Supplemental Oil and Gas Disclosures (Unaudited)

12 Months Ended

Dec. 31, 2022

Extractive Industries [Abstract]

Supplemental Oil and Gas Disclosures (Unaudited)

Note 14 — Supplemental Oil and Gas Disclosures (Unaudited)

Capitalized Costs

Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion and amortization as of the dates indicated are presented below (in thousands):

	Year Ended December 31,
	2022		2021		2020
Proved properties	$	5,964,340	$	5,232,479	$	4,945,550
Unproved oil and gas properties, not subject to amortization(1)		154,783		219,055		254,994
Total oil and gas properties		6,119,123		5,451,534		5,200,544
Less: Accumulated depletion		3,484,590		3,072,907		2,680,254
Net capitalized costs	$	2,634,533	$	2,378,627	$	2,520,290
Depletion and amortization rate (Per MBoe)(2)	$	18.95	$	16.71	$	31.42

(1)Amount includes $111.4 million, $110.3 million and $121.7 million of unproved properties, not subject to amortization, related to the Company’s operations in offshore Mexico for the years ended December 31, 2022, 2021 and 2020, respectively.

(2)Year ended December 31, 2020 includes the impact of a write-down of U.S. oil and natural gas properties as a result of the Company’s ceiling test computations. See Note 4 — Property, Plant and Equipment for additional information.

Included in the depletable basis of proved oil and gas properties is the estimate of the Company’s proportionate share of asset retirement costs relating to these properties which are also reflected as “Asset retirement obligations” on the accompanying Consolidated Balance Sheets. See Note 4 — Property, Plant and Equipment for additional information.

Costs Incurred for Property Acquisition, Exploration and Development Activities

The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to estimates during the year.

	Year Ended December 31,
	2022		2021		2020
Property acquisition costs:
Proved properties	$	—	$	210	$	422,833
Unproved properties, not subject to amortization		2,221		—		95,242
Total property acquisition costs		2,221		210		518,075
Exploration costs(1)		125,889		23,844		59,422
Development costs		541,512		245,058		362,011
Total costs incurred	$	669,622	$	269,112	$	939,508

(1)Amount includes $1.2 million, $6.6 million and $14.6 million of exploration costs related to the Company’s operations in offshore Mexico for the years ended December 31, 2022, 2021 and 2020, respectively.

Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves

The Company employs full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Engineering reserve estimates were prepared based upon interpretation of production performance data and subsurface information obtained from the drilling of existing wells. The Company’s Director of Reserves, internal reservoir engineers and geologists analyzed and prepared reserve estimates on all oil and natural gas fields. All of the Company’s proved oil, natural gas and NGL reserves are located in the U.S. Gulf of Mexico.

At, December 31, 2022, 2021 and 2020, 100% of proved oil, natural gas and NGL reserves attributable to all of the Company’s oil and natural gas properties were estimated and compiled for reporting purposes by the Company’s reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists.

The following table presents the Company’s estimated proved reserves at its net ownership interest:

	Oil (MBbls)			Gas (MMcf)			NGL (MBbls)			Oil Equivalent (MBoe)
Total proved reserves at December 31, 2019		106,754			155,998			8,981			141,735
Revision of previous estimates		(14,633	)		(56,358	)		(168	)		(24,195	)
Production(1)		(13,665	)		(28,652	)		(1,559	)		(19,999	)
Purchases of reserves		26,903			181,872			3,528			60,743
Extensions and discoveries		3,948			4,348			76			4,749
Total proved reserves at December 31, 2020		109,307			257,208			10,858			163,033
Revision of previous estimates		13,619			8,979			5,137			20,252
Production		(16,159	)		(32,795	)		(1,875	)		(23,500	)
Extensions and discoveries		997			2,961			315			1,806
Total proved reserves at December 31, 2021		107,764			236,353			14,435			161,591
Revision of previous estimates		(5,625	)		(8,302	)		(2,002	)		(9,010	)
Production		(14,561	)		(32,215	)		(1,793	)		(21,723	)
Sales of reserves		(158	)		(7,625	)		—			(1,429	)
Extensions and discoveries		3,639			31,340			2,288			11,150
Total proved reserves at December 31, 2022		91,059			219,551			12,928			140,579
Total proved developed reserves as of:
December 31, 2020		85,007			204,054			8,104			127,120
December 31, 2021		93,420			186,442			11,792			136,286
December 31, 2022		80,285			161,727			9,315			116,555
Total proved undeveloped reserves as of:
December 31, 2020		24,300			53,154			2,754			35,913
December 31, 2021		14,344			49,911			2,643			25,305
December 31, 2022		10,774			57,824			3,613			24,024

(1)Excludes approximately 3.0 MBoe of Mexico well test production.

During 2022, proved reserves decreased by 21.0 MMBoe primarily due to a decrease of 21.7 MMBoe of production. Additionally, there was a decrease of 9.0 MMBoe primarily due to timing of development of certain PUD locations to move beyond five years at the Phoenix Field in the Green Canyon core area and sales of reserves of 1.4 MMBoe primarily related to the Brushy Creek Field in the Shelf and Gulf Coast core area. The decrease was partially offset by 11.2 MMBoe of estimated proved reserves from extensions and discoveries primarily from evaluations of the Pompano Field and the Ram Powell Field located in the Mississippi Canyon core area.

During 2021, proved reserves decreased by 1.4 MMBoe primarily due to a decrease of 23.5 MMBoe of production. The decrease was partially offset by revision to previous estimates of 20.3 MMBoe due to increase in commodity prices as well as 1.8 MMBoe of estimated proved reserves from extensions and discoveries primarily from an evaluation of Crown and Anchor Field located in the Mississippi Canyon core area.

During 2020, proved reserves decreased by 21.3 MMBoe primarily due to a decrease of 20.0 MMBoe of production and revision to previous estimates of 24.2 MMBoe due to decrease in commodity prices. The decrease was partially offset by the addition of 60.7 MMBoe added through purchases from the ILX and Castex Acquisition, Castex Energy 2005 Acquisition and LLOG Acquisition as well as 4.7 MMBoe of estimated proved reserves from extensions and discoveries primarily from an evaluation of Green Canyon 18 and Claiborne Fields.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves

The following table reflects the standardized measure of discounted future net cash flows relating to the Company’s interest in proved oil, natural gas and NGL reserves (in thousands):

	Year Ended December 31,
	2022			2021			2020
Future cash inflows	$	10,674,896		$	8,496,005		$	4,927,497
Future costs:
Production		(1,906,752	)		(1,868,818	)		(1,105,211	)
Development and abandonment		(1,873,453	)		(1,422,507	)		(1,236,874	)
Future net cash flows before income taxes		6,894,691			5,204,680			2,585,412
Future income tax expense		(1,114,409	)		(676,778	)		(141,515	)
Future net cash flows after income taxes		5,780,282			4,527,902			2,443,897
Discount at 10% annual rate		(1,411,834	)		(1,087,291	)		(538,963	)
Standardized measure of discounted future net cash flows	$	4,368,448		$	3,440,611		$	1,904,934

Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of derivative instruments. See the following table for SEC Pricing used in determining the standardized measure:

	Year Ended December 31,
	2022		2021		2020
Oil price per Bbl	$	96.03	$	67.14	$	39.47
Natural gas price per Mcf	$	6.80	$	3.71	$	1.97
NGL price per Bbl	$	33.89	$	26.62	$	9.89

Future net cash flows are discounted at the prescribed rate of 10%. Actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development and abandonment costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. All estimated costs to settle asset retirement obligations associated with our proved reserves have been included in our calculation of development and abandonment of the standardized measure of discounted future net cash flows for each period presented. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves.

Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved oil, natural gas and NGL reserves are as follows (in thousands):

	Year Ended December 31,
	2022			2021			2020
Standardized measure, beginning of year	$	3,440,611		$	1,904,934		$	2,537,595
Sales and transfers of oil, net gas and NGLs produced during the period		(1,340,400	)		(957,576	)		(339,557	)
Net change in prices and production costs		2,388,442			2,049,980			(1,468,304	)
Changes in estimated future development and abandonment costs		(84,391	)		(57,876	)		32,589
Previously estimated development and abandonment costs incurred		20,107			69,125			46,143
Accretion of discount		392,600			199,849			299,302
Net change in income taxes		(327,265	)		(391,834	)		361,875
Purchases of reserves		—			—			730,611
Sales of reserves		(5,218	)		—			—
Extensions and discoveries		202,239			45,485			71,589
Net change due to revision in quantity estimates		(255,743	)		426,357			(309,338	)
Changes in production rates (timing) and other		(62,534	)		152,167			(57,571	)
Standardized measure, end of year	$	4,368,448		$	3,440,611		$	1,904,934