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Supplemental Oil and Gas Information (Unaudited)
 12 Months Ended
Dec. 31, 2022
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Supplemental Oil and Gas Information
The following unaudited schedules are presented in accordance with required disclosures about Oil and Natural 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 crude oil, condensate, natural gas liquids 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 judgmental decisions 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 2022 were $93.67 per barrel for NYMEX crude oil (WTI) and $6.36 per MCF for natural gas (Henry Hub). The average prices used for 2021 were $66.56 per barrel for NYMEX crude oil (WTI) and $3.60 per MCF for natural gas (Henry Hub). The average prices used for 2020 were $39.57 per barrel for NYMEX crude oil (WTI) and $1.98 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 with one decimal; totals within the tables may not add as a result of rounding. 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 natural gas liquids.
All crude oil, natural gas liquid reserves and natural gas reserves are from consolidated subsidiaries (including noncontrolling interest) 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 NATURAL 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, 2022.
Equivalents
(Millions of barrels of oil equivalent)
TotalUnited
States		CanadaOther
Proved developed and undeveloped reserves:
December 31, 2019825.0 500.1 324.1 0.8 
Revisions of previous estimates(194.7)(146.6)(47.3)(0.8)
Extensions and discoveries150.3 19.5 130.7 — 
Sales of properties(1.7)(1.7)— — 
Production(63.9)(42.8)(21.1)— 
December 31, 2020714.9 328.5 386.4 — 
Revisions of previous estimates(52.9)35.6 (89.3)0.8 
Extensions and discoveries109.4 18.2 91.3 — 
Purchases of properties7.4 1.6 5.8 — 
Sales of properties(0.7)— (0.7)— 
Production(61.1)(40.4)(20.6)(0.1)
December 31, 2021716.9 343.4 372.8 0.7 
Revisions of previous estimates(23.6)29.0 (52.8)0.2 
Improved recovery5.3 5.3 — — 
Extensions and discoveries80.1 20.6 59.5 — 
Purchases of properties5.0 5.0 — — 
Sales of properties(4.4)(4.4)— — 
Production(63.9)(41.9)(21.7)(0.3)
December 31, 2022 ¹715.4 357.0 357.8 0.6 
Proved developed reserves:
December 31, 2019472.3 273.4 198.1 0.8 
December 31, 2020410.8 230.3 180.5 — 
December 31, 2021419.2 241.9 176.8 0.6 
December 31, 2022 ²436.0 264.2 171.3 0.5 
Proved undeveloped reserves:
December 31, 2019352.7 226.7 126.0 — 
December 31, 2020304.1 98.2 205.9 — 
December 31, 2021297.7 101.6 196.0 0.1 
December 31, 2022 ³279.4 92.8 186.5 0.1 
1  Includes proved reserves of 18.2 MMBOE, consisting of 16.5 MMBBL oil, 0.6 MMBBL NGLs and 5.6 BCF natural gas attributable to the noncontrolling interest in MP GOM.
2 Includes proved developed reserves of 15.0 MMBOE, consisting of 13.7 MMBBL oil, 0.5 MMBBL NGLs and 4.2 BCF natural gas attributable to the noncontrolling interest in MP GOM.
3 Includes proved undeveloped reserves of 3.2 MMBOE, consisting of 2.8 MMBBL oil, 0.1 MMBBL NGLs and 1.4 BCF natural gas attributable to the noncontrolling interest in MP GOM.
4 Totals within the tables may not add as a result of rounding.
2022 Comments for Proved Equivalent Reserves Changes
Revisions of previous estimates - The equivalent reserves revisions in 2022 resulted predominantly from increased royalty rates and accelerated royalty incentive payouts due to higher commodity prices in Tupper Montney. These negative revisions were partially offset by positive well performance in the U.S. Gulf of Mexico.
Extensions and discoveries - In 2022, proved equivalent reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney and Kaybob Duvernay as well as in the U.S. at the Gulf of Mexico and the Eagle Ford Shale.
Purchases and sales of properties - In 2022, the Company acquired incremental working interest in two producing fields in the U.S. Gulf of Mexico and divested working interest in one field in the U.S. Gulf of Mexico and a portion Eagle Ford Shale.
2021 Comments for Proved Equivalent Reserves Changes
Revisions of previous estimates - The equivalent reserves revisions in 2021 resulted predominantly from accelerated royalty incentive payouts due to higher commodity prices in Tupper Montney. These negative revisions were partially offset by positive revisions in the U.S. from higher commodity prices, which partially reversed the 2020 capital expenditure reduction and improved well performance in the U.S. Gulf of Mexico.
Extensions and discoveries - In 2021, proved equivalent reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney as well as in the U.S. at the Eagle Ford Shale and the Gulf of Mexico.
Purchases and sales of properties - In 2021, the Company acquired incremental working interest in Terra Nova offshore Canada and in the U.S. Gulf of Mexico.
2020 Comments for Proved Equivalent Reserves Changes
Revisions of previous estimates - The negative reserves revisions in 2020 resulted predominantly from lower crude oil prices and lower capital expenditures for onshore shale properties over the next 5 years causing the removal of numerous proved undeveloped locations, partially offset by improved well performance in the Gulf of Mexico. The 2020 negative equivalents revision in the U.S. was primarily attributable to lower capital expenditures in the Eagle Ford Shale and the negative revision in Canada was primarily attributable to the Kaybob Duvernay. Lower commodity prices also resulted in negative equivalents revisions in the U.S offshore and Canada offshore.
Extensions and discoveries - In 2020, proved equivalent reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney as well as in the U.S. at the Eagle Ford Shale. Proved equivalent reserves were also added for drilling activities in both the U.S. offshore and Canada offshore.
Purchases and sales of properties - In 2020, the Company divested partial working interest in an undeveloped well in the Gulf of Mexico.
(Millions of barrels)
TotalUnited
States		CanadaOther
Proved developed and undeveloped crude oil reserves:
December 31, 2019423.9 377.8 45.3 0.8 
Revisions of previous estimates(137.4)(116.8)(19.8)(0.8)
Extensions and discoveries19.6 14.5 5.1 — 
Sales of properties(1.5)(1.5)— — 
Production(38.1)(33.4)(4.7)— 
December 31, 2020266.5 240.6 25.9 — 
Revisions of previous estimates39.3 31.1 7.5 0.7 
Extensions and discoveries14.1 13.5 0.6 — 
Purchases of properties6.4 1.3 5.2 — 
Production(34.9)(31.5)(3.3)(0.1)
December 31, 2021291.5 255.0 35.9 0.6 
Revisions of previous estimates23.4 19.9 3.3 0.2 
Improved recovery4.7 4.7 — — 
Extensions and discoveries18.9 16.1 2.8 — 
Purchases of properties4.2 4.2 — — 
Sales of properties(3.6)(3.6)— — 
Production(35.5)(32.7)(2.5)(0.3)
December 31, 2022 ¹303.6 263.6 39.5 0.5 
Proved developed crude oil reserves:
December 31, 2019230.9 205.0 25.1 0.8 
December 31, 2020179.8 161.4 18.4 — 
December 31, 2021191.5 174.9 16.0 0.5 
December 31, 2022 ²209.0 194.4 14.2 0.4 
Proved undeveloped crude oil reserves:
December 31, 2019193.0 172.8 20.2 — 
December 31, 202086.7 79.2 7.5 — 
December 31, 202199.9 80.0 19.8 0.1 
December 31, 2022 ³94.6 69.2 25.3 0.1 
1 Includes total proved reserves of 16.5 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.
2 Includes proved developed reserves of 13.7 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.
3 Includes proved undeveloped reserves of 2.8 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.
4 Totals within the tables may not add as a result of rounding.
2022 Comments for Proved Crude Oil Reserves Changes
Revisions of previous estimates - The positive crude oil reserves revisions in 2022 resulted predominantly from improved well performance in the U.S. Gulf of Mexico and impacts of higher commodity prices in the U.S.
Extensions and discoveries - In 2022, proved oil reserves were added for drilling and expansion activities predominantly in the U.S. in the Gulf of Mexico and the Eagle Ford Shale.
Purchases and sales of properties - In 2022, the Company acquired incremental working interest in two producing fields in the U.S. Gulf of Mexico and divested working interest in one field in the U.S. Gulf of Mexico and a portion of the Eagle Ford Shale.
2021 Comments for Proved Crude Oil Reserves Changes
Revisions of previous estimates - The positive crude oil reserves revisions in 2021 resulted predominantly from impacts of higher commodity prices in the U.S., which partially reversed the 2020 capital expenditure reductions and improved well performance in the U.S. Gulf of Mexico.
Extensions and discoveries - In 2021, proved oil reserves were added for drilling and expansion activities predominantly in the U.S. at the Eagle Ford Shale and the Gulf of Mexico.
Purchases and sales of properties - In 2021, the Company acquired incremental working interest in Terra Nova offshore Canada and one field in the U.S. Gulf of Mexico.
2020 Comments for Proved Crude Oil Reserves Changes
Revisions of previous estimates - The negative crude oil reserves revisions in 2020 resulted predominantly from lower crude oil prices and lower capital expenditures for onshore shale properties over the next 5 years causing the removal of numerous proved undeveloped locations, partially offset by improved well performance in the Gulf of Mexico. The 2020 negative oil revision in the U.S. was primarily attributable to lower capital expenditures in the Eagle Ford Shale and the negative revision in Canada was primarily attributable to the Kaybob Duvernay. Lower commodity prices also resulted in negative oil reserves revisions in the U.S offshore and Canada offshore.
Extensions and discoveries - In 2020, proved oil reserves were added for drilling activities predominantly in the U.S. offshore and the Eagle Ford Shale. Proved oil reserves were also added for drilling activities in Canada offshore.
Purchases and sales of properties - In 2020, the Company divested partial working interest in an undeveloped well in the Gulf of Mexico.
(Millions of barrels)
TotalUnited
States		Canada Other
Proved developed and undeveloped NGL reserves:
December 31, 201956.1 52.8 3.3 — 
Revisions of previous estimates(16.4)(17.1)0.7 — 
Extensions and discoveries2.8 2.7 0.1 — 
Sales of properties(0.1)(0.1)— — 
Production(4.2)(3.7)(0.5)— 
December 31, 202038.2 34.6 3.6 — 
Revisions of previous estimates1.4 1.4 — — 
Extensions and discoveries2.5 2.4 0.1 — 
Purchases of properties0.1 0.1 — — 
Production(3.8)(3.4)(0.4)— 
December 31, 202138.4 35.1 3.3 — 
Revisions of previous estimates4.4 3.9 0.5 — 
Improved recovery0.2 0.2 — — 
Extensions and discoveries2.5 1.9 0.6 — 
Purchases of properties0.3 0.3 — — 
Sales of properties(0.2)(0.2)— — 
Production(3.9)(3.6)(0.3)— 
December 31, 2022 ¹41.7 37.6 4.1 — 
Proved developed NGL reserves:
December 31, 201928.1 26.2 1.9 — 
December 31, 202028.7 25.5 3.2 — 
December 31, 202128.4 25.6 2.8 — 
December 31, 2022 ²29.7 27.4 2.3 — 
Proved undeveloped NGL reserves:
December 31, 201928.0 26.6 1.4 — 
December 31, 20209.5 9.1 0.4 — 
December 31, 202110.0 9.5 0.5 — 
December 31, 2022 ³12.0 10.2 1.8 — 
1 Includes total proved reserves of 0.6 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.
2 Includes proved developed reserves of 0.5 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.
3 Includes proved undeveloped reserves of 0.1 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.
2022 Comments for Proved Natural Gas Liquids Reserves Changes
Revisions of previous estimates - The positive NGL reserves revisions in 2022 resulted predominantly from improved well performance in the U.S. Gulf of Mexico and the Eagle Ford Shale as well as in Canada at Kaybob Duvernay.
Extensions and discoveries - In 2022, proved NGL reserves were added for drilling and expansion activities predominantly in the U.S. at the Gulf of Mexico and the Eagle Ford Shale as well as in Canada at Tupper Montney and Kaybob Duvernay.
Purchases and sales of properties - In 2022, the Company acquired incremental working interest in two producing fields in the U.S. Gulf of Mexico and divested working interest in one field in the U.S. Gulf of Mexico and a portion of the Eagle Ford Shale.
2021 Comments for Proved Natural Gas Liquids Reserves Changes
Revisions of previous estimates - The positive NGL reserves revisions in 2021 resulted predominantly from impacts of higher commodity prices, which partially reversed the 2020 capital expenditure reductions and improved well performance in the U.S. Gulf of Mexico.
Extensions and discoveries - In 2021, proved NGL reserves were added for drilling and expansion activities predominantly in the U.S. Eagle Ford Shale.
Purchases and sales of properties - In 2021, the Company acquired incremental working interest in the U.S. Gulf of Mexico.
2020 Comments for Proved Natural Gas Liquids Reserves Changes
Revisions of previous estimates - The negative NGL reserves revisions in 2020 resulted predominantly from lower crude oil prices and lower capital expenditures for onshore shale properties over the next 5 years causing the removal of numerous proved undeveloped locations, partially offset by improved well performance in the Gulf of Mexico. The 2020 negative NGL revision in the U.S. was primarily attributable to lower capital allowance in the Eagle Ford Shale. The positive revision in Canada was primarily attributable to higher yields at the Kaybob Duvernay due to improved plant recoveries.
Extensions and discoveries - In 2020, proved NGL reserves were added for drilling activities predominantly in the U.S. at the Eagle Ford Shale.
Purchases and sales of properties - In 2020, the Company divested partial working interest in an undeveloped well in the Gulf of Mexico.
(Billions of cubic feet)
TotalUnited
States		CanadaOther
Proved developed and undeveloped natural gas reserves:    
December 31, 20192,069.7 416.8 1,652.9 — 
Revisions of previous estimates(245.4)(76.2)(169.2)— 
Extensions and discoveries767.2 14.0 753.2 — 
Sales of properties(0.7)(0.7)— — 
Production(129.8)(34.4)(95.4)— 
December 31, 20202,461.0 319.5 2,141.5 — 
Revisions of previous estimates(562.2)18.7 (581.0)0.2 
Extensions and discoveries556.7 13.5 543.2 — 
Purchases of properties5.4 1.5 3.9 — 
Sale of properties(4.4)— (4.4)— 
Production(134.2)(32.8)(101.4)— 
December 31, 20212,322.3 320.3 2,001.8 0.2 
Revisions of previous estimates(309.8)30.7 (340.5)— 
Improved recovery2.6 2.6 — — 
Extensions and discoveries352.4 15.7 336.7 — 
Purchases of properties2.9 2.9 — — 
Sales of properties(3.6)(3.6)— — 
Production(146.9)(33.7)(113.2)— 
December 31, 2022 1,4
2,219.9 334.9 1,884.8 0.2 
Proved developed natural gas reserves:
December 31, 20191,279.8 253.1 1,026.7 — 
December 31, 20201,213.8 260.2 953.6 — 
December 31, 20211,196.0 248.1 947.7 0.2 
December 31, 2022 2,4
1,183.1 254.1 928.8 0.2 
Proved undeveloped natural gas reserves:
December 31, 2019789.9 163.7 626.2 — 
December 31, 20201,247.2 59.3 1,187.9 — 
December 31, 20211,126.4 72.2 1,054.1 — 
December 31, 2022 ³1,036.8 80.8 956.0 — 
1 Includes total proved reserves of 5.6 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.
2 Includes proved developed reserves of 4.2 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.
3 Includes proved undeveloped reserves of 1.4 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.
4 Includes proved natural gas reserves to be consumed in operations as fuel of 74.9 BCF and 43.5 BCF for the U.S. and Canada, respectively, with 0.8 BCF attributable to the noncontrolling interest in MP GOM.
5 Totals within the tables may not add as a result of rounding.
2022 Comments for Proved Natural Gas Reserves Changes
Revisions of previous estimates - The negative natural gas reserves revisions in 2022 resulted predominantly from increased royalty rates and accelerated royalty incentive payouts due to higher commodity prices in Canada at Tupper Montney.
Extensions and discoveries - In 2022, proved natural gas reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney as well as in the U.S. at the Gulf of Mexico and the Eagle Ford Shale.
Purchases and sales of properties - In 2022, the Company acquired incremental working interest in two producing fields in the U.S. Gulf of Mexico and divested working interest in one field in the U.S. Gulf of Mexico and a portion of the Eagle Ford Shale.
2021 Comments for Proved Natural Gas Reserves Changes
Revisions of previous estimates - The negative natural gas reserves revisions in 2021 resulted predominantly from accelerated royalty incentive payouts due to higher commodity prices at Tupper Montney.
Extensions and discoveries - In 2021, proved equivalent reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney as well as in the U.S. at the Eagle Ford Shale and the Gulf of Mexico.
Purchases and sales of properties - In 2021, the Company acquired incremental working interest at Terra Nova offshore Canada and in the U.S. Gulf of Mexico.
2020 Comments for Proved Natural Gas Reserves Changes
Revisions of previous estimates - The negative natural gas reserves revisions in 2020 resulted predominantly from lower crude oil prices and lower capital expenditures for onshore shale properties over the next 5 years causing the removal of numerous proved undeveloped locations, partially offset by improved well performance in the Gulf of Mexico. The 2020 negative natural gas revision in the U.S. was primarily attributable to lower capital expenditures in the Eagle Ford Shale which offset positive natural gas revisions in the Gulf of Mexico. The negative revision in Canada was primarily attributable to the Kaybob Duvernay.
Extensions and discoveries - In 2020, proved natural gas reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney as well as in the U.S. at the Eagle Ford Shale.
Purchases and sales of properties - In 2020, the Company divested partial working interest in an undeveloped well in the Gulf of Mexico.
(Millions of dollars)
United
States
Canada 1
OtherTotal
Year ended December 31, 2022
Property acquisition costs
Unproved$1.8 $— $— $1.8 
Proved128.5 — — 128.5 
Total acquisition costs130.3 — — 130.3 
Exploration costs 42.2 0.8 70.3 113.3 
Development costs 704.9 208.5 4.3 917.7 
Total costs incurred877.4 209.3 74.6 1,161.3 
Charged to expense
Dry hole expense23.0 — 59.1 82.1 
Geophysical and other costs15.8 0.8 21.1 37.7 
Total charged to expense38.8 0.8 80.2 119.8 
Property additions$838.6 $208.5 $(5.7)$1,041.4 
Year ended December 31, 2021
Property acquisition costs
Unproved$8.8 $— $— $8.8 
Proved19.9 (20.4)— (0.5)
Total acquisition costs28.7 (20.4)— 8.3 
Exploration costs 31.7 0.4 30.1 62.2 
Development costs 513.2 102.4 3.7 619.3 
Total costs incurred573.6 82.4 33.8 689.8 
Charged to expense
Dry hole expense17.3 — — 17.3 
Geophysical and other costs13.1 0.4 19.3 32.8 
Total charged to expense30.4 0.4 19.3 50.1 
Property additions$543.2 $82.0 $14.5 $639.7 
Year ended December 31, 2020
Property acquisition costs
Unproved$6.5 $0.5 $7.3 $14.3 
Proved0.2 — — 0.2 
Total acquisition costs6.7 0.5 7.3 14.5 
Exploration costs 34.3 (0.4)24.7 58.6 
Development costs 609.2 120.8 6.8 736.8 
Total costs incurred650.2 120.9 38.8 809.9 
Charged to expense
Geophysical and other costs14.3 0.7 23.6 38.6 
Total charged to expense14.3 0.7 23.6 38.6 
Property additions$635.9 $120.2 $15.2 $771.3 
(Millions of dollars)
United
States		CanadaOtherTotal
Year ended December 31, 2022    
Revenues    
Crude oil and natural gas liquids sales$3,210.3 $267.5 $22.8 $3,500.6 
Natural gas sales225.3 312.6 — 537.9 
Sales of purchased natural gas0.2 181.5 — 181.7 
Total oil and natural gas revenues3,435.8 761.6 22.8 4,220.2 
Other operating revenues25.4 1.3 — 26.7 
Total revenues3,461.2 762.9 22.8 4,246.9 
Costs and expenses
Lease operating expenses522.7 155.1 1.5 679.3 
Severance and ad valorem taxes55.7 1.3 — 57.0 
Transportation, gathering and processing142.2 70.5 — 212.7 
Costs of purchased natural gas0.2 171.8 — 172.0 
Exploration costs charged to expense38.8 0.8 80.2 119.8 
Undeveloped lease amortization8.7 0.2 4.4 13.3 
Depreciation, depletion and amortization617.0 141.5 5.4 763.9 
Accretion of asset retirement obligations36.5 9.6 0.1 46.2 
Selling and general expenses20.4 21.9 2.2 44.5 
Other expenses (benefits)126.3 12.4 3.1 141.8 
Total costs and expenses1,568.5 585.1 96.9 2,250.5 
Results of operations before taxes1,892.7 177.8 (74.1)1,996.4 
Income tax expense (benefit)370.8 43.6 2.9 417.3 
Results of operations$1,521.9 $134.2 $(77.0)$1,579.1 
Year ended December 31, 2021
Revenues
Crude oil and natural gas liquids sales$2,199.7 $228.9 $4.9 $2,433.5 
Natural gas sales121.8 245.9 — 367.7 
Total oil and natural gas revenues2,321.5 474.8 4.9 2,801.2 
Other operating revenues16.0 1.5 — 17.5 
Total revenues2,337.5 476.3 4.9 2,818.7 
Costs and expenses
Lease operating expenses406.4 136.3 (3.2)539.5 
Severance and ad valorem taxes39.6 1.6 — 41.2 
Transportation, gathering and processing126.5 60.5 — 187.0 
Exploration costs charged to expense30.4 0.4 19.3 50.1 
Undeveloped lease amortization11.1 0.2 7.6 18.9 
Depreciation, depletion and amortization616.5 163.8 1.8 782.1 
Accretion of asset retirement obligations36.9 9.7 — 46.6 
Impairment of assets— 171.3 18.0 189.3 
Selling and general expenses20.5 16.5 6.6 43.6 
Other expenses99.4 (66.2)(2.2)31.0 
Total costs and expenses1,387.3 494.1 47.9 1,929.3 
Results of operations before taxes950.2 (17.8)(43.0)889.4 
Income tax expense (benefit)183.9 (1.7)(9.5)172.7 
Results of operations$766.3 $(16.1)$(33.5)$716.7 
1  Results exclude corporate overhead, interest and discontinued operations. Results include noncontrolling interest in MP GOM.
(Millions of dollars)
United
States		CanadaOtherTotal
Year ended December 31, 2020
Revenues
Crude oil and natural gas liquids sales$1,335.8 $174.0 $1.8 $1,511.6 
Natural gas sales69.4 170.6 — 240.1 
Total oil and natural gas revenues1,405.3 344.6 1.8 1,751.7 
Other operating revenues6.5 1.2 — 7.7 
Total revenues1,411.8 345.8 1.8 1,759.4 
Costs and expenses
Lease operating expenses476.9 121.6 1.6 600.1 
Severance and ad valorem taxes27.2 1.3 — 28.5 
Transportation, gathering and processing127.7 44.7 — 172.4 
Restructuring expenses1.2 — — 1.2 
Exploration costs charged to expense35.5 0.6 23.6 59.7 
Undeveloped lease amortization17.2 0.4 9.2 26.8 
Depreciation, depletion and amortization749.4 213.2 2.3 964.9 
Accretion of asset retirement obligations36.6 5.6 — 42.2 
Impairment of assets1,152.5 — 39.7 1,192.2 
Selling and general expenses24.6 17.1 7.1 48.8 
Other expenses21.5 (2.3)1.8 21.0 
Total costs and expenses2,670.3 402.2 85.3 3,157.8 
Results of operations before taxes(1,258.5)(56.4)(83.5)(1,398.4)
Income tax expense (benefit)(244.2)(21.4)2.1 (263.5)
Results of operations$(1,014.3)$(35.0)$(85.6)$(1,134.9)
1  Results exclude corporate overhead, interest and discontinued operations. Results include noncontrolling interest in MP GOM.
(Millions of dollars)
United
States		CanadaOther Total
December 31, 2022    
Future cash inflows$27,277.9 $12,360.2 $59.2 $39,697.3 
Future development costs(1,594.5)(642.4)(1.4)(2,238.3)
Future production costs(8,297.4)(4,199.0)(12.1)(12,508.5)
Future income taxes(2,606.8)(1,788.7)(5.4)(4,400.9)
Future net cash flows14,779.2 5,730.1 40.3 20,549.6 
10% annual discount for estimated timing of cash flows(5,709.8)(3,015.6)(11.0)(8,736.4)
Standardized measure of discounted future net cash flows$9,069.4 $2,714.5 $29.3 $11,813.2 
December 31, 2021
Future cash inflows$18,449.1 $7,203.5 $44.0 $25,696.7 
Future development costs(1,164.3)(521.1)(1.5)(1,686.8)
Future production costs(7,140.6)(3,525.8)(9.1)(10,675.4)
Future income taxes(1,024.4)(565.4)(3.0)(1,592.8)
Future net cash flows9,119.9 2,591.3 30.4 11,741.6 
10% annual discount for estimated timing of cash flows(3,264.9)(1,169.3)(8.5)(4,442.7)
Standardized measure of discounted future net cash flows$5,855.1 $1,422.0 $21.9 $7,299.0 
December 31, 2020
Future cash inflows$9,976.7 $4,617.5 $— $14,594.2 
Future development costs(1,289.8)(404.3)— (1,694.1)
Future production costs(5,777.5)(2,634.6)— (8,412.1)
Future income taxes— (166.8)— (166.8)
Future net cash flows2,909.4 1,411.8 — 4,321.2 
10% annual discount for estimated timing of cash flows(1,079.2)(623.4)— (1,702.6)
Standardized measure of discounted future net cash flows$1,830.2 $788.4 $— $2,618.6 
1 Includes noncontrolling interest in MP GOM.
2 Totals within the table may not add as a result of rounding.
Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown.
(Millions of dollars)
202220212020
Net changes in prices and production costs 2
$4,812.2 $5,962.1 $(5,942.1)
Net changes in development costs(531.1)(503.6)2,215.1 
Sales and transfers of oil and natural gas produced, net of production costs(2,917.4)(2,220.5)(1,123.1)
Net change due to extensions and discoveries1,223.5 908.5 568.5 
Net change due to purchases and sales of proved reserves102.1 63.1 (14.6)
Development costs incurred 
769.3 619.3 736.8 
Accretion of discount802.6 267.2 699.3 
Revisions of previous quantity estimates1,652.9 277.1 (1,461.3)
Net change in income taxes(1,399.9)(692.8)1,112.4 
Net increase (decrease)4,514.2 4,680.4 (3,209.0)
Standardized measure at January 17,299.0 2,618.6 5,827.6 
Standardized measure at December 31$11,813.2 $7,299.0 $2,618.6 
1  Includes noncontrolling interest in MP GOM.
2 The average prices used for 2022 were $93.67 per barrel for NYMEX crude oil (WTI) and $6.36 per MCF for natural gas (Henry Hub). The average prices used for 2021 were $66.56 per barrel for NYMEX crude oil (WTI) and $3.60 per MCF for natural gas (Henry Hub). The average prices used for 2020 were $39.57 per barrel for NYMEX crude oil (WTI) and $1.98 per MCF for natural gas (Henry Hub).
(Millions of dollars)
United
States		CanadaOtherTotal
December 31, 2022
Unproved oil and natural gas properties$494.6 $19.2 $135.1 $648.9 
Proved oil and natural gas properties15,051.9 4,684.8 55.9 19,792.6 
Gross capitalized costs15,546.5 4,704.0 191.0 20,441.5 
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties(117.8)— (14.7)(132.5)
Proved oil and natural gas properties(8,873.6)(3,208.0)(41.3)(12,122.9)
Net capitalized costs$6,555.1 $1,496.0 $135.0 $8,186.1 
December 31, 2021
Unproved oil and natural gas properties$602.8 $17.7 $141.7 $762.2 
Proved oil and natural gas properties14,690.7 4,865.1 100.0 19,655.8 
Gross capitalized costs15,293.5 4,882.8 241.7 20,418.0 
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties(109.1)— (22.0)(131.1)
Proved oil and natural gas properties(8,821.5)(3,320.5)(69.0)(12,211.0)
Net capitalized costs$6,362.9 $1,562.3 $150.7 $8,075.9 
Note:    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.