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Supplemental Oil and Gas Information (Unaudited) | 12 Months Ended
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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) | Total |  | United States |  | Canada |  | Other
Proved developed and undeveloped reserves: |  |  |  |  |  |  |
December 31, 2019 | 825.0 |  |  | 500.1 |  |  | 324.1 |  |  | 0.8 |
Revisions of previous estimates | (194.7) |  |  | (146.6) |  |  | (47.3) |  |  | (0.8) |
Extensions and discoveries | 150.3 |  |  | 19.5 |  |  | 130.7 |  |  | — |
Sales of properties | (1.7) |  |  | (1.7) |  |  | — |  |  | — |
Production | (63.9) |  |  | (42.8) |  |  | (21.1) |  |  | — |
December 31, 2020 | 714.9 |  |  | 328.5 |  |  | 386.4 |  |  | — |
Revisions of previous estimates | (52.9) |  |  | 35.6 |  |  | (89.3) |  |  | 0.8 |
Extensions and discoveries | 109.4 |  |  | 18.2 |  |  | 91.3 |  |  | — |
Purchases of properties | 7.4 |  |  | 1.6 |  |  | 5.8 |  |  | — |
Sales of properties | (0.7) |  |  | — |  |  | (0.7) |  |  | — |
Production | (61.1) |  |  | (40.4) |  |  | (20.6) |  |  | (0.1) |
December 31, 2021 | 716.9 |  |  | 343.4 |  |  | 372.8 |  |  | 0.7 |
Revisions of previous estimates | (23.6) |  |  | 29.0 |  |  | (52.8) |  |  | 0.2 |
Improved recovery | 5.3 |  |  | 5.3 |  |  | — |  |  | — |
Extensions and discoveries | 80.1 |  |  | 20.6 |  |  | 59.5 |  |  | — |
Purchases of properties | 5.0 |  |  | 5.0 |  |  | — |  |  | — |
Sales of properties | (4.4) |  |  | (4.4) |  |  | — |  |  | — |
Production | (63.9) |  |  | (41.9) |  |  | (21.7) |  |  | (0.3) |
December 31, 2022 ¹ | 715.4 |  |  | 357.0 |  |  | 357.8 |  |  | 0.6 |
Proved developed reserves: |  |  |  |  |  |  |
December 31, 2019 | 472.3 |  |  | 273.4 |  |  | 198.1 |  |  | 0.8 |
December 31, 2020 | 410.8 |  |  | 230.3 |  |  | 180.5 |  |  | — |
December 31, 2021 | 419.2 |  |  | 241.9 |  |  | 176.8 |  |  | 0.6 |
December 31, 2022 ² | 436.0 |  |  | 264.2 |  |  | 171.3 |  |  | 0.5 |
Proved undeveloped reserves: |  |  |  |  |  |  |
December 31, 2019 | 352.7 |  |  | 226.7 |  |  | 126.0 |  |  | — |
December 31, 2020 | 304.1 |  |  | 98.2 |  |  | 205.9 |  |  | — |
December 31, 2021 | 297.7 |  |  | 101.6 |  |  | 196.0 |  |  | 0.1 |
December 31, 2022 ³ | 279.4 |  |  | 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) | Total |  | United States |  | Canada |  | Other
Proved developed and undeveloped crude oil reserves: |  |  |  |  |  |  |
December 31, 2019 | 423.9 |  |  | 377.8 |  |  | 45.3 |  |  | 0.8 |
Revisions of previous estimates | (137.4) |  |  | (116.8) |  |  | (19.8) |  |  | (0.8) |
Extensions and discoveries | 19.6 |  |  | 14.5 |  |  | 5.1 |  |  | — |
Sales of properties | (1.5) |  |  | (1.5) |  |  | — |  |  | — |
Production | (38.1) |  |  | (33.4) |  |  | (4.7) |  |  | — |
December 31, 2020 | 266.5 |  |  | 240.6 |  |  | 25.9 |  |  | — |
Revisions of previous estimates | 39.3 |  |  | 31.1 |  |  | 7.5 |  |  | 0.7 |
Extensions and discoveries | 14.1 |  |  | 13.5 |  |  | 0.6 |  |  | — |
Purchases of properties | 6.4 |  |  | 1.3 |  |  | 5.2 |  |  | — |
Production | (34.9) |  |  | (31.5) |  |  | (3.3) |  |  | (0.1) |
December 31, 2021 | 291.5 |  |  | 255.0 |  |  | 35.9 |  |  | 0.6 |
Revisions of previous estimates | 23.4 |  |  | 19.9 |  |  | 3.3 |  |  | 0.2 |
Improved recovery | 4.7 |  |  | 4.7 |  |  | — |  |  | — |
Extensions and discoveries | 18.9 |  |  | 16.1 |  |  | 2.8 |  |  | — |
Purchases of properties | 4.2 |  |  | 4.2 |  |  | — |  |  | — |
Sales of properties | (3.6) |  |  | (3.6) |  |  | — |  |  | — |
Production | (35.5) |  |  | (32.7) |  |  | (2.5) |  |  | (0.3) |
December 31, 2022 ¹ | 303.6 |  |  | 263.6 |  |  | 39.5 |  |  | 0.5 |
Proved developed crude oil reserves: |  |  |  |  |  |  |
December 31, 2019 | 230.9 |  |  | 205.0 |  |  | 25.1 |  |  | 0.8 |
December 31, 2020 | 179.8 |  |  | 161.4 |  |  | 18.4 |  |  | — |
December 31, 2021 | 191.5 |  |  | 174.9 |  |  | 16.0 |  |  | 0.5 |
December 31, 2022 ² | 209.0 |  |  | 194.4 |  |  | 14.2 |  |  | 0.4 |
Proved undeveloped crude oil reserves: |  |  |  |  |  |  |
December 31, 2019 | 193.0 |  |  | 172.8 |  |  | 20.2 |  |  | — |
December 31, 2020 | 86.7 |  |  | 79.2 |  |  | 7.5 |  |  | — |
December 31, 2021 | 99.9 |  |  | 80.0 |  |  | 19.8 |  |  | 0.1 |
December 31, 2022 ³ | 94.6 |  |  | 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) | Total |  | United States |  | Canada |  | Other
Proved developed and undeveloped NGL reserves: |  |  |  |  |  |  |
December 31, 2019 | 56.1 |  |  | 52.8 |  |  | 3.3 |  |  | — |
Revisions of previous estimates | (16.4) |  |  | (17.1) |  |  | 0.7 |  |  | — |
Extensions and discoveries | 2.8 |  |  | 2.7 |  |  | 0.1 |  |  | — |
Sales of properties | (0.1) |  |  | (0.1) |  |  | — |  |  | — |
Production | (4.2) |  |  | (3.7) |  |  | (0.5) |  |  | — |
December 31, 2020 | 38.2 |  |  | 34.6 |  |  | 3.6 |  |  | — |
Revisions of previous estimates | 1.4 |  |  | 1.4 |  |  | — |  |  | — |
Extensions and discoveries | 2.5 |  |  | 2.4 |  |  | 0.1 |  |  | — |
Purchases of properties | 0.1 |  |  | 0.1 |  |  | — |  |  | — |
Production | (3.8) |  |  | (3.4) |  |  | (0.4) |  |  | — |
December 31, 2021 | 38.4 |  |  | 35.1 |  |  | 3.3 |  |  | — |
Revisions of previous estimates | 4.4 |  |  | 3.9 |  |  | 0.5 |  |  | — |
Improved recovery | 0.2 |  |  | 0.2 |  |  | — |  |  | — |
Extensions and discoveries | 2.5 |  |  | 1.9 |  |  | 0.6 |  |  | — |
Purchases of properties | 0.3 |  |  | 0.3 |  |  | — |  |  | — |
Sales of properties | (0.2) |  |  | (0.2) |  |  | — |  |  | — |
Production | (3.9) |  |  | (3.6) |  |  | (0.3) |  |  | — |
December 31, 2022 ¹ | 41.7 |  |  | 37.6 |  |  | 4.1 |  |  | — |
Proved developed NGL reserves: |  |  |  |  |  |  |
December 31, 2019 | 28.1 |  |  | 26.2 |  |  | 1.9 |  |  | — |
December 31, 2020 | 28.7 |  |  | 25.5 |  |  | 3.2 |  |  | — |
December 31, 2021 | 28.4 |  |  | 25.6 |  |  | 2.8 |  |  | — |
December 31, 2022 ² | 29.7 |  |  | 27.4 |  |  | 2.3 |  |  | — |
Proved undeveloped NGL reserves: |  |  |  |  |  |  |
December 31, 2019 | 28.0 |  |  | 26.6 |  |  | 1.4 |  |  | — |
December 31, 2020 | 9.5 |  |  | 9.1 |  |  | 0.4 |  |  | — |
December 31, 2021 | 10.0 |  |  | 9.5 |  |  | 0.5 |  |  | — |
December 31, 2022 ³ | 12.0 |  |  | 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) | Total |  | United States |  | Canada |  | Other
Proved developed and undeveloped natural gas reserves: |  |  |  |  |  |  |
December 31, 2019 | 2,069.7 |  |  | 416.8 |  |  | 1,652.9 |  |  | — |
Revisions of previous estimates | (245.4) |  |  | (76.2) |  |  | (169.2) |  |  | — |
Extensions and discoveries | 767.2 |  |  | 14.0 |  |  | 753.2 |  |  | — |
Sales of properties | (0.7) |  |  | (0.7) |  |  | — |  |  | — |
Production | (129.8) |  |  | (34.4) |  |  | (95.4) |  |  | — |
December 31, 2020 | 2,461.0 |  |  | 319.5 |  |  | 2,141.5 |  |  | — |
Revisions of previous estimates | (562.2) |  |  | 18.7 |  |  | (581.0) |  |  | 0.2 |
Extensions and discoveries | 556.7 |  |  | 13.5 |  |  | 543.2 |  |  | — |
Purchases of properties | 5.4 |  |  | 1.5 |  |  | 3.9 |  |  | — |
Sale of properties | (4.4) |  |  | — |  |  | (4.4) |  |  | — |
Production | (134.2) |  |  | (32.8) |  |  | (101.4) |  |  | — |
December 31, 2021 | 2,322.3 |  |  | 320.3 |  |  | 2,001.8 |  |  | 0.2 |
Revisions of previous estimates | (309.8) |  |  | 30.7 |  |  | (340.5) |  |  | — |
Improved recovery | 2.6 |  |  | 2.6 |  |  | — |  |  | — |
Extensions and discoveries | 352.4 |  |  | 15.7 |  |  | 336.7 |  |  | — |
Purchases of properties | 2.9 |  |  | 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, 2019 | 1,279.8 |  |  | 253.1 |  |  | 1,026.7 |  |  | — |
December 31, 2020 | 1,213.8 |  |  | 260.2 |  |  | 953.6 |  |  | — |
December 31, 2021 | 1,196.0 |  |  | 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, 2019 | 789.9 |  |  | 163.7 |  |  | 626.2 |  |  | — |
December 31, 2020 | 1,247.2 |  |  | 59.3 |  |  | 1,187.9 |  |  | — |
December 31, 2021 | 1,126.4 |  |  | 72.2 |  |  | 1,054.1 |  |  | — |
December 31, 2022 ³ | 1,036.8 |  |  | 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 |  |  |  | Other |  | Total
Year ended December 31, 2022 |  |  |  |  |  |  |  |  |
Property acquisition costs |  |  |  |  |  |  |  |  |
Unproved | $ | 1.8 |  |  | $ | — |  |  |  |  | $ | — |  |  | $ | 1.8 |
Proved | 128.5 |  |  | — |  |  |  |  | — |  |  | 128.5 |
Total acquisition costs | 130.3 |  |  | — |  |  |  |  | — |  |  | 130.3 |
Exploration costs | 42.2 |  |  | 0.8 |  |  |  |  | 70.3 |  |  | 113.3 |
Development costs | 704.9 |  |  | 208.5 |  |  |  |  | 4.3 |  |  | 917.7 |
Total costs incurred | 877.4 |  |  | 209.3 |  |  |  |  | 74.6 |  |  | 1,161.3 |
Charged to expense |  |  |  |  |  |  |  |  |
Dry hole expense | 23.0 |  |  | — |  |  |  |  | 59.1 |  |  | 82.1 |
Geophysical and other costs | 15.8 |  |  | 0.8 |  |  |  |  | 21.1 |  |  | 37.7 |
Total charged to expense | 38.8 |  |  | 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 |
Proved | 19.9 |  |  | (20.4) |  |  |  |  | — |  |  | (0.5) |
Total acquisition costs | 28.7 |  |  | (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 incurred | 573.6 |  |  | 82.4 |  |  |  |  | 33.8 |  |  | 689.8 |
Charged to expense |  |  |  |  |  |  |  |  |
Dry hole expense | 17.3 |  |  | — |  |  |  |  | — |  |  | 17.3 |
Geophysical and other costs | 13.1 |  |  | 0.4 |  |  |  |  | 19.3 |  |  | 32.8 |
Total charged to expense | 30.4 |  |  | 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 |
Proved | 0.2 |  |  | — |  |  |  |  | — |  |  | 0.2 |
Total acquisition costs | 6.7 |  |  | 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 incurred | 650.2 |  |  | 120.9 |  |  |  |  | 38.8 |  |  | 809.9 |
Charged to expense |  |  |  |  |  |  |  |  |
Geophysical and other costs | 14.3 |  |  | 0.7 |  |  |  |  | 23.6 |  |  | 38.6 |
Total charged to expense | 14.3 |  |  | 0.7 |  |  |  |  | 23.6 |  |  | 38.6 |
Property additions | $ | 635.9 |  |  | $ | 120.2 |  |  |  |  | $ | 15.2 |  |  | $ | 771.3 |
(Millions of dollars) | United States |  | Canada |  | Other |  | Total
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 sales | 225.3 |  |  | 312.6 |  |  | — |  |  | 537.9 |
Sales of purchased natural gas | 0.2 |  |  | 181.5 |  |  | — |  |  | 181.7 |
Total oil and natural gas revenues | 3,435.8 |  |  | 761.6 |  |  | 22.8 |  |  | 4,220.2 |
Other operating revenues | 25.4 |  |  | 1.3 |  |  | — |  |  | 26.7 |
Total revenues | 3,461.2 |  |  | 762.9 |  |  | 22.8 |  |  | 4,246.9 |
Costs and expenses |  |  |  |  |  |  |
Lease operating expenses | 522.7 |  |  | 155.1 |  |  | 1.5 |  |  | 679.3 |
Severance and ad valorem taxes | 55.7 |  |  | 1.3 |  |  | — |  |  | 57.0 |
Transportation, gathering and processing | 142.2 |  |  | 70.5 |  |  | — |  |  | 212.7 |
Costs of purchased natural gas | 0.2 |  |  | 171.8 |  |  | — |  |  | 172.0 |
Exploration costs charged to expense | 38.8 |  |  | 0.8 |  |  | 80.2 |  |  | 119.8 |
Undeveloped lease amortization | 8.7 |  |  | 0.2 |  |  | 4.4 |  |  | 13.3 |
Depreciation, depletion and amortization | 617.0 |  |  | 141.5 |  |  | 5.4 |  |  | 763.9 |
Accretion of asset retirement obligations | 36.5 |  |  | 9.6 |  |  | 0.1 |  |  | 46.2 |
Selling and general expenses | 20.4 |  |  | 21.9 |  |  | 2.2 |  |  | 44.5 |
Other expenses (benefits) | 126.3 |  |  | 12.4 |  |  | 3.1 |  |  | 141.8 |
Total costs and expenses | 1,568.5 |  |  | 585.1 |  |  | 96.9 |  |  | 2,250.5 |
Results of operations before taxes | 1,892.7 |  |  | 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 sales | 121.8 |  |  | 245.9 |  |  | — |  |  | 367.7 |
Total oil and natural gas revenues | 2,321.5 |  |  | 474.8 |  |  | 4.9 |  |  | 2,801.2 |
Other operating revenues | 16.0 |  |  | 1.5 |  |  | — |  |  | 17.5 |
Total revenues | 2,337.5 |  |  | 476.3 |  |  | 4.9 |  |  | 2,818.7 |
Costs and expenses |  |  |  |  |  |  |
Lease operating expenses | 406.4 |  |  | 136.3 |  |  | (3.2) |  |  | 539.5 |
Severance and ad valorem taxes | 39.6 |  |  | 1.6 |  |  | — |  |  | 41.2 |
Transportation, gathering and processing | 126.5 |  |  | 60.5 |  |  | — |  |  | 187.0 |
Exploration costs charged to expense | 30.4 |  |  | 0.4 |  |  | 19.3 |  |  | 50.1 |
Undeveloped lease amortization | 11.1 |  |  | 0.2 |  |  | 7.6 |  |  | 18.9 |
Depreciation, depletion and amortization | 616.5 |  |  | 163.8 |  |  | 1.8 |  |  | 782.1 |
Accretion of asset retirement obligations | 36.9 |  |  | 9.7 |  |  | — |  |  | 46.6 |
Impairment of assets | — |  |  | 171.3 |  |  | 18.0 |  |  | 189.3 |
Selling and general expenses | 20.5 |  |  | 16.5 |  |  | 6.6 |  |  | 43.6 |
Other expenses | 99.4 |  |  | (66.2) |  |  | (2.2) |  |  | 31.0 |
Total costs and expenses | 1,387.3 |  |  | 494.1 |  |  | 47.9 |  |  | 1,929.3 |
Results of operations before taxes | 950.2 |  |  | (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 |  | Canada |  | Other |  | Total
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 sales | 69.4 |  |  | 170.6 |  |  | — |  |  | 240.1 |
Total oil and natural gas revenues | 1,405.3 |  |  | 344.6 |  |  | 1.8 |  |  | 1,751.7 |
Other operating revenues | 6.5 |  |  | 1.2 |  |  | — |  |  | 7.7 |
Total revenues | 1,411.8 |  |  | 345.8 |  |  | 1.8 |  |  | 1,759.4 |
Costs and expenses |  |  |  |  |  |  |
Lease operating expenses | 476.9 |  |  | 121.6 |  |  | 1.6 |  |  | 600.1 |
Severance and ad valorem taxes | 27.2 |  |  | 1.3 |  |  | — |  |  | 28.5 |
Transportation, gathering and processing | 127.7 |  |  | 44.7 |  |  | — |  |  | 172.4 |
Restructuring expenses | 1.2 |  |  | — |  |  | — |  |  | 1.2 |
Exploration costs charged to expense | 35.5 |  |  | 0.6 |  |  | 23.6 |  |  | 59.7 |
Undeveloped lease amortization | 17.2 |  |  | 0.4 |  |  | 9.2 |  |  | 26.8 |
Depreciation, depletion and amortization | 749.4 |  |  | 213.2 |  |  | 2.3 |  |  | 964.9 |
Accretion of asset retirement obligations | 36.6 |  |  | 5.6 |  |  | — |  |  | 42.2 |
Impairment of assets | 1,152.5 |  |  | — |  |  | 39.7 |  |  | 1,192.2 |
Selling and general expenses | 24.6 |  |  | 17.1 |  |  | 7.1 |  |  | 48.8 |
Other expenses | 21.5 |  |  | (2.3) |  |  | 1.8 |  |  | 21.0 |
Total costs and expenses | 2,670.3 |  |  | 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 |  | Canada |  | Other |  | 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 flows | 14,779.2 |  |  | 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 flows | 9,119.9 |  |  | 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 flows | 2,909.4 |  |  | 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) | 2022 |  | 2021 |  | 2020
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 discoveries | 1,223.5 |  |  | 908.5 |  |  | 568.5 |
Net change due to purchases and sales of proved reserves | 102.1 |  |  | 63.1 |  |  | (14.6) |
Development costs incurred | 769.3 |  |  | 619.3 |  |  | 736.8 |
Accretion of discount | 802.6 |  |  | 267.2 |  |  | 699.3 |
Revisions of previous quantity estimates | 1,652.9 |  |  | 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 1 | 7,299.0 |  |  | 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 |  | Canada |  | Other |  | Total
December 31, 2022 |  |  |  |  |  |  |
Unproved oil and natural gas properties | $ | 494.6 |  |  | $ | 19.2 |  |  | $ | 135.1 |  |  | $ | 648.9 |
Proved oil and natural gas properties | 15,051.9 |  |  | 4,684.8 |  |  | 55.9 |  |  | 19,792.6 |
Gross capitalized costs | 15,546.5 |  |  | 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 properties | 14,690.7 |  |  | 4,865.1 |  |  | 100.0 |  |  | 19,655.8 |
Gross capitalized costs | 15,293.5 |  |  | 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.

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