Supplemental Oil and Gas Disclosures - Unaudited (Tables)
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12 Months Ended |
Dec. 31, 2021 |
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| Notes Tables |
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| Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block] |
Net capitalized costs related to our oil, NGLs and natural gas producing activities are as follows (in millions):
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Year Ended December 31, |
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2021 |
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2020 |
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2019 |
Net capitalized costs: |
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Proved oil and natural gas properties and equipment |
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$ |
8,636.4 |
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$ |
8,567.5 |
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$ |
8,532.2 |
Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities |
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(7,981.3) |
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(7,890.9) |
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(7,793.3) |
Net capitalized costs related to producing activities |
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$ |
655.1 |
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$ |
676.6 |
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$ |
738.9 |
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| Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] |
The following costs were incurred in oil and gas acquisition, exploration, and development activities (in millions):
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Year Ended December 31, |
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2021 |
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2020 |
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2019 |
Costs incurred: (1) |
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Proved properties acquisitions |
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$ |
2.2 |
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$ |
8.1 |
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$ |
223.8 |
Exploration (2) |
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47.3 |
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7.4 |
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30.6 |
Development |
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18.4 |
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23.6 |
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114.5 |
Total costs incurred in oil and gas property acquisition, exploration and development activities |
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$ |
67.9 |
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$ |
39.1 |
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$ |
368.9 |
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(1) |
Includes net additions from capitalized ARO of $36.2 million, $15.2 million, and $37.5 million during 2021, 2020, and 2019, respectively. These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates.
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(2) |
Includes seismic costs of $0.1 million, $0.3 million, and $7.8 million incurred during 2021, 2020, and 2019, respectively. Includes geological and geophysical costs charged to expense of $5.7 million, $4.5 million, and $5.7 million during 2021, 2020, and 2019, respectively.
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| Schedule of Amortization Expense Per Unit of Production [Table Text Block] |
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Year Ended December 31, |
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2021 |
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2020 |
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2019 |
Depreciation, depletion, amortization and accretion ($/Boe) |
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$ |
8.15 |
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$ |
7.82 |
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$ |
10.01 |
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| Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block] |
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Total Energy Equivalent |
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Reserves (1) |
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Natural Gas |
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NGLs |
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Natural Gas |
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Oil Equivalent |
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Equivalent |
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Oil (MMBbls) |
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(MMBbls) |
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(Bcf) |
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(MMBoe) |
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(Bcfe) |
Proved reserves as of December 31, 2018 |
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39.1 |
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9.8 |
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210.5 |
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84.0 |
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504.1 |
Revisions of previous estimates (2) |
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1.4 |
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(1.5) |
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(16.9) |
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(3.0) |
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(18.2) |
Extensions and discoveries (3) |
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0.9 |
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0.1 |
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1.2 |
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1.1 |
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6.7 |
Purchase of minerals in place (4) |
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3.1 |
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17.4 |
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417.6 |
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90.1 |
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540.9 |
Production |
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(6.7) |
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(1.3) |
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(41.3) |
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(14.8) |
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(89.0) |
Proved reserves as of December 31, 2019 |
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37.8 |
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24.5 |
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571.1 |
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157.4 |
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944.5 |
Revisions of previous estimates (5) |
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(0.9) |
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(5.9) |
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31.6 |
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(1.4) |
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(8.8) |
Extensions and discoveries (6) |
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0.2 |
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— |
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0.2 |
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0.2 |
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1.3 |
Purchase of minerals in place (7) |
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0.7 |
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0.5 |
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14.8 |
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3.6 |
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21.8 |
Production |
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(5.6) |
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(1.7) |
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(48.4) |
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(15.4) |
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(92.3) |
Proved reserves as of December 31, 2020 |
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32.2 |
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17.4 |
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569.3 |
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144.4 |
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866.5 |
Revisions of previous estimates (8) |
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10.0 |
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3.1 |
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83.0 |
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27.1 |
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162.4 |
Extensions and discoveries |
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— |
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— |
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— |
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— |
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— |
Purchase of minerals in place (9) |
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— |
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— |
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0.1 |
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— |
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0.1 |
Production |
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(5.0) |
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(1.4) |
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(44.8) |
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(13.9) |
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(83.5) |
Proved reserves as of December 31, 2021 |
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37.2 |
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19.1 |
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607.6 |
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157.6 |
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945.5 |
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Year-end proved developed reserves: |
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2021 |
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27.6 |
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17.8 |
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549.2 |
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137.0 |
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821.9 |
2020 |
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24.0 |
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16.5 |
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550.2 |
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132.2 |
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793.3 |
2019 |
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28.0 |
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21.7 |
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504.9 |
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133.8 |
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802.9 |
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Year-end proved undeveloped reserves: |
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2021(10) |
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9.6 |
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1.3 |
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58.4 |
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20.6 |
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123.8 |
2020 |
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8.2 |
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0.9 |
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19.1 |
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12.2 |
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73.2 |
2019 |
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9.8 |
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2.8 |
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66.2 |
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23.6 |
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141.6 |
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(1) |
The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ significantly. |
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(2) |
Increases primarily related to upward revisions to our Ship Shoal 028 field and our Main Pass 108 field. Decreases of 10.0 MMBoe were due to price revisions for all proved reserves, which include estimated price revisions of the purchase of minerals in place from the date of purchase to December 31, 2019.
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(3) |
Primarily related to extensions and discoveries of 0.9 MMBoe at our Mississippi Canyon 800 (Gladden) field.
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(4) |
Primarily related to the Mobile Bay Properties and Magnolia acquisitions. |
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(5) |
Decreases of 27.7 MMBoe were due to price revisions for all proved reserves. increases of 26.2 MMBoe were primarily related to technical revisions at our Mobile Bay and Fairway properties.
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(6) |
Primarily related to the discovery at East Cameron 338 field. |
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(7) |
Primarily related to the Mobile Bay Properties and Mahogany working interest acquisitions. |
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(8) |
Increases of 27.1 MMBoe were due to price revisions for all proved reserves.
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(9) |
Primarily related to Main Pass working interest acquisitions. |
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(10) |
We believe that we will be able to develop all but 2.5 MMBoe (approximately 12%) of the total 20.6 MMBoe classified as PUDs at December 31, 2021, within five years from the date such PUDs were initially recorded. The lone exceptions are at the Mississippi Canyon 243 field (“Matterhorn”) and Viosca Knoll 823 (“Virgo”) deepwater fields where future development drilling has been planned as sidetracks of existing wellbores due to conductor slot limitations and rig availability. Two sidetrack PUD locations, one each at Matterhorn and Virgo, will be delayed until an existing well is depleted and available to sidetrack. We also plan to recomplete and convert an existing producer at Matterhorn to water injection for improved recovery following depletion of existing well. Based on the latest reserve report, these PUD locations are expected to be developed in 2023 and 2024.
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| Schedule Of Prices Weighted By Field Production Related To The Proved Reserves [Table Text Block] |
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December 31, |
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2021 |
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2020 |
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2019 |
Oil ($/Bbl) |
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$ |
65.25 |
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$ |
37.78 |
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$ |
58.11 |
NGLs ($/Bbl) |
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26.83 |
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10.29 |
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18.72 |
Natural gas ($/Mcf) |
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3.68 |
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2.05 |
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2.63 |
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| Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block] |
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Year Ended December 31, |
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2021 |
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2020 |
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2019 |
Standardized Measure of Discounted Future Net Cash Flows |
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Future cash inflows |
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$ |
5,178.2 |
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$ |
2,561.2 |
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$ |
4,153.8 |
Future costs: |
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Production |
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(2,061.7) |
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(1,257.4) |
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(1,901.1) |
Development and abandonment |
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(976.5) |
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(707.4) |
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(794.7) |
Income taxes |
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(359.0) |
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(60.5) |
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(170.5) |
Future net cash inflows before 10% discount |
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1,781.0 |
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535.9 |
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1,287.5 |
10% annual discount factor |
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(625.0) |
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(42.2) |
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(300.6) |
Total |
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$ |
1,156.0 |
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$ |
493.7 |
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$ |
986.9 |
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| Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block] |
The change in the standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions):
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Year Ended December 31, |
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2021 |
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2020 |
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2019 |
Changes in Standardized Measure |
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Standardized measure, beginning of year |
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$ |
493.7 |
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$ |
986.9 |
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$ |
1,067.0 |
Increases (decreases): |
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Sales and transfers of oil and gas produced, net of production costs |
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(370.5) |
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(168.6) |
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(315.8) |
Net changes in price, net of future production costs |
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980.9 |
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(503.7) |
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(376.4) |
Extensions and discoveries, net of future production and development costs |
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— |
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2.8 |
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27.0 |
Changes in estimated future development costs |
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(25.4) |
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(15.9) |
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(6.0) |
Previously estimated development costs incurred |
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0.6 |
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1.4 |
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19.3 |
Revisions of quantity estimates |
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289.6 |
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(65.2) |
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116.4 |
Accretion of discount |
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44.0 |
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111.8 |
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107.4 |
Net change in income taxes |
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(181.8) |
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87.7 |
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62.9 |
Purchases of reserves in-place |
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0.5 |
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44.6 |
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298.3 |
Sales of reserves in-place |
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— |
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— |
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— |
Changes in production rates due to timing and other |
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(75.6) |
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11.9 |
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(13.2) |
Net (decrease) increase |
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662.3 |
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(493.2) |
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(80.1) |
Standardized measure, end of year |
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$ |
1,156.0 |
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$ |
493.7 |
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$ |
986.9 |
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