XML 95 R31.htm IDEA: XBRL DOCUMENT v3.25.4
Supplemental Oil and Gas Information (Unaudited)
 12 Months Ended
Dec. 31, 2025
Oil and Gas Disclosure [Abstract]  
Supplemental Oil and Gas Information
The following unaudited schedules are presented in accordance with required disclosures about Oil and Gas Producing Activities to provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies. Additional background information concerning some of the schedules follows:
SCHEDULE 1 – SUMMARY OF TOTAL PROVED EQUIVALENT RESERVES
SCHEDULE 2 – SUMMARY OF PROVED CRUDE OIL RESERVES
SCHEDULE 3 – SUMMARY OF PROVED NATURAL GAS LIQUIDS RESERVES
SCHEDULE 4 – SUMMARY OF PROVED NATURAL GAS RESERVES
Reserves of oil and natural gas are estimated by the Company’s or independent engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgments are required to estimate reserves. Reserve estimates and future cash flows are based on the average market prices for sales of oil and natural gas on the first calendar day of each month during the year. The average prices used for 2025 were $65.34 per BBL for crude oil (WTI) and $3.39 per MCF for natural gas (Henry Hub). The average prices used for 2024 were $75.48 per BBL for crude oil (WTI) and $2.13 per MCF for natural gas (Henry Hub). The average prices used for 2023 were $78.22 per BBL for crude oil (WTI) and $2.64 per MCF for natural gas (Henry Hub). Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors.
Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data (including hydrocarbon prices, operating costs, and development costs) and commercially available technologies to establish “reasonable certainty” of economic producibility. Estimates are presented in millions of barrels of oil equivalents and dollars and billions of cubic feet rounded to one decimal. As defined by the SEC, reasonable certainty of proved reserves describes a high degree of confidence that the quantities will be recovered. In estimating proved reserves, Murphy uses common industry-accepted methods for subsurface evaluations, including performance, volumetric and analog-based studies. Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves. Reliable geologic and engineering technology is a method or combination of methods that are field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates. The approach was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas and in certain reservoirs developed with the application of improved recovery techniques. Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data and commercially available seismic processing and numerical reservoir simulation programs. Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.
Production quantities shown are net volumes withdrawn from reservoirs. These may differ from sales quantities due to inventory changes, volumes consumed for fuel and/or shrinkage from the extraction of NGLs.
All oil and natural gas reserves are from consolidated subsidiaries (including NCI) and proportionately consolidated joint ventures. The Company has no proved reserves attributable to investees accounted for by the equity method.
SCHEDULE 7 – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
GAAP requires calculation of future net cash flows using a 10% annual discount factor, an unweighted average of oil and natural gas prices in effect at the beginning of each month of the year, and year-end costs and statutory tax rates, except for known future changes such as contracted prices and legislated tax rates.
The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future cash flows because prices, costs and governmental policies do not remain static; appropriate discount rates may vary; and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts.
Schedule 7 also presents the principal reasons for change in the standardized measure of discounted future net cash flows for each of the three years ended December 31, 2025.
Equivalents
(Millions of barrels of oil equivalent)
TotalUnited
States		CanadaOther
Proved developed and undeveloped reserves:
December 31, 2022715.4 357.0 357.8 0.6 
Revisions of previous estimates(13.3)(13.3)0.2 (0.2)
Improved recovery0.4 — 0.4 — 
Extensions and discoveries112.6 12.7 87.3 12.6 
Sale of properties(5.2)— (5.2)— 
Production(70.4)(45.3)(25.0)(0.1)
December 31, 2023739.5 311.1 415.5 12.9 
Revisions of previous estimates14.3 8.1 6.3 (0.1)
Improved recovery11.3 11.3 — — 
Extensions and discoveries31.4 16.0 15.4 — 
Production(67.5)(39.1)(28.3)(0.1)
December 31, 2024729.0 307.4 408.9 12.7 
Revisions of previous estimates26.0 18.0 7.1 0.9 
Extensions and discoveries43.0 4.9 38.1 — 
Purchases of properties4.3 4.3 — — 
Sale of properties(3.4)(3.4)— — 
Production(68.9)(39.3)(29.5)(0.1)
December 31, 2025 ¹730.0 291.9 424.6 13.5 
Proved developed reserves:
December 31, 2022436.0 264.2 171.3 0.5 
December 31, 2023425.5 223.2 202.0 0.3 
December 31, 2024436.2 218.9 217.1 0.2 
December 31, 2025 ²418.9 197.8 220.9 0.2 
Proved undeveloped reserves:
December 31, 2022279.4 92.8 186.5 0.1 
December 31, 2023314.0 87.9 213.5 12.6 
December 31, 2024292.8 88.5 191.8 12.5 
December 31, 2025 ³311.1 94.1 203.7 13.3 
1  Total and United States includes proved reserves of 15.0 MMBOE, consisting of 13.9 MMBBL of oil, 0.4 MMBBL of NGLs and 4.2 BCF of natural gas attributable to the noncontrolling interest in MP GOM.
2 Total and United States includes proved developed reserves of 13.1 MMBOE, consisting of 12.1 MMBBL of oil, 0.4 MMBBL of NGLs and 3.9 BCF of natural gas attributable to the noncontrolling interest in MP GOM.
3 Total and United States includes proved undeveloped reserves of 1.9 MMBOE, consisting of 1.8 MMBBL of oil and 0.3 BCF of natural gas attributable to the noncontrolling interest in MP GOM.
2025 Comments for Proved Equivalent Reserves Changes
Revisions of previous estimates - The equivalent reserves revisions in 2025 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale, revisions in the Gulf of America for additional field life at the Chinook #8 location, in the Cascade and Chinook fields, due to the Pioneer FPSO purchase, partially offset by the effects of lower oil prices and higher gas prices that increased royalty rates and accelerated royalty incentive payouts in the Tupper Montney.
Extensions and discoveries - In 2025, proved equivalent reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale.
Purchases and sales of properties - In 2025, the Company acquired incremental working interest in various properties in the Eagle Ford Shale and divested a minor area of the Eagle Ford Shale in separate transactions.

2024 Comments for Proved Equivalent Reserves Changes
Revisions of previous estimates - The equivalent reserves revisions in 2024 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the Tupper Montney.
Improved Recovery – Proved equivalent reserves were added in 2024 for the non-operated St. Malo waterflood in the Gulf of America.
Extensions and discoveries - In 2024, proved equivalent reserves were added for drilling activities predominantly in the Tupper Montney, the Eagle Ford Shale, and projects in the Gulf of America.

2023 Comments for Proved Equivalent Reserves Changes
Revisions of previous estimates - The equivalent reserves revisions in 2023 resulted predominantly from lower commodity prices in the U.S. and performance adjustments in the Tupper Montney and the Eagle Ford Shale. These negative revisions were partially offset by positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the Tupper Montney.
Extensions and discoveries - In 2023, proved equivalent reserves were added for drilling and expansion activities predominantly in the Tupper Montney, the Eagle Ford Shale, and Vietnam.
Purchases and sales of properties - In 2023, the Company divested a portion of its working interest, in the Kaybob Duvernay and all of its non-operated Placid Montney assets.
(Millions of barrels)
TotalUnited
States		CanadaOther
Proved developed and undeveloped crude oil reserves:
December 31, 2022303.6 263.6 39.5 0.5 
Revisions of previous estimates(10.8)(8.9)(1.8)(0.1)
Improved recovery0.4 — 0.4 — 
Extensions and discoveries22.5 8.9 1.5 12.1 
Sale of properties
(2.0)— (2.0)— 
Production(37.9)(35.6)(2.2)(0.1)
December 31, 2023275.8 228.0 35.4 12.4 
Revisions of previous estimates6.6 6.6 0.1 (0.1)
Improved recovery10.7 10.7 – — 
Extensions and discoveries16.6 10.7 5.9 – 
Production(34.6)(30.8)(3.7)(0.1)
December 31, 2024275.1 225.2 37.7 12.2 
Revisions of previous estimates20.2 18.2 1.8 0.2 
Extensions and discoveries5.7 3.4 2.3 — 
Purchases of properties3.5 3.5 – – 
Sales of properties(1.8)(1.8)— – 
Production(34.0)(30.3)(3.6)(0.1)
December 31, 2025 ¹268.7 218.2 38.2 12.3 
Proved developed crude oil reserves:
December 31, 2022209.0 194.4 14.2 0.4 
December 31, 2023186.3 163.7 22.3 0.3 
December 31, 2024184.7 164.1 20.4 0.2 
December 31, 2025 ²173.1 150.8 22.1 0.2 
Proved undeveloped crude oil reserves:
December 31, 202294.6 69.2 25.3 0.1 
December 31, 202389.5 64.3 13.1 12.1 
December 31, 202490.4 61.1 17.3 12.0 
December 31, 2025 ³95.6 67.4 16.1 12.1 
1 Total and United States includes proved reserves of 13.9 MMBBL attributable to the noncontrolling interest in MP GOM.
2 Total and United States includes proved developed reserves of 12.1 MMBBL attributable to the noncontrolling interest in MP GOM.
3 Total and United States includes proved undeveloped reserves of 1.8 MMBBL attributable to the noncontrolling interest in MP GOM.
2025 Comments for Proved Crude Oil Reserves Changes
Revisions of previous estimates - The crude oil reserves revisions in 2025 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale, revisions in the Gulf of America for additional field life at the Chinook #8 location, in the Cascade and Chinook fields, due to the Pioneer FPSO purchase, partially offset by the effects of lower oil prices.
Extensions and discoveries - In 2025, proved oil reserves were added for drilling activities predominantly in the Eagle Ford Shale and in the Kaybob Duvernay in Canada.
Purchases and sales of properties - In 2025, the Company acquired incremental working interest in various properties in the Eagle Ford Shale and divested a minor area of the Eagle Ford Shale in separate transactions.

2024 Comments for Proved Crude Oil Reserves Changes
Revisions of previous estimates - The crude oil reserves revisions in 2024 resulted predominantly from performance adjustments in the Eagle Ford Shale and the Gulf of America.
Improved Recovery – Proved oil reserves were added in 2024 for the non-operated St. Malo waterflood in the Gulf of America.
Extensions and discoveries - In 2024, proved oil reserves were added for drilling activities predominantly in the Eagle Ford Shale and the Gulf of America.

2023 Comments for Proved Crude Oil Reserves Changes
Revisions of previous estimates - The negative crude oil reserves revisions in 2023 resulted predominantly from impacts of lower commodity prices in the U.S. and performance adjustments in the Eagle Ford Shale and the Gulf of America.
Extensions and discoveries - In 2023, proved oil reserves were added for drilling and expansion activities predominantly in the Eagle Ford Shale and Vietnam.
Purchases and sales of properties - In 2023, the Company divested a portion of its working interest in the Kaybob Duvernay and all of its non-operated Placid Montney assets.
(Millions of barrels)
TotalUnited
States		Canada Other
Proved developed and undeveloped NGL reserves:
December 31, 202241.7 37.6 4.1 — 
Revisions of previous estimates(1.4)(1.2)(0.2)— 
Extensions and discoveries2.0 1.7 0.3 — 
Sale of properties
(0.6)— (0.6)— 
Production(4.1)(3.8)(0.3)— 
December 31, 202337.6 34.3 3.3 — 
Revisions of previous estimates1.2 0.3 0.9 — 
Improved recovery0.4 0.4 — — 
Extensions and discoveries2.9 2.4 0.5 — 
Production(3.5)(3.3)(0.2)— 
December 31, 202438.6 34.1 4.5 — 
Revisions of previous estimates1.4 1.2 0.2 — 
Extensions and discoveries1.1 0.7 0.4 — 
Purchases of properties0.4 0.4 – — 
Sale of properties
(0.8)(0.8)— — 
Production(4.0)(3.8)(0.2)— 
December 31, 2025 ¹36.7 31.8 4.9 — 
Proved developed NGL reserves:
December 31, 202229.7 27.4 2.3 — 
December 31, 202325.9 24.1 1.8 — 
December 31, 202424.1 21.9 2.2 — 
December 31, 2025 ²21.7 19.2 2.5 — 
Proved undeveloped NGL reserves:
December 31, 202212.0 10.2 1.8 — 
December 31, 202311.7 10.2 1.5 — 
December 31, 202414.5 12.2 2.3 — 
December 31, 2025 15.0 12.6 2.4 — 
1 Total and United States includes total proved reserves of 0.4 MMBBL attributable to the noncontrolling interest in MP GOM.
2 Total and United States includes proved developed reserves of 0.4 MMBBL attributable to the noncontrolling interest in MP GOM.
2025 Comments for Proved Natural Gas Liquids Reserves Changes
Revisions of previous estimates - The NGL reserves revisions in 2025 resulted predominantly from performance adjustments in the Eagle Ford Shale and the Gulf of America, partially offset by lower commodity prices in the United States.
Extensions and discoveries - In 2025, proved NGL reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale.
Purchases and sales of properties - In 2025, the Company acquired incremental working interest in various properties in the Eagle Ford Shale and divested a minor area of the Eagle Ford Shale in separate transactions.

2024 Comments for Proved Natural Gas Liquids Reserves Changes
Revisions of previous estimates - The NGL reserves revisions in 2024 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale, and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the Tupper Montney.
Improved Recovery – Proved NGL reserves were added in 2024 for the non-operated St. Malo waterflood in the Gulf of America.
Extensions and discoveries - In 2024, proved NGL reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale.

2023 Comments for Proved Natural Gas Liquids Reserves Changes
Revisions of previous estimates - The negative NGL reserves revisions in 2023 resulted predominantly from impacts of lower commodity prices in the U.S. and performance adjustments in the Eagle Ford Shale. These revisions were partially offset by improvements in the Gulf of America.
Extensions and discoveries - In 2023, proved NGL reserves were added for drilling and expansion activities predominantly in the Eagle Ford Shale.
Purchases and sales of properties - In 2023, the Company divested a portion of its working interest in the Kaybob Duvernay and all of its non-operated Placid Montney assets.
(Billions of cubic feet)
TotalUnited
States		CanadaOther
Proved developed and undeveloped natural gas reserves:    
December 31, 20222,219.9 334.9 1,884.8 0.2 
Revisions of previous estimates(6.9)(19.0)12.1 — 
Extensions and discoveries528.9 12.3 513.8 2.8 
Sale of properties
(15.6)— (15.6)— 
Production(170.1)(35.1)(135.0)— 
December 31, 20232,556.2 293.1 2,260.1 3.0 
Revisions of previous estimates39.1 7.7 31.4 — 
Improved recovery1.2 1.2 – — 
Extensions and discoveries71.4 17.0 54.4 — 
Production(176.1)(30.1)(146.0)— 
December 31, 20242,491.8 288.9 2,199.9 3.0 
Revisions of previous estimates26.7 (8.7)30.8 4.6 
Extensions and discoveries217.2 4.7 212.5 — 
Purchases of properties2.4 2.4 — — 
Sale of properties
(5.1)(5.1)— — 
Production(185.3)(31.0)(154.3)— 
December 31, 2025 1,2
2,547.7 251.2 2,288.9 7.6 
Proved developed natural gas reserves:
December 31, 20221,183.1 254.1 928.8 0.2 
December 31, 20231,279.3 212.4 1,066.7 0.2 
December 31, 20241,364.2 196.8 1,167.2 0.2 
December 31, 2025 2,3
1,345.1 166.4 1,178.5 0.2 
Proved undeveloped natural gas reserves:
December 31, 20221,036.8 80.8 956.0 — 
December 31, 20231,276.9 80.7 1,193.4 2.8 
December 31, 20241,127.6 92.1 1,032.7 2.8 
December 31, 2025 4
1,202.6 84.8 1,110.4 7.4 
1 Total and United States includes total proved reserves of 4.2 BCF attributable to the noncontrolling interest in MP GOM.
2 Includes proved natural gas reserves to be consumed in operations as fuel of 54.2 BCF, 35.1 BCF and 7.4 BCF for the U.S., Canada and Other, respectively, with 1.7 BCF attributable to the noncontrolling interest in MP GOM.
3 Total and United States includes proved developed reserves of 3.9 BCF attributable to the noncontrolling interest in MP GOM.
4 Total and United States includes proved undeveloped reserves of 0.3 BCF attributable to the noncontrolling interest in MP GOM.
2025 Comments for Proved Natural Gas Reserves Changes
Revisions of previous estimates - The natural gas reserves revisions in 2025 resulted predominantly from performance adjustments in the Tupper Montney, partially offset by negative revisions due to increased royalty rates and accelerated royalty incentive payouts resulting from higher commodity prices in the Tupper Montney and the effects of reduced oil price in the Eagle Ford Shale.
Extensions and discoveries - In 2025, proved natural gas reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale.
Purchases and sales of properties - In 2025, the Company acquired incremental working interest in various properties in the Eagle Ford Shale and divested a minor area of the Eagle Ford Shale in separate transactions

2024 Comments for Proved Natural Gas Reserves Changes
Revisions of previous estimates - The natural gas reserves revisions in 2024 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale, and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the Tupper Montney.
Improved Recovery – Proved natural gas reserves were added in 2024 for the non-operated St. Malo waterflood in the Gulf of America.
Extensions and discoveries - In 2024, proved natural gas reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale.

2023 Comments for Proved Natural Gas Reserves Changes
Revisions of previous estimates - The negative natural gas reserves revisions in 2023 resulted predominantly from lower commodity prices in the U.S. and performance adjustments in the Tupper Montney and the Eagle Ford Shale. These negative revisions were partially offset by positive revisions in the Gulf of America, as well as reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the Tupper Montney.
Extensions and discoveries - In 2023, proved natural gas reserves were added for drilling and expansion activities predominantly in the Tupper Montney.
Purchases and sales of properties - In 2023, the Company divested a portion of its working interest in the Kaybob Duvernay and all of its non-operated Placid Montney assets.
(Millions of dollars)
United
States
Canada
OtherTotal
Year ended December 31, 2025
Property acquisition costs
Unproved$5.5 $— $— $5.5 
Proved23.6 — — 23.6 
Total acquisition costs29.1 — — 29.1 
Exploration costs 71.6 0.3 144.3 216.2 
Development costs 696.2 152.5 102.9 951.6 
Total costs incurred796.9 152.8 247.2 1,196.9 
Charged to expense
Dry hole expense(0.9)— 31.0 30.1 
Geophysical and other costs34.3 0.3 35.3 69.9 
Total charged to expense 1
33.4 0.3 66.3 100.0 
Property additions$763.5 $152.5 $180.9 $1,096.9 
Year ended December 31, 2024
Property acquisition costs
Unproved$7.8 $0.2 $— $8.0 
Proved— — — — 
Total acquisition costs7.8 0.2 – 8.0 
Exploration costs 85.3 0.4 60.2 145.9 
Development costs 598.7 137.7 45.1 781.5 
Total costs incurred691.8 138.3 105.3 935.4 
Charged to expense
Dry hole expense70.9 — 2.3 73.2 
Geophysical and other costs19.2 0.4 31.2 50.8 
Total charged to expense 1
90.1 0.4 33.5 124.0 
Property additions$601.7 $137.9 $71.8 $811.4 
Year ended December 31, 2023
Property acquisition costs
Unproved$— $— $8.5 $8.5 
Proved12.8 — 14.3 27.1 
Total acquisition costs12.8 — 22.8 35.6 
Exploration costs 157.8 0.4 39.9 198.1 
Development costs 667.2 206.2 7.4 880.8 
Total costs incurred837.8 206.6 70.1 1,114.5 
Charged to expense
Dry hole expense153.1 — 16.7 169.8 
Geophysical and other costs13.4 0.4 40.3 54.1 
Total charged to expense 1
166.5 0.4 57.0 223.9 
Property additions$671.3 $206.2 $13.1 $890.6 
1 Excludes undeveloped lease amortization for the years ended 2025, 2024 and 2023 of $11.7 million, $9.6 million and $10.9 million, respectively.
(Millions of dollars)
United
States		CanadaOtherTotal
Year ended December 31, 2025    
Revenues    
Crude oil and natural gas liquids sales$2,047.4 $254.4 $5.7 $2,307.5 
Natural gas sales106.5 275.8 — 382.3 
Total oil and natural gas revenues2,153.9 530.2 5.7 2,689.8 
Other operating revenues5.9 1.7 10.0 17.6 
Total revenues2,159.8 531.9 15.7 2,707.4 
Costs and expenses
Lease operating expenses577.1 185.6 2.5 765.2 
Severance and ad valorem taxes37.7 1.5 — 39.2 
Transportation, gathering and processing107.0 92.7 — 199.7 
Exploration costs charged to expense33.5 0.3 66.2 100.0 
Undeveloped lease amortization7.5 0.1 4.1 11.7 
Depreciation, depletion and amortization822.1 144.8 2.5 969.4 
Accretion of asset retirement obligations46.6 10.3 0.7 57.6 
Impairment of assets115.0 — — 115.0 
Selling and general expenses13.7 23.7 8.8 46.2 
Other expenses (benefits)13.4 3.5 (0.4)16.5 
Total costs and expenses1,773.6 462.5 84.4 2,320.5 
Results of operations before taxes386.2 69.4 (68.7)386.9 
Income tax expense (benefit)77.7 14.6 (2.1)90.2 
Results of operations$308.5 $54.8 $(66.6)$296.7 
Year ended December 31, 2024
Revenues
Crude oil and natural gas liquids sales$2,436.0 $272.3 $6.6 $2,714.9 
Natural gas sales67.8 232.2 — 300.0 
Sales of purchased natural gas— 3.7 — 3.7 
Total oil and natural gas revenues2,503.8 508.2 6.6 3,018.6 
Other operating revenues4.5 1.5 — 6.0 
Total revenues2,508.3 509.7 6.6 3,024.5 
Costs and expenses
Lease operating expenses749.9 185.5 1.6 937.0 
Severance and ad valorem taxes37.8 1.4 — 39.2 
Transportation, gathering and processing130.9 79.9 — 210.8 
Costs of purchased natural gas— 3.1 — 3.1 
Exploration costs charged to expense90.0 0.4 33.5 123.9 
Undeveloped lease amortization6.2 0.1 3.3 9.6 
Depreciation, depletion and amortization709.2 146.0 1.7 856.9 
Accretion of asset retirement obligations43.1 8.6 0.7 52.4 
Impairment of assets62.9 — — 62.9 
Selling and general expenses(3.3)20.4 6.7 23.8 
Other expenses (benefits)(5.6)3.3 2.6 0.3 
Total costs and expenses1,821.1 448.7 50.1 2,319.9 
Results of operations before taxes687.2 61.0 (43.5)704.6 
Income tax expense (benefit)125.3 12.0 (31.0)106.3 
Results of operations$561.9 $49.0 $(12.5)$598.4 
1   Results exclude corporate overhead, interest and discontinued operations. Results include amounts attributable to the noncontrolling interest in MP GOM.
(Millions of dollars)
United
States		CanadaOtherTotal
Year ended December 31, 2023
Revenues
Crude oil and natural gas liquids sales$2,829.1 $165.7 $11.0 $3,005.8 
Natural gas sales92.7 278.2 — 370.9 
Sales of purchased natural gas
— 72.2 — 72.2 
Total oil and natural gas revenues2,921.8 516.1 11.0 3,448.9 
Other operating revenues6.5 1.4 — 7.9 
Total revenues2,928.3 517.5 11.0 3,456.8 
Costs and expenses
Lease operating expenses630.7 151.8 1.9 784.4 
Severance and ad valorem taxes41.4 1.4 — 42.8 
Transportation, gathering and processing157.0 76.0 — 233.0 
Costs of purchased natural gas— 51.7 — 51.7 
Exploration costs charged to expense166.5 0.4 57.0 223.9 
Undeveloped lease amortization8.1 0.1 2.7 10.9 
Depreciation, depletion and amortization706.0 142.2 2.3 850.5 
Accretion of asset retirement obligations37.8 7.8 0.4 46.0 
Selling and general expenses11.8 16.5 9.4 37.7 
Other expenses31.2 16.8 8.9 56.9 
Total costs and expenses1,790.5 464.7 82.6 2,337.8 
Results of operations before taxes1,137.8 52.8 (71.6)1,119.0 
Income tax expense (benefit)232.7 11.2 (6.1)237.8 
Results of operations$905.1 $41.6 $(65.5)$881.2 
1   Results exclude corporate overhead, interest and discontinued operations. Results include amounts attributable to the noncontrolling interest in MP GOM.
(Millions of dollars)
United
States		CanadaOther Total
December 31, 2025    
Future cash inflows$15,502.7 $6,850.9 $873.7 $23,227.3 
Future development costs(1,969.6)(812.6)(204.0)(2,986.2)
Future production costs(6,707.7)(4,240.9)(343.4)(11,292.0)
Future income taxes(602.4)(342.8)(176.2)(1,121.4)
Future net cash flows6,223.0 1,454.6 150.1 7,827.7 
10% annual discount for estimated timing of cash flows(2,459.4)(625.4)(118.7)(3,203.5)
Standardized measure of discounted future net cash flows$3,763.6 $829.2 $31.4 $4,624.2 
December 31, 2024
Future cash inflows$18,118.1 $6,304.4 $1,012.9 $25,435.4 
Future development costs(2,024.9)(825.9)(252.5)(3,103.3)
Future production costs(7,645.7)(4,026.5)(341.7)(12,013.9)
Future income taxes(893.5)(251.2)(203.4)(1,348.1)
Future net cash flows7,554.0 1,200.8 215.3 8,970.1 
10% annual discount for estimated timing of cash flows(2,887.3)(486.0)(200.9)(3,574.2)
Standardized measure of discounted future net cash flows$4,666.7 $714.8 $14.4 $5,395.9 
December 31, 2023
Future cash inflows$18,927.6 $8,012.7 $1,004.2 $27,944.5 
Future development costs(1,685.3)(769.6)(304.3)(2,759.2)
Future production costs(7,856.2)(4,223.6)(288.7)(12,368.5)
Future income taxes(1,057.5)(634.6)(121.3)(1,813.4)
Future net cash flows8,328.6 2,384.9 289.9 11,003.4 
10% annual discount for estimated timing of cash flows(2,840.6)(1,056.9)(252.5)(4,150.0)
Standardized measure of discounted future net cash flows$5,488.0 $1,328.0 $37.4 $6,853.4 
1 Includes amounts attributable to the noncontrolling interest in MP GOM.
The following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown.
(Millions of dollars)
202520242023
Net changes in prices and production costs 2
$(1,126.6)$(1,116.5)$(5,845.6)
Net changes in development costs46.4 (152.7)(78.8)
Sales and transfers of oil and natural gas produced, net of production costs(1,685.7)(1,824.8)(2,264.8)
Net change due to extensions and discoveries122.0 583.7 770.4 
Net change due to purchases and sales of proved reserves62.6 — (96.1)
Development costs incurred 
686.2 668.6 703.7 
Accretion of discount598.3 773.5 1,393.3 
Revisions of previous quantity estimates403.9 (688.1)(771.5)
Net change in income taxes121.2 298.8 1,229.6 
Net (decrease) increase
(771.7)(1,457.5)(4,959.8)
Standardized measure at January 15,395.9 6,853.4 11,813.2 
Standardized measure at December 31$4,624.2 $5,395.9 $6,853.4 
1  Includes amounts attributable to the noncontrolling interest in MP GOM.
2 The average prices used for crude oil (WTI) were $65.34/BBL in 2025, $75.48/BBL in 2024 and $78.22/BBL in 2023. The average prices used for natural gas (Henry Hub) were $3.39/MCF in 2025, $2.13/MCF in 2024 and $2.64/MCF in 2023.
(Millions of dollars)
United
States		CanadaOtherTotal
December 31, 2025
Unproved oil and natural gas properties 1
$207.0 $6.4 $16.3 $229.7 
Proved oil and natural gas properties17,417.6 4,865.4 439.1 22,722.1 
Gross capitalized costs17,624.6 4,871.8 455.4 22,951.8 
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties(118.5)— (11.5)(130.0)
Proved oil and natural gas properties(11,275.7)(3,412.0)(47.0)(14,734.7)
Net capitalized costs$6,230.4 $1,459.8 $396.9 $8,087.1 
December 31, 2024
Unproved oil and natural gas properties 1
$247.3 $6.6 $29.1 $283.0 
Proved oil and natural gas properties16,598.8 4,498.1 246.7 21,343.6 
Gross capitalized costs16,846.1 4,504.7 275.8 21,626.6 
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties(111.0)— (20.7)(131.7)
Proved oil and natural gas properties(10,326.2)(3,116.2)(44.2)(13,486.6)
Net capitalized costs$6,408.9 $1,388.5 $210.9 $8,008.3 
1 Unproved oil and natural gas properties above include costs and associated accumulated amortization of properties that do not have proved reserves; these costs include mineral interests, uncompleted exploratory wells and exploratory wells capitalized pending further evaluation.