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Supplemental Oil and Gas Information | 12 Months Ended
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Dec. 31, 2019
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 2019 were $55.69 per barrel for NYMEX crude oil (WTI), and $2.57 per Mcf for natural gas (Henry Hub). The average prices used for 2018 were $65.56 per barrel for NYMEX crude oil (WTI), and $3.10 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 and commercially available technologies to establish “reasonable certainty” of economic producibility. 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. On December 22, 2017, the U.S. enacted into legislation the Tax Cuts and Jobs Act (2017 Tax Act); as a result, the company’s statutory U.S. tax rate was 21% in 2018 and a decrease from the previous rate of 35% in 2017 and 2016. 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, 2019. s proved reserves of 24.6 MMBOE, consisting of 22.1 MMBBL oil, 0.9 MMBBL NGLs, and 9.5 BCF natural gas attributable to the noncontrolling interest in MP GOM. 2 Includes proved developed reserves of 19.6 MMBOE, consisting of 17.7 MMBBL oil, 0.7 MMBBL NGLs, and 7.1 BCF natural gas attributable to the noncontrolling interest in MP GOM. 3 Includes proved undeveloped reserves of 5.0 MMBOE, consisting of 4.4 MMBBL oil, 0.2 MMBBL NGLs, and 2.4 BCF natural gas attributable to the noncontrolling interest in MP GOM. 2019 Comments for Proved Equivalent Reserves Changes Revisions of previous estimates - The positive Canadian equivalents reserves revisions in 2019 resulted from improved performance in the Tupper Montney asset which offset reserves reductions from deferrals of capital expenditures at Kaybob Duvernay. The 2019 negative equivalents revision in the U.S. was primarily attributable to changes in well performance in the Eagle Ford Shale, primarily the Tilden area. Extensions and discoveries - In 2019, proved equivalent reserves were added in the U.S. for drilling activities in both the Eagle Ford Shale and in Canada at Kaybob Duvernay. Proved equivalent reserves were also added for drilling activities in both the U.S. offshore and Canada offshore. Purchases and sales of properties - In 2019, the Company acquired deepwater Gulf of Mexico producing assets from LLOG. In addition, the Company acquired incremental ownership in the Chinook field in the Gulf of Mexico and partial ownership in the Jagus East field in Brunei (which is now held for sale). The Company’s Malaysia assets were divested in 2019. 2018 Comments for Proved Equivalent Reserves Changes Revisions of previous estimates - The 2018 negative proved equivalents revision in the U.S. was primarily attributable to revised type curves and the removal of proved undeveloped locations outside the 5-year development window. The negative Canadian equivalent reserves revisions in 2018 resulted from deferrals of capital expenditures of the Kaybob Duvernay as well as locations removed in Hibernia Offshore Canada due to updated operator development plans. The positive revisions for proved equivalent reserves in Malaysia were principally attributable to continued development in Kakap field and improved performance in South Acis field. Improved recovery - The 2018 Malaysia proved equivalent reserve addition was due to favorable impacts from gas lift activity at the Kikeh field. Extensions and discoveries - In 2018, proved equivalent reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and in Canada for drilling activities in the Kaybob Duvernay. Proved equivalent reserves were also added for drilling activities in the U.S. offshore. Purchases of properties - In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and oversees operations. In addition, the Company acquired partial ownership in the Jagus East field in Brunei. 2017 Comments for Proved Equivalent Reserves Changes Revisions of previous estimates - The 2017 negative proved equivalent reserves revision in the U.S. was primarily attributable to the removal of proved undeveloped locations within the 5-year development window as capital was reallocated to higher performing drilling locations within the Company’s Eagle Ford Shale fields, partially offset by improved Eagle Ford Shale costs and performance results in the Gulf of Mexico. The positive Canadian proved equivalent reserves revisions in 2017 resulted from improved performance at Tupper Montney assets in onshore Canada, and offshore Canada fields, Hibernia and Terra Nova. The negative revisions for proved equivalent reserves in Malaysia were principally attributable to the redetermination of Kakap participation that lowered the Company’s entitlement, and higher government entitlement under the terms of the respective production sharing contracts due to higher oil prices, offsetting positive performance revisions at the Company’s Sarawak projects. Improved recovery - The 2017 Malaysia proved equivalent reserve addition was primarily due to favorable impacts for waterflood activity at certain Sarawak oil fields. Extensions and discoveries - In 2017, proved equivalent reserves were added in the U.S. for drilling activities in the Eagle Ford Shale concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves, and in Canada for drilling activities in the Montney and Duvernay. Proved equivalent reserves were also added for drilling activities in the U.S. offshore. In Malaysia, proved equivalent reserves were added in Sarawak from field development activities. total proved reserves of 22.1 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM. 2 Includes proved developed reserves of 17.7 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM. 3 Includes proved undeveloped reserves of 4.4 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM. 2019 Comments for Proved Crude Oil Reserves Changes Revisions of previous estimates – The 2019 negative crude oil revision in the U.S. was primarily attributable to changes in well performance in the Eagle Ford Shale, primarily in the Tilden area. The negative Canadian oil reserves revisions in 2019 resulted from deferrals of capital expenditures at Kaybob Duvernay. Extensions and discoveries – In 2019, proved oil reserves were added in the U.S. for drilling activities both in the Eagle Ford Shale and in Canada at Kaybob Duvernay. Proved oil reserves were also added for drilling activities in both the U.S. offshore and Canada offshore. Purchases and sales of properties – In 2019, the Company acquired deepwater Gulf of Mexico producing assets from LLOG. In addition, the Company acquired incremental ownership in the Chinook field in the Gulf of Mexico. The Company’s Malaysia assets were divested in 2019. 2018 Comments for Proved Crude Oil Reserves Changes Revisions of previous estimates – The 2018 negative crude oil revision in the U.S. was primarily attributable to revised type curves and the removal of proved undeveloped locations outside the 5-year development window. The negative Canadian oil reserves revisions in 2018 resulted from deferrals of capital expenditures at Kaybob Duvernay as well as locations removed in Hibernia Offshore Canada due to updated operator development plans. The positive revisions for crude oil reserves in Malaysia were principally attributable to continued development in Kakap field and improved performance in South Acis field. Improved recovery – The 2018 Malaysia crude oil proved reserve addition was due to favorable impacts from natural gas lift activity at the Kikeh field. Extensions and discoveries – In 2018, proved oil reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and in Canada for drilling activities in the Kaybob Duvernay. Proved oil reserves were also added for drilling activities in the U.S. offshore. Purchases of properties – In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and oversees operations. In addition, the Company acquired partial ownership in the Jagus East field in Brunei. 2017 Comments for Proved Crude Oil Reserves Changes Revisions of previous estimates – The 2017 negative crude oil revision in the U.S. was primarily attributable to the removal of proved undeveloped locations within the 5-year development window as capital was reallocated to higher performing drilling locations within the Company’s Eagle Ford Shale fields, partially offset by improved Eagle Ford Shale costs and performance results in the Gulf of Mexico. The positive Canadian oil reserves revisions in 2017 resulted from improved performance at Tupper Montney assets in onshore Canada, and offshore Canada fields, Hibernia and Terra Nova. The negative revisions for crude oil reserves in Malaysia were principally attributable to the redetermination of Kakap participation that lowered the Company’s entitlement, and higher government entitlement under the terms of the respective production sharing contracts due to higher oil prices, offsetting positive performance revisions at the Company’s Sarawak projects. Improved recovery – The 2017 Malaysia crude oil proved reserve addition was primarily due to favorable impacts for waterflood activity at certain Sarawak oil fields. Extensions and discoveries – In 2017, proved oil reserves were added in the U.S. for drilling activities in the Eagle Ford Shale concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves, and in Canada for drilling activities in the Montney and Duvernay. Proved oil reserves were also added for drilling activities in the U.S. offshore. Purchases of properties – In 2017, the Company acquired greater working interests in two of its operated Gulf of Mexico fields. In U.S. onshore, the Company acquired acreage in the Permian area of west Texas. Additional Eagle Ford Shale acreage was acquired through joint venture agreements with other operators within its core acreage position. ludes total proved reserves of 0.9 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM. 2 Includes proved developed reserves of 0.7 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM. 3 Includes proved undeveloped reserves of 0.2 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM. 2019 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates – The negative 2019 NGL proved reserves revision in the U.S. was primarily due to midstream elections in the Eagle Ford Shale resulting in lower NGL yields. The negative Canadian NGL reserves revisions in 2019 resulted from deferrals of capital expenditures at Kaybob Duvernay. Extensions and discoveries – In 2019, proved NGL reserves were added in the U.S. for drilling activities in both the Eagle Ford Shale and in Canada at Kaybob Duvernay area in onshore Canada. Proved NGL reserves were also added for drilling activities in the U.S. offshore. Purchases and sales of properties – In 2019, the Company acquired deepwater Gulf of Mexico producing assets from LLOG. In addition, the Company acquired incremental ownership in the Chinook field in the Gulf of Mexico. The Company’s Malaysia assets were divested in 2019. 2018 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates – The negative 2018 NGL proved reserves revision in the U.S. was primarily in the Company’s Eagle Ford Shale fields based on removal of proved undeveloped locations outside the 5-year development window. The negative Canadian NGL reserves revisions in 2018 resulted from deferrals of capital expenditures at Kaybob Duvernay. The positive revisions for NGL reserves in Malaysia were principally attributable to improved performance for natural gas fields offshore Sarawak. Extensions and discoveries – In 2018, proved NGL reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and in Canada for drilling activities in the Kaybob Duvernay. Purchases of properties – In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and oversees operations. 2017 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates – The positive 2017 NGL proved reserves revision in the U.S. was primarily in the Company’s Eagle Ford Shale fields based on an updated shrinkage ratio of liquids rich natural gas production combined with improved costs, offsetting removal of proved undeveloped locations from within the 5-year development window as capital was reallocated to higher performing drilling locations within the Eagle Ford Shale. Extensions and discoveries – Proved NGL reserves were added primarily from drilling activities in the Eagle Ford Shale area concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves. Purchase of properties – In U.S., proved NGL reserves were added following the acquisition of acreage in both the Eagle Ford Shale and Permian areas, and increased working interest in two Gulf of Mexico fields. total proved reserves of 9.5 BCF for Total and United States attributable to the noncontrolling interest in MP GOM. 2 Includes proved developed reserves of 7.1 BCF for Total and United States attributable to the noncontrolling interest in MP GOM. 3 Includes proved undeveloped reserves of 2.4 BCF for Total and United States attributable to the noncontrolling interest in MP GOM. 2019 Comments for Proved Natural Gas Reserves Changes Revisions of previous estimates – In 2019, the positive natural gas revisions in Canada resulted from improved performance in the Tupper Montney asset and adjustments relating to royalties. The positive revision for natural gas reserves in the Eagle Ford Shale was primarily attributable to producing well performance. Extensions and discoveries – In 2019, proved natural gas reserves were added in the U.S. for development drilling activities in both the Eagle Ford Shale and in Canada at Tupper Montney and Kaybob Duvernay. Proved natural gas reserves were also added for drilling activities in both the U.S. offshore and Canada offshore. Purchases and sales of properties – In 2019, the Company acquired deepwater Gulf of Mexico producing assets from LLOG. In addition, the Company acquired incremental ownership in the Chinook field in the Gulf of Mexico. The Company’s Malaysia assets were divested in 2019. 2018 Comments for Proved Natural Gas Reserves Changes Revisions of previous estimates – In 2018, the U.S. positive natural gas revision was primarily due to drilling within the Eagle Ford Shale. The 2018 negative natural gas revisions in Canada resulted from deferrals of capital expenditures at Kaybob Duvernay partially offset by positive performance revisions in the Tupper Montney asset. The positive revision for natural gas reserves in Malaysia was primarily attributable to positive performance revisions at the Company’s Sarawak projects offset somewhat by negative Block H revisions attributable to higher government entitlement under the terms of the respective production sharing contracts due to higher natural gas prices. Improved recovery – The 2018 Malaysia natural gas proved reserve addition was due to favorable impacts from natural gas lift activity at the Kikeh field. Extensions and discoveries – In 2018, the U.S. added natural gas reserves primarily for developmental drilling activities in the Eagle Ford Shale. Natural gas reserve additions in Canada were attributable to developmental drilling activities in the Tupper Montney and Kaybob Duvernay areas in onshore Canada. In Malaysia, proved natural gas reserves were added in the Merapuh field in Sarawak from field development activities. Purchases of properties – In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and overseas operations. In addition, the Company acquired acreage in Tupper Montney in onshore Canada. 2017 Comments for Proved Natural Gas Reserves Changes Revisions of previous estimates – In the U.S., the negative natural gas revision was primarily due to shutting in a natural gas well located in the Gulf of Mexico due to early water break through, and in the Company’s Eagle Ford Shale fields proved undeveloped locations were removed from within the 5-year development window as capital was reallocated to higher performing drilling locations within the Eagle Ford Shale. The negative revision for natural gas reserves in Malaysia was primarily attributable to higher government entitlement under the terms of the respective production sharing contracts due to higher natural gas prices, offsetting positive performance revisions at the Company’s Sarawak projects. The 2017 positive natural gas revisions in Canada were attributable to updated well type curves and field performance at the Tupper Montney assets in onshore Canada. Extensions and discoveries – In 2017, the U.S. added natural gas reserves primarily for developmental drilling activities in the Eagle Ford Shale concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves, and field development drilling in the Gulf of Mexico. Natural gas reserve additions in Canada were attributable to developmental drilling activities in the Montney and Kaybob Duvernay areas in onshore Canada. In Malaysia, proved natural gas reserves were added in Sarawak from field development activities. Purchase of properties – In the U.S., proved natural gas reserves were added following the acquisition of acreage in both the Eagle Ford Shale and Permian areas, and increased working interest in two Gulf of Mexico fields. ludes noncash asset retirement costs as follows:
2019 |  |  |  |  |  |  |  |  |
Exploration costs | $ | — |  |  | — |  |  | — |  |  | — |  |  | — |
Development costs | 75.8 |  |  | 3.8 |  |  | — |  |  | — |  |  | 79.6 |
﻿ | $ | 75.8 |  |  | 3.8 |  |  | — |  |  | — |  |  | 79.6 |
2018 |  |  |  |  |  |  |  |  |
Exploration costs | $ | — |  |  | — |  |  | — |  |  | — |  |  | — |
Development costs | 366.0 |  |  | — |  |  | 7.3 |  |  | 0.2 |  |  | 373.5 |
﻿ | $ | 366.0 |  |  | — |  |  | 7.3 |  |  | 0.2 |  |  | 373.5 |
2017 |  |  |  |  |  |  |  |  |
Exploration costs | $ | — |  |  | — |  |  | — |  |  | — |  |  | — |
Development costs | 37.6 |  |  | 6.3 |  |  | 8.4 |  |  | — |  |  | 52.3 |
﻿ | $ | 37.6 |  |  | 6.3 |  |  | 8.4 |  |  | — |  |  | 52.3 |
Results of Operations for Oil and Natural Gas Producing Activities 1
(Millions of dollars) | United States |  | Canada |  | Other |  | Total
Year ended December 31, 2019 |  |  |  |  |  |  |
Revenues |  |  |  |  |  |  |  |  |  |  |
Crude oil and natural gas liquids sales | $ | 2,285.8 |  |  | 287.4 |  |  | 11.6 |  |  | 2,584.8 |
Natural gas sales | 73.9 |  |  | 158.4 |  |  | — |  |  | 232.3 |
Total oil and natural gas revenues | 2,359.7 |  |  | 445.8 |  |  | 11.6 |  |  | 2,817.1 |
Other operating revenues | 7.3 |  |  | 1.2 |  |  | — |  |  | 8.5 |
Total revenues | 2,367.0 |  |  | 447.0 |  |  | 11.6 |  |  | 2,825.6 |
Costs and expenses |  |  |  |  |  |  |
Lease operating expenses | 461.5 |  |  | 142.4 |  |  | 1.3 |  |  | 605.2 |
Severance and ad valorem taxes | 46.6 |  |  | 1.4 |  |  | — |  |  | 48.0 |
Transportation, gathering and processing | 140.8 |  |  | 35.5 |  |  | — |  |  | 176.3 |
Exploration costs charged to expense | 21.4 |  |  | 0.6 |  |  | 45.3 |  |  | 67.3 |
Undeveloped lease amortization | 23.1 |  |  | 1.3 |  |  | 3.6 |  |  | 28.0 |
Depreciation, depletion and amortization | 878.7 |  |  | 243.0 |  |  | 3.5 |  |  | 1,125.2 |
Accretion of asset retirement obligations | 34.4 |  |  | 6.1 |  |  | — |  |  | 40.5 |
Selling and general expenses | 74.3 |  |  | 30.0 |  |  | 22.5 |  |  | 126.8 |
Other expenses (benefits) | 52.2 |  |  | (6.1 | ) |  | 1.3 |  |  | 47.4 |
Total costs and expenses | 1,733.0 |  |  | 454.2 |  |  | 77.5 |  |  | 2,264.7 |
Results of operations before taxes | 634.0 |  |  | (7.2 | ) |  | (65.9 | ) |  | 560.9 |
Income tax expense (benefit) | 115.6 |  |  | (2.9 | ) |  | (12.4 | ) |  | 100.3 |
Results of operations | $ | 518.4 |  |  | (4.3 | ) |  | (53.5 | ) |  | 460.6 |
Year ended December 31, 2018 |  |  |  |  |  |  |
Revenues |  |  |  |  |  |  |
Crude oil and natural gas liquids sales | $ | 1,277.7 |  |  | 302.8 |  |  | 6.1 |  |  | 1,586.6 |
Natural gas sales | 53.6 |  |  | 166.3 |  |  | — |  |  | 219.9 |
Total oil and natural gas revenues | 1,331.3 |  |  | 469.1 |  |  | 6.1 |  |  | 1,806.5 |
Other operating revenues | 1.4 |  |  | 1.4 |  |  | 16.1 |  |  | 18.9 |
Total revenues | 1,332.7 |  |  | 470.5 |  |  | 22.2 |  |  | 1,825.4 |
Costs and expenses |  |  |  |  |  |  |
Lease operating expenses | 230.5 |  |  | 122.6 |  |  | 0.7 |  |  | 353.8 |
Severance and ad valorem taxes | 50.9 |  |  | 1.2 |  |  | — |  |  | 52.1 |
Transportation, gathering and processing | 43.1 |  |  | 31.9 |  |  | — |  |  | 75.0 |
Exploration costs charged to expense | 29.4 |  |  | 0.6 |  |  | 31.6 |  |  | 61.6 |
Undeveloped lease amortization | 36.8 |  |  | 0.8 |  |  | 2.5 |  |  | 40.1 |
Depreciation, depletion and amortization | 519.5 |  |  | 232.4 |  |  | 3.5 |  |  | 755.4 |
Accretion of asset retirement obligations | 19.5 |  |  | 7.7 |  |  | — |  |  | 27.2 |
Impairment of assets | 20.0 |  |  | — |  |  | — |  |  | 20.0 |
Selling and general expenses | 49.0 |  |  | 26.8 |  |  | 23.5 |  |  | 99.3 |
Other expenses | 23.0 |  |  | (19.1 | ) |  | 2.3 |  |  | 6.2 |
Total costs and expenses | 1,021.7 |  |  | 404.9 |  |  | 64.1 |  |  | 1,490.7 |
Results of operations before taxes | 311.0 |  |  | 65.6 |  |  | (41.9 | ) |  | 334.7 |
Income tax expense (benefit) | 68.1 |  |  | 14.5 |  |  | (25.3 | ) |  | 57.3 |
Results of operations | $ | 242.9 |  |  | 51.1 |  |  | (16.6 | ) |  | 277.4 |
1 Results exclude corporate overhead, interest and discontinued operations. 2019 and 2018 include noncontrolling interest in MP GOM. ໿
(Millions of dollars) | United States |  | Canada |  | Other |  | Total
Year ended December 31, 2017 |  |  |  |  |  |  |
Revenues |  |  |  |  |  |  |
Crude oil and natural gas liquids sales | $ | 903.7 |  |  | 203.7 |  |  | — |  |  | 1,107.4 |
Natural gas sales | 37.9 |  |  | 155.1 |  |  | — |  |  | 193.0 |
Total oil and natural gas revenues | 941.6 |  |  | 358.8 |  |  | — |  |  | 1,300.4 |
Other operating revenues | 2.7 |  |  | 126.7 |  |  | — |  |  | 129.4 |
Total revenues | 944.3 |  |  | 485.5 |  |  | — |  |  | 1,429.8 |
Costs and expenses |  |  |  |  |  |  |
Lease operating expenses | 198.5 |  |  | 101.1 |  |  | — |  |  | 299.6 |
Severance and ad valorem taxes | 42.2 |  |  | 1.5 |  |  | — |  |  | 43.7 |
Exploration costs charged to expense | 7.8 |  |  | 0.5 |  |  | 50.3 |  |  | 58.6 |
Undeveloped lease amortization | 60.2 |  |  | 1.6 |  |  | — |  |  | 61.8 |
Depreciation, depletion and amortization | 546.1 |  |  | 185.4 |  |  | 3.8 |  |  | 735.3 |
Accretion of asset retirement obligations | 17.4 |  |  | 7.9 |  |  | — |  |  | 25.3 |
Selling and general expenses | 61.8 |  |  | 28.3 |  |  | 19.6 |  |  | 109.7 |
Other expenses | 20.0 |  |  | 2.3 |  |  | 73.7 |  |  | 96.0 |
Total costs and expenses | 954.0 |  |  | 328.6 |  |  | 73.7 |  |  | 1,356.3 |
Results of operations before taxes | (9.7 | ) |  | 156.9 |  |  | (73.7 | ) |  | 73.5 |
Income tax expense (benefit) | (0.8 | ) |  | 44.4 |  |  | (36.2 | ) |  | 7.4 |
Results of operations | $ | (8.9 | ) |  | 112.5 |  |  | (37.5 | ) |  | 66.1 |
1 Results exclude corporate overhead, interest and discontinued operations. Schedule 7 – Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves 1
(Millions of dollars) | United States |  | Canada |  | Malaysia & Other |  | Total
December 31, 2019 |  |  |  |  |  |  |  |  |  |  |
Future cash inflows | $ | 23,565.6 |  |  | 4,912.1 |  |  | 55.7 |  |  | 28,533.4 |
Future development costs | (4,137.8 | ) |  | (723.7 | ) |  | (0.3 | ) |  | (4,861.8 | )
Future production costs | (8,986.2 | ) |  | (2,549.9 | ) |  | (29.9 | ) |  | (11,566.0 | )
Future income taxes | (1,709.3 | ) |  | (414.5 | ) |  | (14.1 | ) |  | (2,137.9 | )
Future net cash flows | 8,732.3 |  |  | 1,224.0 |  |  | 11.4 |  |  | 9,967.7 |
10% annual discount for estimated timing of cash flows | (3,633.1 | ) |  | (504.0 | ) |  | (3.0 | ) |  | (4,140.1 | )
Standardized measure of discounted future net cash flows | $ | 5,099.2 |  |  | 720.0 |  |  | 8.4 |  |  | 5,827.6 |
December 31, 2018 |  |  |  |  |  |  |
Future cash inflows | $ | 23,473.9 |  |  | 5,437.5 |  |  | 5,511.6 |  |  | 34,423.0 |
Future development costs | (3,279.1 | ) |  | (1,362.7 | ) |  | (517.4 | ) |  | (5,159.2 | )
Future production costs | (7,279.5 | ) |  | (2,693.0 | ) |  | (2,813.4 | ) |  | (12,785.9 | )
Future income taxes | (2,216.5 | ) |  | (236.4 | ) |  | (472.0 | ) |  | (2,924.9 | )
Future net cash flows | 10,698.8 |  |  | 1,145.4 |  |  | 1,708.8 |  |  | 13,553.0 |
10% annual discount for estimated timing of cash flows | (4,295.4 | ) |  | (531.4 | ) |  | (446.3 | ) |  | (5,273.1 | )
Standardized measure of discounted future net cash flows | $ | 6,403.4 |  |  | 614.0 |  |  | 1,262.5 |  |  | 8,279.9 |
December 31, 2017 |  |  |  |  |  |  |
Future cash inflows | $ | 12,885.8 |  |  | 4,714.3 |  |  | 4,392.0 |  |  | 21,992.1 |
Future development costs | (2,079.5 | ) |  | (1,081.7 | ) |  | (632.3 | ) |  | (3,793.5 | )
Future production costs | (4,765.3 | ) |  | (2,507.4 | ) |  | (2,305.0 | ) |  | (9,577.7 | )
Future income taxes | (893.7 | ) |  | (161.1 | ) |  | (232.2 | ) |  | (1,287.0 | )
Future net cash flows | 5,147.3 |  |  | 964.1 |  |  | 1,222.5 |  |  | 7,333.9 |
10% annual discount for estimated timing of cash flows | (2,698.2 | ) |  | (394.6 | ) |  | (318.2 | ) |  | (3,411.0 | )
Standardized measure of discounted future net cash flows | $ | 2,449.1 |  |  | 569.5 |  |  | 904.3 |  |  | 3,922.9 |
1 2019 and 2018 include noncontrolling interest in MP GOM. Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown.
(Millions of dollars) | 2019 |  | 2018 |  | 2017
Net changes in prices and production costs 2 | (2,993.9 | ) |  | 2,972.6 |  |  | 2,428.4 |
Net changes in development costs | (675.7 | ) |  | (1,891.1 | ) |  | (724.4 | )
Sales and transfers of oil and natural gas produced, net of production costs | (2,163.8 | ) |  | (1,978.6 | ) |  | (1,576.0 | )
Net change due to extensions and discoveries | 1,221.9 |  |  | 1,930.3 |  |  | 807.9 |
Net change due to purchases and sales of proved reserves | (628.1 | ) |  | 3,152.4 |  |  | 85.9 |
Development costs incurred | 1,282.4 |  |  | 1,017.3 |  |  | 802.7 |
Accretion of discount | 1,002.0 |  |  | 469.5 |  |  | 270.9 |
Revisions of previous quantity estimates | (71.2 | ) |  | (347.8 | ) |  | (109.5 | )
Net change in income taxes | 574.1 |  |  | (967.6 | ) |  | (643.0 | )
Net increase (decrease) | (2,452.3 | ) |  | 4,357.0 |  |  | 1,342.9 |
Standardized measure at January 1 | 8,279.9 |  |  | 3,922.9 |  |  | 2,580.0 |
Standardized measure at December 31 | 5,827.6 |  |  | 8,279.9 |  |  | 3,922.9 |
1 2019 and 2018 include noncontrolling interest in MP GOM. 2 The average prices used for 2019 were $55.69 per barrel for NYMEX crude oil (WTI), and $2.57 per Mcf for natural gas (Henry Hub). The average prices used for 2018 were $65.56 per barrel for NYMEX crude oil (WTI), and $3.10 per Mcf for natural gas (Henry Hub). Capitalized Costs Relating to Oil and Natural Gas Producing Activities ໿
(Millions of dollars) | United States |  | Canada |  | Other |  | Total
December 31, 2019 |  |  |  |  |  |  |
Unproved oil and natural gas properties | $ | 1,116.6 |  |  | 243.7 |  |  | 210.4 |  |  | 1,570.7 |
Proved oil and natural gas properties | 13,292.6 |  |  | 4,176.7 |  |  | 21.1 |  |  | 17,490.4 |
Gross capitalized costs | 14,409.2 |  |  | 4,420.4 |  |  | 231.5 |  |  | 19,061.1 |
Accumulated depreciation, depletion and amortization |  |  |  |  |  |  |
Unproved oil and natural gas properties | (136.4 | ) |  | (225.4 | ) |  | (25.9 | ) |  | (387.7 | )
Proved oil and natural gas properties | (6,298.9 | ) |  | (2,438.6 | ) |  | (2.4 | ) |  | (8,739.9 | )
Net capitalized costs | $ | 7,973.9 |  |  | 1,756.4 |  |  | 203.2 |  |  | 9,933.5 |
December 31, 2018 |  |  |  |  |  |  |
Unproved oil and natural gas properties | $ | 394.2 |  |  | 250.0 |  |  | 176.9 |  |  | 821.1 |
Proved oil and natural gas properties | 11,678.3 |  |  | 3,693.0 |  |  | — |  |  | 15,371.3 |
Gross capitalized costs | 12,072.5 |  |  | 3,943.0 |  |  | 176.9 |  |  | 16,192.4 |
Accumulated depreciation, depletion and amortization |  |  |  |  |  |  |
Unproved oil and natural gas properties | (129.3 | ) |  | (213.5 | ) |  | (25.4 | ) |  | (368.2 | )
Proved oil and natural gas properties | (5,433.7 | ) |  | (2,088.8 | ) |  | — |  |  | (7,522.5 | )
Net capitalized costs | $ | 6,509.5 |  |  | 1,640.7 |  |  | 151.5 |  |  | 8,301.7 |
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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