance that we will not experience interruptions in the future.

Inflationary pressures, particularly as they relate to certain of our long-term contracts with CPI-based adjustments, and supply chain disruptions have and could continue to result in increases to our operating and capital costs that are not fixed. These economic variables are beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.

Sources of Our Revenues

​

●

Natural gas, NGLs and oil sale revenues. Our revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from our natural gas during processing. Our production is entirely from within the continental United States; however, some of our production revenues are attributable to customers who export our products. During 2024 and 2025, our production revenues were comprised of 44% and 57%, respectively, from the sale of natural gas and 56% and 43%, respectively, from the sale of NGLs and oil. Natural gas, NGLs and oil prices are inherently volatile and are influenced by many factors outside of our control. All of our production is derived from natural gas wells, some of which also produce NGLs which are extracted through processing, and oil.

●

Commodity derivatives. We utilize derivative instruments to hedge future sales prices for our production when circumstances warrant. We currently utilize call and embedded put options, basis swap contracts that hedge the difference between the NYMEX index price and a local index price, collar contracts and fixed price contracts for a portion of our natural gas in which we receive or pay the difference between a fixed price and the variable market price received. Assuming our 2026 production is the same as our production in 2025, approximately 42% of our total production for 2026 is hedged through commodity derivatives. In addition, we have derivative contracts in place for a portion of our 2027 production. 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, and because we have not elected hedge accounting, we recognize changes in the fair value of these derivative instruments in earnings. We expect continued volatility in the prices we receive for our production and the fair value of our derivative instruments.

●

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

●

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

Principal Components of Our Cost Structure

●

Lease operating expenses. These are the operating costs incurred to maintain our production. Such costs include produced water hauling, water handling, water disposal, and labor-related costs to monitor producing wells, maintenance, repairs and workover expenses. Cost levels for these expenses can vary based on the volume of water produced, supply and demand for oilfield services, activity levels, and other factors.

●

Gathering, compression, processing and transportation. These costs include the fees paid to Antero Midstream and other third parties who operate low and high pressure gathering and compression systems that transport our gas. They also include costs to process and extract NGLs from our liquids-rich gas and to transport our natural gas, NGLs and oil to market. We often enter into fixed price long-term contracts that secure transportation and processing capacity, which may include

52

Table of Contents

minimum volume commitments, the cost for which is included in these expenses to the extent that they are not associated with excess capacity. Costs associated with excess capacity are included in marketing expenses.

●

Water handling. Water handling expenses relate to the direct operating costs attributable to fresh water and other fluid handling services.

●

Production and ad valorem taxes. Production and ad valorem taxes consist of severance and ad valorem taxes. Severance taxes are paid on produced natural gas and oil based on a percentage of sales prices, which exclude the effects of our derivative instruments, or at fixed per-unit rates established by state authorities. Ad valorem taxes are paid based on the value of our reserves as well as the value of property and equipment.

●

Marketing expenses. We purchase and sell third-party natural gas and NGLs and market our excess capacity under long-term contracts. Marketing costs include the cost of purchased third-party natural gas and NGLs. We also classify firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize this excess capacity as marketing expenses, 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.

●

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

●

Impairment of property and equipment. 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. We record impairment charges for proved properties on a geological reservoir basis when events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. We also record impairment charges for other property and equipment when events or changes in circumstances indicate that the carrying amount of such property and/or equipment may not be recoverable.

●

Depletion, depreciation and amortization. DD&A includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas, NGLs and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts and allocate these costs using the units of production method. Depreciation is computed over an asset’s estimated useful life using the straight-line basis.

●

General and administrative expense. These costs include overhead, including payroll and benefits for our staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other professional fees, insurance, legal expenses and other administrative expenses. General and administrative expense also includes noncash equity-based compensation expense. 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 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, 2024 and 2025, we had an outstanding balance on the Credit Facility of $393 million and $439 million, respectively, with a weighted average interest rate of 5.9% and 5.3%, 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, 2024 and 2025, we had fixed interest rates on our Senior Notes ranging from 5.375% to 8.375% and 5.375% to 7.625%, respectively, with an aggregate principal balance of $1.1 billion and $1.0 billion, respectively. 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) 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. 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.

53

Table of Contents

Results of Operations

We have three reportable segments: exploration and production, our equity method investment in Antero Midstream and marketing. 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.

Year Ended December 31, 2024 Compared to Year Ended December 31, 2025

The operating results of our reportable segments were as follows (in thousands):

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 2024

​

​

​

​

​

​

​

Equity Method

​

​

​

​

​

​

​

Exploration

​

​

​

Investment in

​

Elimination of

​

​

​

​

​

and

​

​

​

Antero

​

Unconsolidated

​

Consolidated

​

​

Production

Marketing

Midstream (1)

Affiliate

Total

Revenue and other:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Natural gas sales

​

$

1,818,297

​

​

—

​

​

—

​

​

—

​

​

1,818,297

​

Natural gas liquids sales

​

​

2,066,975

​

​

—

​

​

—

​

​

—

​

​

2,066,975

​

Oil sales

​

​

230,027

​

​

—

​

​

—

​

​

—

​

​

230,027

​

Commodity derivative fair value gains

​

​

731

​

​

—

​

​

—

​

​

—

​

​

731

​

Gathering, compression and water handling

​

​

—

​

​

—

​

​

1,106,193

​

​

(1,106,193)

​

​

—

​

Marketing

​

​

—

​

​

179,069

​

​

—

​

​

—

​

​

179,069

​

Amortization of deferred revenue, VPP

​

​

27,101

​

​

—

​

​

—

​

​

—

​

​

27,101

​

Other revenue and income

​

​

3,396

​

​

—

​

​

—

​

​

—

​

​

3,396

​

Total revenue

​

​

4,146,527

​

​

179,069

​

​

1,106,193

​

​

(1,106,193)

​

​

4,325,596

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Operating expenses:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Lease operating

​

​

118,693

​

​

—

​

​

—

​

​

—

​

​

118,693

​

Gathering and compression

​

​

897,160

​

​

—

​

​

103,053

​

​

(103,053)

​

​

897,160

​

Processing

​

​

1,069,887

​

​

—

​

​

—

​

​

—

​

​

1,069,887

​

Transportation

​

​

735,883

​

​

—

​

​

—

​

​

—

​

​

735,883

​

Water handling

​

​

—

​

​

—

​

​

114,923

​

​

(114,923)

​

​

—

​

Production and ad valorem taxes

​

​

207,671

​

​

—

​

​

—

​

​

—

​

​

207,671

​

Marketing

​

​

—

​

​

244,906

​

​

—

​

​

—

​

​

244,906

​

Exploration

​

​

2,618

​

​

—

​

​

—

​

​

—

​

​

2,618

​

General and administrative (excluding equity-based compensation)

​

​

162,876

​

​

—

​

​

41,754

​

​

(41,754)

​

​

162,876

​

Equity-based compensation

​

​

66,462

​

​

—

​

​

44,332

​

​

(44,332)

​

​

66,462

​

Depletion, depreciation and amortization

​

​

762,068

​

​

—

​

​

140,000

​

​

(140,000)

​

​

762,068

​

Impairment of property and equipment

​

​

47,433

​

​

—

​

​

332

​

​

(332)

​

​

47,433

​

Accretion of asset retirement obligations

​

​

3,759

​

​

—

​

​

—

​

​

—

​

​

3,759

​

Loss on sale of assets

​

​

862

​

​

—

​

​

—

​

​

—

​

​

862

​

Contract termination, loss contingency, settlements and other operating expenses

​

​

4,858

​

​

—

​

​

2,633

​

​

(2,633)

​

​

4,858

​

Total operating expenses

​

​

4,080,230

​

​

244,906

​

​

447,027

​

​

(447,027)

​

​

4,325,136

​

Operating income (loss)

​

$

66,297

​

​

(65,837)

​

​

659,166

​

​

(659,166)

​

​

460

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Equity in earnings of unconsolidated affiliates

​

$

93,787

​

​

—

​

​

110,573

​

​

(110,573)

​

​

93,787

​

(1)

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

​

​

54

Table of Contents

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 2025

​

​

​

​

​

​

​

Equity Method

​

​

​

​

​

​

​

Exploration

​

​

​

Investment in

​

Elimination of

​

​

​

​

​

and

​

​

​

Antero

​

Unconsolidated

​

Consolidated

​

​

Production

Marketing

Midstream (1)

Affiliate

Total

Revenue and other:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Natural gas sales

​

$

2,873,241

​

​

—

​

​

—

​

​

—

​

​

2,873,241

​

Natural gas liquids sales

​

​

1,986,840

​

​

—

​

​

—

​

​

—

​

​

1,986,840

​

Oil sales

​

​

150,158

​

​

—

​

​

—

​

​

—

​

​

150,158

​

Commodity derivative fair value gains

​

​

111,049

​

​

—

​

​

—

​

​

—

​

​

111,049

​

Gathering, compression and water handling

​

​

—

​

​

—

​

​

1,188,426

​

​

(1,188,426)

​

​

—

​

Marketing

​

​

—

​

​

125,900

​

​

—

​

​

—

​

​

125,900

​

Amortization of deferred revenue, VPP

​

​

25,264

​

​

—

​

​

—

​

​

—

​

​

25,264

​

Other revenue and income

​

​

3,371

​

​

—

​

​

—

​

​

—

​

​

3,371

​

Total revenue

​

​

5,149,923

​

​

125,900

​

​

1,188,426

​

​

(1,188,426)

​

​

5,275,823

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Operating expenses:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Lease operating

​

​

135,124

​

​

—

​

​

—

​

​

—

​

​

135,124

​

Gathering and compression

​

​

946,900

​

​

—

​

​

107,846

​

​

(107,846)

​

​

946,900

​

Processing

​

​

1,125,358

​

​

—

​

​

—

​

​

—

​

​

1,125,358

​

Transportation

​

​

785,168

​

​

—

​

​

—

​

​

—

​

​

785,168

​

Water handling

​

​

—

​

​

—

​

​

124,064

​

​

(124,064)

​

​

—

​

Production and ad valorem taxes

​

​

163,135

​

​

—

​

​

—

​

​

—

​

​

163,135

​

Marketing

​

​

—

​

​

190,206

​

​

—

​

​

—

​

​

190,206

​

Exploration

​

​

2,990

​

​

—

​

​

—

​

​

—

​

​

2,990

​

General and administrative (excluding equity-based compensation)

​

​

171,714

​

​

—

​

​

41,976

​

​

(41,976)

​

​

171,714

​

Equity-based compensation

​

​

60,812

​

​

—

​

​

45,958

​

​

(45,958)

​

​

60,812

​

Depletion, depreciation and amortization

​

​

749,675

​

​

—

​

​

134,310

​

​

(134,310)

​

​

749,675

​

Impairment of property and equipment

​

​

29,358

​

​

—

​

​

984

​

​

(984)

​

​

29,358

​

Accretion of asset retirement obligations

​

​

3,892

​

​

—

​

​

—

​

​

—

​

​

3,892

​

Gain on sale of assets

​

​

(266)

​

​

—

​

​

—

​

​

—

​

​

(266)

​

Loss on long-lived assets

​

​

—

​

​

—

​

​

86,626

​

​

(86,626)

​

​

—

​

Contract termination, loss contingency, settlements and other operating expenses

​

​

28,111

​

​

—

​

​

1,993

​

​

(1,993)

​

​

28,111

​

Total operating expenses

​

​

4,201,971

​

​

190,206

​

​

543,757

​

​

(543,757)

​

​

4,392,177

​

Operating income (loss)

​

$

947,952

​

​

(64,306)

​

​

644,669

​

​

(644,669)

​

​

883,646

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Equity in earnings of unconsolidated affiliates

​

$

98,484

​

​

—

​

​

116,439

​

​

(116,439)

​

​

98,484

​

(1)

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

​

55

Table of Contents

Exploration and Production Segment

The following table sets forth selected operating data of the exploration and production segment:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended

​

Amount of

​

​

​

​

​

​

December 31,

​

Increase

​

Percent

​

​

​

  ​ ​

2024

  ​ ​

2025

  ​ ​

(Decrease)

  ​ ​

Change

​

​

Production data (1) (2):

​

​

​

​

​

​

​

​

​

​

​

​

​

Natural gas (Bcf)

​

​

793

​

​

808

​

​

15

​

2

%

​

C2 Ethane (MBbl)

​

​

30,391

​

​

29,842

​

​

(549)

​

(2)

%

​

C3+ NGLs (MBbl)

​

​

42,434

​

​

42,010

​

​

(424)

​

(1)

%

​

Oil (MBbl)

​

​

3,693

​

​

2,899

​

​

(794)

​

(22)

%

​

Combined (Bcfe)

​

​

1,252

​

​

1,256

​

​

4

​

*

​

​

Daily combined production (MMcfe/d)

​

​

3,421

​

​

3,442

​

​

21

​

1

%

​

Average prices before effects of derivative settlements (3):

​

​

​

​

​

​

​

​

​

​

​

​

​

Natural gas (per Mcf)

​

$

2.29

​

​

3.56

​

​

1.27

​

55

%

​

C2 Ethane (per Bbl) (4)

​

$

9.05

​

​

11.91

​

​

2.86

​

32

%

​

C3+ NGLs (per Bbl)

​

$

42.23

​

​

38.83

​

​

(3.40)

​

(8)

%

​

Oil (per Bbl)

​

$

62.29

​

​

51.80

​

​

(10.49)

​

(17)

%

​

Weighted Average Combined (per Mcfe)

​

$

3.29

​

​

3.99

​

​

0.70

​

21

%

​

Average realized prices after effects of derivative settlements (3):

​

​

​

​

​

​

​

​

​

​

​

​

​

Natural gas (per Mcf)

​

$

2.30

​

​

3.54

​

​

1.24

​

54

%

​

C2 Ethane (per Bbl) (4)

​

$

9.05

​

​

11.91

​

​

2.86

​

32

%

​

C3+ NGLs (per Bbl)

​

$

42.36

​

​

38.83

​

​

(3.53)

​

(8)

%

​

Oil (per Bbl)

​

$

62.15

​

​

51.76

​

​

(10.39)

​

(17)

%

​

Weighted Average Combined (per Mcfe)

​

$

3.30

​

​

3.97

​

​

0.67

​

20

%

​

Average costs (per Mcfe):

​

​

​

​

​

​

​

​

​

​

​

​

​

Lease operating

​

$

0.09

​

​

0.11

​

​

0.02

​

22

%

​

Gathering and compression

​

$

0.72

​

​

0.75

​

​

0.03

​

4

%

​

Processing

​

$

0.85

​

​

0.90

​

​

0.05

​

6

%

​

Transportation

​

$

0.59

​

​

0.62

​

​

0.03

​

5

%

​

Production and ad valorem taxes

​

$

0.17

​

​

0.13

​

​

(0.04)

​

(24)

%

​

Marketing expense, net

​

$

0.05

​

​

0.05

​

​

—

​

*

​

​

General and administrative (excluding equity-based compensation)

​

$

0.13

​

​

0.14

​

​

0.01

​

8

%

​

Depletion, depreciation, amortization and accretion

​

$

0.61

​

​

0.60

​

​

(0.01)

​

(2)

%

​

*Not meaningful

(1)

Production data excludes volumes related to the VPP.

(2)

Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and may not reflect their relative economic value.

(3)

Average prices reflect the before and after effects of our settled commodity derivatives. Our calculation of such after effects includes gains (losses) on settlements of commodity derivatives, 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, 2024 and 2025 includes $2 million and $1 million, respectively, of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives for the years ended December 31, 2024 and 2025 would have been $8.99 per Bbl and $11.88 per Bbl, respectively.

​

Natural gas sales. Revenues from sales of natural gas increased from $1.8 billion for the year ended December 31, 2024 to $2.9 billion for the year ended December 31, 2025, an increase of $1.1 billion, or 58%. Higher commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2025 accounted for an approximate $1.0 billion increase in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes). Higher natural gas production volumes accounted for an approximate $34 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).

NGLs sales. Revenues from sales of NGLs decreased from $2.1 billion for the year ended December 31, 2024 to $2.0 billion for the year ended December 31, 2025, a decrease of $0.1 billion, or 4%. Lower C3+ NGLs commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2025 accounted for an approximate $143 million decrease in year-over-year NGLs revenues (calculated as the change in the year-to-year average price times current year production volumes), partially offset by higher ethane commodity prices during the year ended December 31, 2025 that accounted for an approximate $85 million increase in year-over-year NGLs revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower NGLs production volumes during the year ended December 31, 2025 accounted for an approximate $23 million decrease in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price).

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Oil sales. Revenues from sale of oil decreased from $230 million for the year ended December 31, 2024 to $150 million for the year ended December 31, 2025, a decrease of $80 million, or 35%. Lower oil production volumes during the year ended December 31, 2025 accounted for an approximate $50 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, 2025 (excluding the effects of derivative settlements) accounted for an approximate $30 million decrease in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes).

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, 2024 and 2025, our commodity hedges resulted in derivative fair value gains of $1 million and $111 million, respectively. For the year ended December 31, 2024, commodity derivative fair value gains included $10 million of net cash proceeds for settled derivative gains. For the year ended December 31, 2025, commodity derivative fair value gains included $17 million of net cash payments for settled derivative losses.

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.

Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP decreased from $27 million for the year ended December 31, 2024 to $25 million for the year ended December 31, 2025, a decrease of $2 million or 7%, 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.

Lease operating expense. Lease operating expense increased from $119 million, or $0.09 per Mcfe, for the year ended December 31, 2024 to $135 million, or $0.11 per Mcfe, for the year ended December 31, 2025, an increase of $16 million primarily due to increased produced water volumes and trucking and disposal costs as a result of our completion activity timing during the year ended December 31, 2025, as well as higher oilfield service and workover costs between periods.

Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense increased from $2.7 billion for the year ended December 31, 2024 to $2.9 billion for the year ended December 31, 2025, an increase of $0.2 billion, or 6%. This fluctuation was primarily a result of the following:

●

Gathering and compression costs on a per unit basis increased from $0.72 per Mcfe for the year ended December 31, 2024 to $0.75 per Mcfe for the year ended December 31, 2025, primarily due to increased fuel costs as a result of higher natural gas prices and annual CPI-based adjustments between periods.

●

Processing costs on a per unit basis increased from $0.85 per Mcfe for the year ended December 31, 2024 to $0.90 per Mcfe for the year ended December 31, 2025, primarily due to increased costs for NGLs processing and transportation, which includes an annual CPI-based adjustment during the first quarter of 2025, and higher NGLs transportation fees between periods.

●

Transportation costs on a per unit basis increased from $0.59 per Mcfe for the year ended December 31, 2024 to $0.62 per Mcfe for the year ended December 31, 2025, primarily due to higher fuel costs as a result of higher natural gas prices between periods and higher demand fees for certain pipelines during the year ended December 31, 2025.

Production and ad valorem tax expense. Production and ad valorem taxes decreased from $208 million for the year ended December 31, 2024 to $163 million for the year ended December 31, 2025, a decrease of $45 million or 21%, primarily due to lower ad valorem taxes of $115 million between periods, partially offset by higher severance taxes of $70 million as a result of increased natural gas prices during the year ended December 31, 2025. Production and ad valorem taxes as a percentage of natural gas revenues decreased from 11% for the year ended December 31, 2024 to 6% for the year ended December 31, 2025, primarily as a result of lower ad valorem taxes between periods. West Virginia ad valorem taxes in 2024 were based on commodity prices during 2022, and West Virginia ad valorem taxes in 2025 are based on commodity prices during 2023.

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General and administrative expense. General and administrative expense (excluding equity-based compensation expense) increased from $163 million for the year ended December 31, 2024 to $172 million for the year ended December 31, 2025, an increase of $9 million, or 5%, primarily due to higher professional service fees and increased salary and wage expense as a result of increased employee headcount between periods. We had 616 and 632 employees as of December 31, 2024 and 2025, respectively. General and administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.13 per Mcfe for the year ended December 31, 2024 to $0.14 per Mcfe for the year ended December 31, 2025 primarily as a result of higher overall costs between periods.

Equity-based compensation expense. Non-cash equity-based compensation expense decreased from $66 million for the year ended December 31, 2024 to $61 million for the year ended December 31, 2025, a decrease of $5 million or 9%. This decrease was primarily due to lower performance share unit (“PSU”) award grants between periods. See Note 9—Equity-Based Compensation to our consolidated financial statements for additional information.

Depletion, depreciation and amortization expense. DD&A expense decreased from $762 million for the year ended December 31, 2024 to $750 million for the year ended December 31, 2025, a decrease of $12 million or 2%, primarily as a result of increased proved reserve volumes due to higher commodity prices. DD&A expense per Mcfe remained relatively consistent for the years ended December 31, 2024 and 2025 at $0.61 and $0.60, respectively.

Impairment of property and equipment. Impairment of property and equipment decreased from $47 million for the year ended December 31, 2024 to $29 million for the year ended December 31, 2025, a decrease of $18 million, or 38%, primarily due to lower impairments of expiring leases between periods as a result of our maintenance capital program. 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 increased from $5 million for the year ended December 31, 2024 to $28 million for the year ended December 31, 2025, an increase of $23 million. This increase was primarily due to loss contingencies recorded during the year ended December 31, 2025. See Note 15—Contingencies to our consolidated financial statements for additional information.

Marketing Segment

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

Net marketing expense remained relatively consistent at $66 million, or $0.05 per Mcfe, for the year ended December 31, 2024 and $64 million, or $0.05 per Mcfe, for the year ended December 31, 2025.

Marketing revenue. Marketing revenue decreased from $179 million for the year ended December 31, 2024 to $126 million for the year ended December 31, 2025, a decrease of $53 million, or 30%. This fluctuation primarily resulted from the following:

●

Natural gas marketing revenue decreased by $18 million between periods primarily due to lower natural gas marketing volumes, partially offset by higher natural gas prices. Lower natural gas marketing volumes accounted for a $24 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher natural gas prices accounted for a $6 million increase 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 decreased by $53 million between periods primarily due to lower oil marketing volumes and prices. Lower oil marketing volumes accounted for a $31 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 oil prices accounted for an $22 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

●

NGLs marketing revenue increased by $8 million between periods primarily due to higher ethane and C3+ NGLs marketing volumes and higher ethane prices.

​

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Marketing expense. Marketing expense decreased from $245 million for the year ended December 31, 2024 to $190 million for the year ended December 31, 2025, a decrease of $55 million, or 22%. 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 commodity purchases decreased by $60 million between periods primarily due to lower marketing volumes and oil prices between periods, partially offset by higher natural gas prices during the year ended December 31, 2025. Firm transportation costs increased $5 million between periods primarily due to the increase in fuel costs and lower pipeline utilization due to maintenance during the year ended December 31, 2025.

Equity Method Investment in Antero Midstream Segment

Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $1.1 billion for the year ended December 31, 2024 to $1.2 billion for the year ended December 31, 2025, an increase of $0.1 billion. This increase is primarily due to higher gathering and processing revenues of $61 million and higher water handling revenues of $21 million. The increased gathering and processing revenues between periods is primarily a result of increased throughput and annual CPI-based gathering and compression rate adjustments between periods. The increased water handling revenues between periods is primarily due to higher wastewater trucking and blending volumes, increased wastewater trucking and disposal costs that are billed at cost plus 3% higher fresh water delivery volumes and increased blending cost of service fees during the year ended December 31, 2025, as well as an increase to the fresh water delivery rate as a result of the annual CPI-based rate adjustment between periods.

Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $447 million for the year ended December 31, 2024 to $544 million for the year ended December 31, 2025, an increase of $97 million. This increase is primarily due to a loss on long-lived assets of $87 million related to the expected divestiture of its Utica Shale midstream assets, higher direct operating expenses of $14 million as a result of higher wastewater trucking and disposal costs, increased blending costs, increased fresh water delivery volumes, increased throughput, higher gathering and compression costs for assets acquired during the second quarter of 2024 and increased heavy maintenance expense during the year ended December 31, 2025, partially offset by lower depreciation expense of $5 million related to Antero Midstream’s program to repurpose underutilized compressor units to expand existing or construct new compressor stations between periods, partially offset by assets placed in service between periods.

Items Not Allocated to Segments

Interest expense. Interest expense decreased from $118 million for the year ended December 31, 2024 to $84 million for the year ended December 31, 2025, a decrease of $34 million or 29%, primarily due to the redemption or repurchase of $139 million aggregate principal amount of our 2026 Notes and 2029 Notes, as well as lower average Credit Facility borrowings and interest rates during the year ended December 31, 2025.

Loss on early extinguishment of debt. During the year ended December 31, 2024, we recognized a loss on early debt extinguishment of $1 million related to the amendment and restatement of our senior revolving credit facility. During the year ended December 31, 2025, we recognized a loss on early debt extinguishment of $4 million related to the redemption of the remaining $97 million aggregate principal amount of our 2026 Notes at a redemption price of 102.094% of the principal amount thereof, plus accrued and unpaid interest, and the repurchase of $42 million aggregate principal amount of our 2029 Notes through open market transactions at a weighted average price of approximately 103% of the principal amount thereof, plus accrued and unpaid interest. See Note 7—Long-Term Debt to our consolidated financial statements for additional information.

Transaction expense. There were no transaction expenses incurred during the year ended December 31, 2024. During the year ended December 31, 2025, we incurred $4 million of transaction expense related to the HG Acquisition. See Note 3—Transactions to our consolidated financial statements for additional information.

Income tax (expense) benefit. For the year ended December 31, 2024, we recognized 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. For the year ended December 31, 2025, we recognized income tax expense of $216 million, with an effective tax rate of 24%, related to our income before income taxes of $890 million. Our effective tax rate for the year ended December 31, 2025 was different than the federal statutory rate of 21% primarily due to the effects of state income taxes, equity-based compensation expenses, dividends received deduction and noncontrolling interests. See Note 13—Income Taxes to our consolidated financial statements for additional information.

As of December 31, 2025, we had U.S. federal and state NOL carryforwards of approximately $960 million and $1.9 billion, respectively. Many of these NOL carryforwards expire at various dates between 2026 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.

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

Refer to “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2024 for a discussion of the results of operations for the year ended December 31, 2023 compared to the year ended December 31, 2024.

Capital Resources and Liquidity

Overview

Our primary sources of liquidity have been through net cash provided by operating activities, borrowings under our Credit Facility, our Term Loan A 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.

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. Assuming our 2026 production is the same as our production in 2025, approximately 42% of our total production for 2026 is hedged through commodity derivatives. Our ability to make significant acquisitions for cash would require us to utilize borrowings under 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.

Capital Spending and 2026 Capital Budget

For the year ended December 31, 2025, our total consolidated capital expenditures were $797 million, including drilling and completion expenditures of $658 million, leasehold additions of $131 million and other capital expenditures of $8 million. We completed 61 net horizontal wells during the year ended December 31, 2025. Our capital budget for 2026 is $1.1 billion to $1.3 billion and includes: $1.0 billion for drilling and completions, $100 million for leasehold expenditures and up to $200 million for discretionary growth capital that is dependent on commodity prices. Our capital budget reflects the closing of the HG Acquisition on February 3, 2026 and assumes the closing of the Utica Shale Divestiture during February 2026. We do not budget for acquisitions. During 2026, we plan to complete 70 to 80 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, acquisition opportunities and commodity prices.

Our capital budget may be adjusted as business conditions warrant as the amount, timing and allocation of capital expenditures is largely discretionary and within our control. If natural gas, NGLs and oil prices decline, or costs increase, to levels that do not generate an acceptable level of corporate returns, we may defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity, and to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows.

Based on strip prices as of December 31, 2025, we believe that net cash provided from operating activities and available borrowings under the Credit Facility, the net proceeds of the offering of the 2036 Notes, borrowings under the Term Loan A Facility and net proceeds from the Utica Shale Divestiture 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.

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

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Cash Flows

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

​

​

​

​

​

​

​

​

​

​

Year Ended December 31,

​

​

​

2024

  ​

2025

  ​

Net cash provided by operating activities

​

$

849,288

​

​

1,630,930

​

Net cash used in investing activities

​

​

(714,153)

​

​

(1,077,813)

​

Net cash used in financing activities

​

​

(135,135)

​

​

(343,117)

​

Net increase in cash, cash equivalents and restricted cash

​

$

—

​

​

210,000

​

​

Year Ended December 31, 2024 Compared to Year Ended December 31, 2025

Operating activities. Net cash provided by operating activities was $0.8 billion and $1.6 billion for the years ended December 31, 2024 and 2025, respectively. Net cash provided by operating activities increased between periods primarily due to higher natural gas revenues, lower ad valorem taxes, lower interest expense and changes in working capital, partially offset by lower NGLs and oil revenues, higher lease operating expense and higher gathering, compression, processing and transportation expense during the year ended December 31, 2025.

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

Investing activities. Net cash used in investing activities increased from $0.7 billion for the year ended December 31, 2024 to $1.1 billion for the year ended December 31, 2025, primarily due to asset acquisitions of $253 million of during the year ended December 31, 2025 and increased drilling and completions and leasing activity of $71 million and $38 million, respectively, between periods, partially offset by higher proceeds from asset sales of $7 million between periods primarily due to oil and gas property trades during the year ended December 31, 2025. The increase in our drilling and completions activity is primarily due to completing 20 additional net wells between periods.

Financing activities. Net cash used in financing activities increased from $135 million for the year ended December 31, 2024 to $343 million for the year ended December 31, 2025, primarily due to redemptions and repurchases of our Senior Notes of $142 million during the year ended December 31, 2025, share repurchases of $136 million during the year ended December 31, 2025, net borrowings on our Credit Facility of $45 million during the year ended December 31, 2025 and higher payment of debt issuance costs for our Unsecured Credit Facility of $3 million, partially offset by lower distributions to the noncontrolling interests in Martica of $4 million between periods and net repayments on our Credit Facility of $24 million during the year ended December 31, 2024.

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

Refer to “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity” in our Annual Report on Form 10-K for the year ended December 31, 2024 for a discussion of the cash flows for the year ended December 31, 2023 compared to the year ended December 31, 2024.

Debt Agreements

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, 2024 and 2025. See Note 7—Long-Term Debt to our consolidated financial statements for additional information.

Critical Accounting Estimates

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

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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.

Successful Efforts Method

We account for our natural gas, NGLs and oil exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, the costs incurred to acquire, drill and complete productive wells, development wells and oil and gas leases are capitalized. Items charged to expense generally include exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases and costs associated with unsuccessful lease acquisitions.

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 $51 million, $47 million and $29 million for the years ended December 31, 2023, 2024 and 2025, respectively.

We believe that the application of the successful efforts method of accounting requires judgment to determine the proper classification of wells designated as developmental or exploratory, which designation determines the proper accounting treatment of the costs incurred. In addition, evaluating our unproved properties for impairment involves significant judgments about future development plans, which include future sales prices of natural gas, NGLs and oil and future development and production costs, as well as the amount of natural gas, NGLs and oil recoveries.

Natural Gas, NGLs and Oil Reserve Quantities

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

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

We believe that the estimates and assumptions related to reserve quantities is critical because any significant revisions or changes to these estimates and assumptions could affect the future amortization rates of capitalized proved property costs and result in a material asset impairment.

Impairment of Proved Properties

We evaluate the carrying amount of our proved natural gas, NGLs and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount of our proved properties exceeds the estimated undiscounted future net cash flows (measured using futures prices at the balance sheet date), we further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeds the estimated fair value of the properties. We did not record any impairments for proved properties during the years ended December 31, 2023, 2024 and 2025.

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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. For our Utica and Marcellus properties, strip pricing would have to decline by more than 6% and 20%, respectively, from year end 2025 levels before further evaluation of those properties would be required in order to determine if an impairment charge is necessary. If future prices decline from December 31, 2025, the fair value of our properties may be below their carrying amounts and an impairment charge may be necessary. However, we are unable to predict commodity prices with any greater precision than the futures market.

We believe that the estimates and assumptions related to our undiscounted future net cash flows and the fair value of our proved properties are critical because different natural gas, NGLs and oil pricing, cost assumptions or discount rates, as applicable, may affect the recognition, timing and amount of an impairment and, if changed, could have a material effect on the Company's financial position and results of operations.

Derivative Instruments

In order to manage our exposure to natural gas, NGLs and oil price volatility, we may enter into derivative transactions from time to time, which agreements could include commodity fixed price swaps, basis swaps, collars or other similar instruments related to the price risk associated with our production. We record derivative instruments on the consolidated balance sheet as either assets or liabilities measured at fair value and record changes in the fair value of derivatives in current earnings as they occur. Our derivatives have not been designated as hedges for accounting purposes. Fair value measurements for our commodity derivatives require the use of assumptions and judgements including valuation techniques, future pricing, volatility, time to maturity and credit risk, among others. We regularly assess the reasonableness of these assumptions and judgements through the review of counterparty statements. However, changes to these assumptions and judgements could have a material effect on the Company's financial position and results of operations.

Income Taxes

Income taxes are accounted for using the asset and liability approach. Under this approach, deferred income tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. We record deferred income tax expense to the extent our deferred income tax liabilities exceed our deferred income tax assets. We record a deferred income tax benefit to the extent our deferred income tax assets exceed our deferred income tax liabilities. We are subject to state and U.S. federal income taxes, but are currently not in a cash tax paying position with respect to U.S. federal income taxes.

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 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. The amount of deferred income tax assets considered realizable could change based upon the amounts of taxable income actually generated, or as estimates of future taxable income change. As of December 31, 2025, we have recognized a valuation allowance of $39 million related to Colorado and Oklahoma state NOL carryforwards that we do not expect to realize due to expected future reduced income tax apportionment in those states. In addition, as of December 31, 2025, we have recorded a reserve for uncertain tax positions of $51 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.

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