0001784031-24-000003 | 10-K | XBRL Viewer

Amount of revenue recognized from goods sold, services rendered, insurance premiums, or other activities that constitute an earning process. Includes, but is not limited to, investment and interest income before deduction of interest expense when recognized as a component of revenue, and sales and trading gain (loss).

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
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-Name Accounting Standards Codification
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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Reference 6: http://www.xbrl.org/2009/role/commonPracticeRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

12 Months Ended

Dec. 31, 2023

Extractive Industries [Abstract]

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Oil and Gas Operations

The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities. The Company has no long-term agreements to purchase oil or gas production from foreign governments or authorities.


	United States		Egypt(1)		North Sea		Other International		Total(1)

	(In millions, except per boe)
2023
Oil and gas production revenues	$	3,018	$	3,029	$	1,338	$	—	$	7,385
Operating cost:
Depreciation, depletion, and amortization(2)	709		521		270		—		1,500
Asset retirement obligation accretion	40		—		76		—		116
Lease operating expenses	593		474		369		—		1,436
Gathering, processing, and transmission	249		33		52		—		334
Exploration expenses	14		119		19		43		195

Production taxes(3)	204		—		—		—		204
Income tax	254		828		414		—		1,496
	2,063		1,975		1,200		43		5,281
Results of operations	$	955	$	1,054	$	138	$	(43)	$	2,104
2022
Oil and gas production revenues	$	4,144	$	3,521	$	1,558	$	—	$	9,223
Operating cost:
Depreciation, depletion, and amortization(2)	564		390		232		—		1,186
Asset retirement obligation accretion	34		—		82		—		116
Lease operating expenses	515		526		404		—		1,445
Gathering, processing, and transmission	315		22		43		—		380
Exploration expenses	24		84		35		162		305

Production taxes(3)	263		—		—		—		263
Income tax	510		1,100		495		—		2,105
	2,225		2,122		1,291		162		5,800
Results of operations	$	1,919	$	1,399	$	267	$	(162)	$	3,423
2021
Oil and gas production revenues	$	3,280	$	2,085	$	1,136	$	—	$	6,501
Operating cost:
Depreciation, depletion, and amortization(2)	511		477		267		—		1,255
Asset retirement obligation accretion	30		—		79		—		109
Lease operating expenses	391		469		383		—		1,243
Gathering, processing, and transmission	309		12		39		—		360
Exploration expenses	28		63		34		30		155

Production taxes(3)	188		—		—		—		188
Income tax	383		479		134		—		996
	1,840		1,500		936		30		4,306
Results of operations	$	1,440	$	585	$	200	$	(30)	$	2,195

(1)Includes a noncontrolling interest in Egypt.

(2)Reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 17—Business Segment Information.

(3)Reflects only amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 17—Business Segment Information.

Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities


	United States		Egypt(2)		North Sea		Other International		Total(2)

	(In millions)
2023
Acquisitions:
Proved	$	1	$	4	$	—	$	—	$	5
Unproved	20		—		—		—		20
Exploration	31		226		44		131		432
Development	1,148		646		468		—		2,262
Costs incurred(1)	$	1,200	$	876	$	512	$	131	$	2,719
(1) Includes capitalized interest and asset retirement costs:
Capitalized interest	$	—	$	—	$	—	$	24	$	24
Asset retirement costs	(4)		—		375		—		371
2022
Acquisitions:
Proved	$	596	$	3	$	—	$	—	$	599
Unproved	66		—		—		—		66
Exploration	4		169		61		311		545
Development	848		568		(57)		—		1,359
Costs incurred(1)	$	1,514	$	740	$	4	$	311	$	2,569
(1) Includes capitalized interest and asset retirement costs:
Capitalized interest	$	—	$	—	$	1	$	17	$	18
Asset retirement costs	79		—		(215)		—		(136)
2021
Acquisitions:
Proved	$	—	$	(157)	$	—	$	—	$	(157)
Unproved	9		20		—		—		29
Exploration	6		86		39		170		301
Development	545		404		135		2		1,086
Costs incurred(1)	$	560	$	353	$	174	$	172	$	1,259
(1) Includes capitalized interest, asset retirement costs, and Egypt modernization impacts as follows:
Capitalized interest	$	—	$	—	$	—	$	9	$	9
Asset retirement costs	130		—		19		—		149
Egypt PSC modernization impacts – Proved and Unproved	—		(145)		—		—		(145)
(2) Includes a noncontrolling interest in Egypt.

In 2021, in connection with APA’s agreement to enter into a new merged concession agreement with EGPC, the Company recorded a reduction in proved properties totaling $165 million and an increase in unproved properties of $20 million, reflecting $247 million of incremental value due to the Company for the period between the effective date of April 1, 2021 and closing, partially offset by a $100 million signing bonus and $2 million of other post-closing adjustments.

Capitalized Costs

The following table sets forth the capitalized costs and associated accumulated depreciation, depletion, and amortization relating to the Company’s oil and gas acquisition, exploration, and development activities:


	United States		Egypt(1)		North Sea		Other International		Total(1)

	(In millions)
2023
Proved properties	$	20,758	$	13,777	$	9,472	$	—	$	44,007
Unproved properties	267		71		3		512		853
	21,025		13,848		9,475		512		44,860
Accumulated DD&A	(15,587)		(11,678)		(7,849)		—		(35,114)
	$	5,438	$	2,170	$	1,626	$	512	$	9,746

2022
Proved properties	$	19,638	$	13,014	$	8,945	$	—	$	41,597
Unproved properties	247		77		11		424		759
	19,885		13,091		8,956		424		42,356
Accumulated DD&A	(14,902)		(11,157)		(7,573)		—		(33,632)
	$	4,983	$	1,934	$	1,383	$	424	$	8,724

(1)Includes a noncontrolling interest in Egypt.

Oil and Gas Reserve Information

Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves.

Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating its proved reserves, the Company uses several different traditional methods that can be classified in three general categories: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy with similar properties. The Company will, at times, utilize additional technical analysis such as computer reservoir models, petrophysical techniques, and proprietary 3-D seismic interpretation methods to provide additional support for more complex reservoirs. Information from this additional analysis is combined with traditional methods outlined above to enhance the certainty of the Company’s reserve estimates.

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.


	Crude Oil and Condensate
	United States	Egypt(1)	North Sea	Total(1)

	(Thousands of barrels)
Proved developed reserves:
December 31, 2020	206,936	95,981	86,566	389,483
December 31, 2021	180,968	106,646	77,073	364,687
December 31, 2022	177,708	108,050	82,580	368,338
December 31, 2023	179,542	102,305	61,076	342,923
Proved undeveloped reserves:
December 31, 2020	25,516	11,228	7,273	44,017
December 31, 2021	18,168	11,003	5,757	34,928
December 31, 2022	22,239	8,557	2,873	33,669
December 31, 2023	30,948	5,254	—	36,202

Total proved reserves:
Balance December 31, 2020	232,452	107,209	93,839	433,500
Extensions, discoveries and other additions	17,869	13,390	2,288	33,547
Purchases of minerals in-place	126	—	—	126
Revisions of previous estimates	(4,479)	22,727	(60)	18,188
Production	(27,450)	(25,677)	(13,237)	(66,364)
Sales of minerals in-place	(19,382)	—	—	(19,382)
Balance December 31, 2021	199,136	117,649	82,830	399,615
Extensions, discoveries and other additions	9,776	7,580	2,616	19,972
Purchases of minerals in-place	16,362	—	—	16,362
Revisions of previous estimates	7,793	22,433	11,898	42,124
Production	(25,695)	(31,055)	(11,891)	(68,641)
Sales of minerals in-place	(7,425)	—	—	(7,425)
Balance December 31, 2022	199,947	116,607	85,453	402,007
Extensions, discoveries and other additions	43,613	12,979	301	56,893
Purchases of minerals in-place	20	—	—	20
Revisions of previous estimates	(3,520)	10,505	(12,002)	(5,017)
Production	(28,795)	(32,532)	(12,676)	(74,003)
Sales of minerals in-place	(775)	—	—	(775)
Balance December 31, 2023	210,490	107,559	61,076	379,125

(1)Includes proved reserves of 36 MMbbls, 39 MMbbls, 39 MMbbls, and 36 MMbbls as of December 31, 2023, 2022, 2021, and 2020, respectively, attributable to a noncontrolling interest in Egypt.


	Natural Gas Liquids
	United States	Egypt(1)	North Sea	Total(1)

	(Thousands of barrels)
Proved developed reserves:
December 31, 2020	150,599	716	2,053	153,368
December 31, 2021	164,172	446	2,059	166,677
December 31, 2022	158,745	—	2,230	160,975
December 31, 2023	153,486	—	1,460	154,946
Proved undeveloped reserves:
December 31, 2020	15,141	126	320	15,587
December 31, 2021	16,380	30	275	16,685
December 31, 2022	19,004	—	76	19,080
December 31, 2023	18,401	—	—	18,401

Total proved reserves:
Balance December 31, 2020	165,740	842	2,373	168,955
Extensions, discoveries and other additions	21,055	7	81	21,143
Purchases of minerals in-place	191	—	—	191
Revisions of previous estimates	22,724	(180)	318	22,862
Production	(24,175)	(193)	(438)	(24,806)
Sales of minerals in-place	(4,983)	—	—	(4,983)
Balance December 31, 2021	180,552	476	2,334	183,362
Extensions, discoveries and other additions	5,456	—	45	5,501
Purchases of minerals in-place	10,985	—	—	10,985
Revisions of previous estimates	9,991	(407)	333	9,917
Production	(22,895)	(69)	(406)	(23,370)
Sales of minerals in-place	(6,340)	—	—	(6,340)
Balance December 31, 2022	177,749	—	2,306	180,055
Extensions, discoveries and other additions	25,711	—	371	26,082
Purchases of minerals in-place	21	—	—	21
Revisions of previous estimates	(8,568)	—	(764)	(9,332)
Production	(22,993)	—	(453)	(23,446)
Sales of minerals in-place	(33)	—	—	(33)
Balance December 31, 2023	171,887	—	1,460	173,347

(1) Includes proved reserves of 159 Mbbls and 281 Mbbls as of December 31, 2021 and 2020, respectively, attributable to a noncontrolling interest in Egypt.


	Natural Gas
	United States	Egypt(1)	North Sea	Total(1)

	(Millions of cubic feet)
Proved developed reserves:
December 31, 2020	1,052,756	409,035	68,159	1,529,950
December 31, 2021	1,237,461	464,826	76,155	1,778,442
December 31, 2022	1,166,218	399,502	66,292	1,632,012
December 31, 2023	1,003,956	377,144	46,839	1,427,939
Proved undeveloped reserves:
December 31, 2020	76,504	12,572	8,341	97,417
December 31, 2021	184,441	9,899	7,124	201,464
December 31, 2022	210,862	1,068	2,304	214,234
December 31, 2023	99,495	2,612	—	102,107

Total proved reserves:
Balance December 31, 2020	1,129,260	421,607	76,500	1,627,367
Extensions, discoveries and other additions	227,684	50,209	3,684	281,577
Purchases of minerals in-place	839	—	—	839
Revisions of previous estimates	279,610	99,143	17,171	395,924
Production	(192,523)	(96,234)	(14,076)	(302,833)
Sales of minerals in-place	(22,968)	—	—	(22,968)
Balance December 31, 2021	1,421,902	474,725	83,279	1,979,906
Extensions, discoveries and other additions	38,157	10,191	1,643	49,991
Purchases of minerals in-place	70,584	—	—	70,584
Revisions of previous estimates	92,599	45,725	(3,431)	134,893
Production	(172,752)	(130,071)	(12,895)	(315,718)
Sales of minerals in-place	(73,410)	—	—	(73,410)
Balance December 31, 2022	1,377,080	400,570	68,596	1,846,246
Extensions, discoveries and other additions	158,118	14,188	3,335	175,641
Purchases of minerals in-place	136	—	—	136
Revisions of previous estimates	(266,664)	83,907	(6,739)	(189,496)
Production	(165,083)	(118,909)	(18,353)	(302,345)
Sales of minerals in-place	(136)	—	—	(136)
Balance December 31, 2023	1,103,451	379,756	46,839	1,530,046

(1) Includes proved reserves of 127 Bcf, 134 Bcf, 158 Bcf, and 141 Bcf as of December 31, 2023, 2022, 2021, and 2020, respectively, attributable to a noncontrolling interest in Egypt.


	Total Equivalent Reserves
	United States	Egypt(1)	North Sea	Total(1)

	(Thousands barrels of oil equivalent)
Proved developed reserves:
December 31, 2020	532,994	164,870	99,979	797,843
December 31, 2021	551,384	184,563	91,825	827,772
December 31, 2022	530,823	174,633	95,859	801,315
December 31, 2023	500,354	165,162	70,343	735,859
Proved undeveloped reserves:
December 31, 2020	53,408	13,449	8,983	75,840
December 31, 2021	65,288	12,683	7,219	85,190
December 31, 2022	76,386	8,735	3,333	88,454
December 31, 2023	65,931	5,690	—	71,621

Total proved reserves:
Balance December 31, 2020	586,402	178,319	108,962	873,683
Extensions, discoveries and other additions	76,871	21,765	2,983	101,619
Purchases of minerals in-place	457	—	—	457
Revisions of previous estimates	64,847	39,071	3,120	107,038
Production	(83,712)	(41,909)	(16,021)	(141,642)
Sales of minerals in-place	(28,193)	—	—	(28,193)
Balance December 31, 2021	616,672	197,246	99,044	912,962
Extensions, discoveries and other additions	21,592	9,278	2,935	33,805
Purchases of minerals in-place	39,110	—	—	39,110
Revisions of previous estimates	33,217	29,647	11,659	74,523
Production	(77,382)	(52,803)	(14,446)	(144,631)
Sales of minerals in-place	(26,000)	—	—	(26,000)
Balance December 31, 2022	607,209	183,368	99,192	889,769
Extensions, discoveries and other additions	95,677	15,344	1,228	112,249
Purchases of minerals in-place	64	—	—	64
Revisions of previous estimates	(56,532)	24,490	(13,889)	(45,931)
Production	(79,302)	(52,350)	(16,188)	(147,840)
Sales of minerals in-place	(831)	—	—	(831)
Balance December 31, 2023	566,285	170,852	70,343	807,480

(1) Includes total proved reserves of 57 MMboe, 61 MMboe, 66 MMboe, and 59 MMboe as of December 31, 2023, 2022, 2021, and 2020, respectively, attributable to a noncontrolling interest in Egypt.

During 2023, the Company added approximately 112 MMboe from extensions, discoveries, and other additions. The Company recorded 96 MMboe of exploration and development adds in the U.S., comprising 67 MMboe in the Permian Basin, 27 MMboe in the Delaware Basin, and 2 MMboe in the Texas Gulf Coast. Drilling programs for the Permian and Delaware Basins include the Wolfcamp, Bone Spring and Spraberry with the Austin Chalk as the primary focus for the Texas Gulf Coast. International operations contributed 16 MMboe of exploration and development adds, with Egypt contributing 15 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area and 1 MMboe from the North Sea. The Company had combined downward revisions of previously estimated reserves of 46 MMboe, primarily driven by revisions in the U.S. Downward revisions for price and interest changes accounted for 83 MMboe, offset by engineering and performance upward revisions of 37 MMboe.

During 2022, the Company added approximately 34 MMboe from extensions, discoveries, and other additions. The Company recorded 22 MMboe of exploration and development adds in the U.S., comprising 9 MMboe in the Permian Basin, 8 MMboe in the Texas Gulf Coast, and 5 MMboe in the Delaware Basin. Drilling programs for the Permian and Delaware Basins include the Wolfcamp, Bone Spring and Spraberry with the Austin Chalk as the primary focus for the Texas Gulf Coast. International operations contributed 12 MMboe of exploration and development adds, with Egypt contributing 9 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area and 3 MMboe from the North Sea. The Company had combined upward revisions of previously estimated reserves of 75 MMboe. Upward revisions related to miscellaneous changes accounted for 5 MMboe. Engineering and performance upward revisions accounted for 70 MMboe, with Egypt accounting for an increase of 43 MMboe, primarily the result of PSC modernization in Egypt. The North Sea contributed 9 MMboe of upward revisions from well performance and reactivations in both the Beryl and Forties programs. In the United States, the Company experienced positive revisions of 18 MMboe. The Company acquired 39 MMboe of proved reserves during 2022, primarily in the Delaware Basin. The Company also sold 26 MMboe of proved reserves associated with U.S. divestitures, primarily related to Permian Basin assets.

During 2021, the Company added approximately 102 MMboe from extensions, discoveries, and other additions. The Company recorded 77 MMboe of exploration and development adds in the U.S., comprising 59 MMboe in the Permian Basin with the remaining 18 MMboe in the Texas Gulf Coast. The Permian Basin drilling programs targeted the Woodford, Barnett, Bone Springs, and Spraberry, while the Texas Gulf Coast focused on the Austin Chalk. International operations contributed 25 MMboe of exploration and development adds, with Egypt contributing 22 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area concession post-PSC modernization. The North Sea contributed 3 MMboe. The Company had combined upward revisions of previously estimated reserves of 107 MMboe. Upward revisions related to changes in product prices accounted for 85 MMboe. Engineering and performance upward revisions accounted for 22 MMboe, with the new merged concession agreement in Egypt resulting in an increase of 57 MMboe, partially offset by other downward revisions of 35 MMboe across all of the Company’s geographic areas of operation. The Company also sold 28 MMboe of proved reserves associated with U.S. divestitures, primarily related to Permian Basin assets.

The impact of the consolidated PSC to proved reserves based on the modernized terms was an estimated increase of 53 MMboe and 4 MMboe in developed and undeveloped reserves, respectively, and approximately $750 million in discounted future net cash flows. As of December 31, 2021, approximately 96 percent of the Company’s Egypt reserves were consolidated within the modernized PSC. These estimates include Sinopec’s noncontrolling interest in Egypt.

Approximately 10 percent of the Company’s year-end 2023 estimated proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced, or zones that have been produced in the past, but are not now producing because of mechanical reasons. These reserves are considered to be a lower tier of reserves than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. Additional capital may have to be spent to access these reserves. The capital and economic impact of production timing are reflected in this Note 18, under “Future Net Cash Flows.”

Future Net Cash Flows

Future cash inflows as of December 31, 2023, 2022, and 2021 were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Future development costs include abandonment and dismantlement costs.

The following table sets forth unaudited information concerning future net cash flows for proved oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under laws in effect as of December 31, 2023, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.


	United States		Egypt(1)		North Sea		Total(1)

	(In millions)
2023
Cash inflows	$	21,417	$	9,921	$	5,761	$	37,099
Production costs	(8,328)		(1,690)		(2,773)		(12,791)
Development costs	(2,238)		(1,235)		(2,461)		(5,934)
Income tax expense	(949)		(2,222)		(946)		(4,117)
Net cash flows	9,902		4,774		(419)		14,257
10 percent discount rate	(3,749)		(943)		476		(4,216)
Discounted future net cash flows(2)	$	6,153	$	3,831	$	57	$	10,041
2022
Cash inflows	$	31,577	$	12,819	$	10,147	$	54,543
Production costs	(10,763)		(2,086)		(3,241)		(16,090)
Development costs	(1,733)		(1,471)		(2,297)		(5,501)
Income tax expense	(1,575)		(2,729)		(2,631)		(6,935)
Net cash flows	17,506		6,533		1,978		26,017
10 percent discount rate	(6,811)		(1,400)		(204)		(8,415)
Discounted future net cash flows(2)	$	10,695	$	5,133	$	1,774	$	17,602
2021
Cash inflows	$	22,852	$	9,337	$	6,832	$	39,021
Production costs	(8,323)		(1,712)		(2,343)		(12,378)
Development costs	(1,632)		(1,402)		(2,533)		(5,567)
Income tax expense	(134)		(1,887)		(768)		(2,789)
Net cash flows	12,763		4,336		1,188		18,287
10 percent discount rate	(5,294)		(983)		350		(5,927)
Discounted future net cash flows(2)	$	7,469	$	3,353	$	1,538	$	12,360

(1)Includes discounted future net cash flows of approximately $1.3 billion, $1.7 billion, and $1.1 billion as of December 31, 2023, 2022, and 2021, respectively, attributable to a noncontrolling interest in Egypt.

(2)Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $13.6 billion, $22.6 billion, and $14.9 billion as of December 31, 2023, 2022, and 2021, respectively.

The following table sets forth the principal sources of change in the discounted future net cash flows:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Sales, net of production costs	$	(5,408)	$	(7,131)	$	(4,707)
Net change in prices and production costs	(7,089)		8,690		9,376
Discoveries and improved recovery, net of related costs	1,869		1,142		1,749
Change in future development costs	(413)		(343)		(839)
Previously estimated development costs incurred during the period	825		669		545
Revision of quantities	(262)		2,646		1,983
Purchases of minerals in-place	1		911		1
Accretion of discount	2,260		1,489		626
Change in income taxes	1,467		(2,467)		(1,583)
Sales of minerals in-place	(18)		(363)		(116)
Change in production rates and other	(793)		(1)		13
	$	(7,561)	$	5,242	$	7,048

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting policies used by APA and its subsidiaries reflect industry practices and conform to accounting principles generally accepted in the U.S. (GAAP). The Company’s financial statements for prior periods may include reclassifications that were made to conform to the current-year presentation. Significant accounting policies are discussed below.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions.

The implementation of the Holding Company Reorganization was accounted for as a merger under common control. APA recognized the assets and liabilities of Apache at carryover basis. The consolidated financial statements of APA present comparative information for prior years on a combined basis, as if both APA and Apache were under common control for all periods presented.

The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions.

Noncontrolling interests represent third-party ownership in the net assets of a consolidated subsidiary of APA and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE.

Additionally, prior to the BCP Business Combination (as defined below), third-party investors owned a minority interest of approximately 21 percent of Altus, which was reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. ALTM qualified as a VIE under GAAP, which APA consolidated because a wholly owned subsidiary of APA had a controlling financial interest and was determined to be the primary beneficiary.

On February 22, 2022, ALTM closed a transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). Pursuant to the BCP Contribution Agreement, the Contributor contributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination). Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik), and the Company determined that it was no longer the primary beneficiary of Kinetik. The Company further determined that Kinetik no longer qualified as a VIE under GAAP. As a result, the Company deconsolidated ALTM on February 22, 2022. Refer to Note 2—Acquisitions and Divestitures for further detail.

During each of the years ended December 31, 2023 and 2022, the Company had a designated director on the Kinetik board of directors. As a result, the Company is considered to have had significant influence over Kinetik for all periods presented and will continue to have such influence until such time as Kinetik appoints a replacement for the Company’s designated director, given that the Company’s current beneficial ownership percentage in Kinetik no longer entitles it to designate a director to the Kinetik board.

Investments in which the Company has significant influence, but not control, are accounted for under the equity method of accounting. These investments are recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company elected the fair value option to account for its equity method interest in Kinetik. Refer to Note 6—Equity Method Interests for further detail.

Use of Estimates

Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known.

Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 below and Note 6—Equity Method Interests), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation), the estimate of income taxes (refer to Note 10—Income Taxes), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of Mexico (refer to Note 11—Commitments and Contingencies), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (refer to Note 18 —Supplemental Oil and Gas Disclosures (Unaudited)).

Fair Value Measurements

Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

Refer to Note 4—Derivative Instruments and Hedging Activities, Note 6—Equity Method Interests, Note 9—Debt and Financing Costs, Note 12—Retirement and Deferred Compensation Plans, and Note 13—Redeemable Noncontrolling Interest — Altus for further detail regarding the Company’s fair value measurements recorded on a recurring basis.

The Company also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment.

For the years ended December 31, 2023 and 2022, the Company recorded $11 million and no asset impairments, respectively, in connection with fair value assessments. For the year ended December 31, 2021, the Company recorded asset impairments totaling $208 million. These charges include a $160 million impairment on the Company’s equity method interest in a pipeline investment as part of Altus’ review of the fair value of its assets in relation to the BCP Business Combination. Refer to “Equity Method Interests” within this Note 1 below and Note 2—Acquisitions and Divestitures for further detail on the BCP Business Combination.

Revenue Recognition

Upstream

The Company’s upstream oil and gas segments primarily generate revenue from contracts with customers from the sale of its crude oil, natural gas, and natural gas liquids production volumes. In addition to APA-related production volumes, the Company also sells commodity volumes purchased from third parties to provide flexibility to fulfill sales obligations and commitments. Under these commodity sales contracts, the physical delivery of each unit of quantity represents a single, distinct performance obligation on behalf of the Company. Contract prices are determined based on market-indexed prices, adjusted for quality, transportation, and other market-reflective differentials. Revenue is measured by allocating an entirely variable market price to each performance obligation and recognized at a point in time when control is transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, and the Company’s right to payment. Control typically transfers to customers upon the physical delivery at specified locations within each contract and the transfer of title.

APA’s Egypt operations are conducted pursuant to production-sharing contracts (PSCs). Under the terms of the Company’s PSCs, the Company is the contractor partner (Contractor) with the Egyptian General Petroleum Corporation (EGPC) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor’s income taxes, which remain the liability of the Contractor under domestic law, are paid by EGPC on behalf of the Contractor out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on the Company’s Egypt operations despite impacting the Company’s production and reserves.

Refer to Note 17—Business Segment Information for a disaggregation of revenue by product and reporting segment.

Altus Midstream

Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Altus Midstream segment was operated by ALTM, through its subsidiary, Altus Midstream LP. Altus generated revenue from contracts with customers from its gathering, compression, processing, and transmission services provided on the Company’s natural gas and natural gas liquid production volumes. Under these long-term commercial service contracts, providing the related service represented a single, distinct performance obligation on behalf of Altus that was satisfied over time. In accordance with the terms of these agreements, Altus primarily received a fixed fee for each contract year, subject to yearly fee escalation recalculations. Revenue was primarily measured using the output method and recognized in the amount to which Altus had the right to invoice, as performance completed to date corresponded directly with the value to its customers. For the periods prior to the BCP Business Combination, Altus Midstream segment revenues were primarily attributable to sales between Altus and Apache, which were fully eliminated upon consolidation.

Payment Terms and Contract Balances

Receivables from contracts with customers, including receivables for purchased oil and gas sales and net of allowance for credit losses, were $1.5 billion and $1.3 billion as of December 31, 2023 and 2022, respectively. Payments under all contracts with customers are typically due and received within a short-term period of one year or less, after physical delivery of the product or service has been rendered. Over the past year, the Company experienced a gradual decline in the timeliness of receipts from the EGPC for the Company’s Egyptian oil and gas sales. Although the Company continues to receive periodic payments from EGPC, deteriorating economic conditions in Egypt have lessened the availability of U.S. dollars in Egypt, resulting in a delay in receipts from EGPC. Continuation of the currency shortage in Egypt could lead to further delays, deferrals of payment, or non-payment in the future; however, the Company currently anticipates that it will ultimately be able to collect its receivable from EGPC.

In accordance with the provisions of ASC 606, “Revenue from Contracts with Customers,” variable market prices for each short-term commodity sale are allocated entirely to each performance obligation as the terms of payment relate specifically to the Company’s efforts to satisfy its obligations. As such, the Company has elected the practical expedients available under the standard to not disclose the aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the end of the reporting period.

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2023 and 2022, the Company had $87 million and $245 million, respectively, of cash and cash equivalents. The Company had no restricted cash as of December 31, 2023 and 2022.

Accounts Receivable and Allowance for Credit Losses

Accounts receivable are stated at amortized cost net of an allowance for credit losses. The Company routinely assesses the collectability of its financial assets measured at amortized cost. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analyses. The Company develops its estimated allowance for expected credit losses primarily using an aging method and analyses of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity.

The following table presents changes to the Company’s allowance for credit loss:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Allowance for credit loss at beginning of year	$	117	$	109	$	95
Additional provisions for the year	16		9		19
Uncollectible accounts written off, net of recoveries	(19)		(1)		(5)
Allowance for credit loss at end of year	$	114	$	117	$	109

Inventories

Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value.

During 2023, the Company recorded $50 million of impairments in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea.

The Company also recorded other impairments during 2021 of approximately $26 million in connection with inventory valuations in Egypt and $22 million in connection with inventory valuations and expected equipment dispositions in the North Sea.

Property and Equipment

The carrying value of the Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations and acquisitions, property and equipment cost is based on the fair values at the acquisition date.

Oil and Gas Property

The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.

Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations.

The following table represents non-cash impairment charges of the carrying value of the Company’s unproved properties:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)






Unproved properties:
U.S.	$	10	$	20	$	22
Egypt	—		4		8
North Sea	11		—		1
Other International	1		—		—
Total unproved properties	$	22	$	24	$	31

Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized well costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.

Oil and gas properties are grouped for depreciation in accordance with ASC 932, “Extractive Activities—Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement.

For the years ended December 31, 2023, 2022, and 2021, the Company recorded no impairments of proved properties.

Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction. Refer to Note 2—Acquisitions and Divestitures for more detail.

Gathering, Processing, and Transmission (GPT) Facilities

GPT facilities totaled $448 million and $449 million at December 31, 2023 and 2022, respectively, with accumulated depreciation for these assets totaling $373 million and $367 million for the respective periods. GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields.

The Company assesses the carrying amount of its GPT facilities whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value.

For the years ended December 31, 2023, 2022, and 2021, the Company recorded no impairments of GPT facilities.

Other Property and Equipment

Other property and equipment includes computer software and equipment, buildings, vehicles, furniture and fixtures, land, and other equipment. These assets are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 20 years. Other property and equipment, net of accumulated depreciation totaled $217 million and $206 million at December 31, 2023 and 2022, respectively.

Asset Retirement Costs and Obligations

The initial estimated asset retirement obligation related to property and equipment and subsequent revisions are recorded as a liability at fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of an asset’s retirement. Asset retirement costs are depreciated using a systematic and rational method similar to that used for the associated property and equipment. Accretion expense on the liability is recognized over the estimated productive life of the related assets.

Capitalized Interest

For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties actively being explored, significant exploration and development projects that have not commenced production, significant midstream development activities that are in progress, and investments in equity method affiliates that are undergoing the construction of assets that have not commenced principal operations qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation.

Equity Method Interests

The Company follows the equity method of accounting when it does not exercise control over its equity interests, but can exercise significant influence over the operating and financial policies of the entity. Under this method, the equity interests are carried originally at acquisition cost, increased by the Company’s proportionate share of the equity interest’s net income and contributions made by the Company, and decreased by the Company’s proportionate share of the equity interest’s net losses and distributions received by the Company. Refer to Note 6—Equity Method Interests for further details of the Company’s equity method interests.

Equity method interests are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income. Prior to the deconsolidation of Altus on February 22, 2022, in the fourth quarter of 2021, Altus, as part of its review of the fair value of its assets in relation to the BCP Business Combination, determined the fair value of a pipeline investment was below carrying value. As such, in the fourth quarter of 2021, Altus recorded an impairment charge of $160 million on its equity method interest in the pipeline.

Commitments and Contingencies

Accruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. For more information regarding loss contingencies, refer to Note 11—Commitments and Contingencies.

Derivative Instruments and Hedging Activities

The Company periodically enters into derivative contracts to manage its exposure to commodity price, interest rate, and/or foreign exchange risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options.

All derivative instruments, other than those that meet the normal purchases and sales exception, are recorded on the Company’s consolidated balance sheet as either an asset or liability measured at fair value. The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses from the change in fair value of derivative instruments are reported in current-period income as “Derivative instrument gains (losses), net” under “Revenues and Other” in the statement of consolidated operations. Refer to Note 4—Derivative Instruments and Hedging Activities for further information.

Income Taxes

The Company records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. The Company routinely assesses the ability to realize its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. Refer to Note 10—Income Taxes for further information.

Earnings Per Share

The Company’s basic earnings per share (EPS) amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was fully vested. Prior to the deconsolidation of Altus on February 22, 2022, the Company used the “if-converted method” to determine the potential dilutive effect of an assumed exchange of the outstanding Preferred Units of Altus Midstream LP for shares of ALTM’s common stock. The impact to net income (loss) attributable to common stock on an assumed conversion of the redeemable noncontrolling Preferred Units interest in Altus Midstream LP was anti-dilutive for the year ended December 31, 2021.

Stock-Based Compensation

The Company grants various types of stock-based awards including stock options, restricted stock, cash-settled restricted stock units, and performance-based awards. Stock compensation equity awards granted are valued on the date of grant and are expensed over the required vesting service period. Cash-settled awards are recorded as a liability based on the Company’s stock price and remeasured at the end of each reporting period over the vesting terms. The Company has elected to account for forfeitures as they occur rather than estimate expected forfeitures. The Company’s stock-based compensation plans and related accounting policies are defined and described more fully in Note 14—Capital Stock.

Treasury Stock

The Company follows the weighted-average-cost method of accounting for treasury stock transactions.

Transaction, Reorganization, and Separation (TRS)

The Company recorded TRS costs in 2023, 2022, and 2021 totaling $15 million, $26 million, and $22 million, respectively, including $7 million, $15 million, and $17 million, respectively, related to ongoing consulting and separation costs in international operations associated with the redesign of the Company’s organizational structure and operations.

New Pronouncements Issued But Not Yet Adopted

In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-07, “Segment Reporting (Topic 280),” which expands disclosures about a public entity’s reportable segments and requires more enhanced information about a reportable segment’s expenses, interim segment profit or loss, and how a public entity’s chief operating decision maker uses reported segment profit or loss information in assessing segment performance and allocating resources. The amendments do not change or remove existing disclosure requirements or how a public entity identifies its operating segments, aggregates those operating segments, or applies the quantitative thresholds to determine its reportable segments. The amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted, and the amendments are required to be applied on a retrospective basis. The Company is currently assessing the impact of adopting this standard and does not believe this will have a material impact on its financial statements.

In December 2023, the FASB issued ASU 2023-09 “Improvements to Income Tax Disclosures (Topic 740),” which requires enhanced disclosures primarily related to existing rate reconciliation and income taxes paid information. This update is effective for the Company beginning in the first quarter of 2025 and is applied on a prospective basis. Retrospective application is also permitted. The Company does not believe this will have a material impact on its financial statements.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Assets:
Derivative assets	$ 6	$ 5
Liabilities:
Derivative liabilities	0	50
Commodity derivative instruments \| Recurring
Assets:
Derivative asset, fair value	6	5
Derivative asset, netting	0	0
Derivative assets	6	5
Liabilities:
Derivative liability, fair value		50
Derivative liability, netting		0
Derivative liabilities		50
Commodity derivative instruments \| Recurring \| Quoted Price in Active Markets (Level 1)
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value		0
Commodity derivative instruments \| Recurring \| Significant Other Inputs (Level 2)
Assets:
Derivative asset, fair value	6	5
Liabilities:
Derivative liability, fair value		50
Commodity derivative instruments \| Recurring \| Significant Unobservable Inputs (Level 3)
Assets:
Derivative asset, fair value	$ 0	0
Liabilities:
Derivative liability, fair value		$ 0

Cover - USD ($)	12 Months Ended
Cover - USD ($)	Dec. 31, 2023	Jan. 31, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	1-40144
Entity Registrant Name	APA CORPORATION
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	86-1430562
Entity Address, Address Line One	One Post Oak Central, 2000 Post Oak Boulevard, Suite 100
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77056-4400
City Area Code	713
Local Phone Number	296-6000
Title of 12(b) Security	Common Stock, $0.625 par value
Trading Symbol	APA
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction	false
Entity Shell Company	false
Entity Public Float			$ 10,499,243,068
Entity Common Stock, Shares Outstanding		301,818,820
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement relating to the registrant’s 2024 annual meeting of stockholders are incorporated by reference in Part II and Part III of this Annual Report on Form 10-K.
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Entity Central Index Key	0001841666

RETIREMENT AND DEFERRED COMPENSATION PLANS - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Portion of employee's salary, employee contributions under non-qualified retirement savings plan	50.00%
Maximum percentage of compensation contributed by the company	8.00%
Percentage of additional contribution to money purchase retirement plan	6.00%
Maximum percentage of eligible compensation contributed by the participating employees	50.00%
Portion of employee's annual bonus, employee contributions under non-qualified retirement savings plan, vested	75.00%
Portion occurring as money purchase retirement plan and the non-qualified retirement/savings plan, vested	20.00%
Annual cost of retirement benefit plans	$ 44	$ 40	$ 31
Targeted ongoing funding level of pension plan policy, percent	100.00%
Outperformance relative to gilts for equities	3.50%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation for pension plans	$ 112	$ 89	$ 205
Expected contribution towards pension and postretirement plan	2
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected contribution towards pension and postretirement plan	$ 2

CAPITAL STOCK (Tables)

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

Schedule of Common Stock Outstanding

The following table provides changes to the Company’s common shares outstanding for the years ended December 31, 2023, 2022, and 2021:


	For the Year Ended December 31,
	2023	2022	2021
Balance, beginning of year	311,559,149	346,930,765	377,482,630
Shares issued for stock-based compensation plans:
Treasury shares issued	2,016	1,996	3,133
Common shares issued	725,914	791,381	649,231
Treasury shares acquired	(8,711,178)	(36,164,993)	(31,204,229)
Balance, end of year	303,575,901	311,559,149	346,930,765

Schedule of Reconciliation of Components of Basic and Diluted Net Income (Loss) Per Common Share

The following table provides a reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2023, 2022, and 2021:


	2023					2022					2021
	Income		Shares	Per Share		Income		Shares	Per Share		Income		Shares	Per Share

	(In millions, except per share amounts)
Basic:


Income attributable to common stock	$	2,855	308	$	9.26	$	3,674	332	$	11.05	$	973	374	$	2.60
Effect of Dilutive Securities:
Stock compensation awards	$	—	1	$	(0.01)	$	—	1	$	(0.03)	$	—	1	$	(0.01)
Diluted:


Income attributable to common stock	$	2,855	309	$	9.25	$	3,674	333	$	11.02	$	973	375	$	2.59

Schedule of Description of Stock Based Compensation Plans and Related Costs

The following table summarizes the Company’s stock-settled and cash-settled compensation costs for the years ended December 31, 2023, 2022, and 2021:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Stock-settled and cash-settled compensation expensed:
Lease operating expenses	$	27	$	82	$	39
Exploration	7		29		10
General and administrative	50		193		108
Total stock-settled and cash-settled compensation expensed	84		304		157
Stock-settled and cash-settled compensation capitalized	13		44		18
Total stock-settled and cash-settled compensation costs	$	97	$	348	$	175

Schedule of Stock Options Activities

The following table summarizes stock option activity for the years ended December 31, 2023, 2022, and 2021:


	2023			2022			2021
	Shares Under Option	Weighted Average Exercise Price		Shares Under Option	Weighted Average Exercise Price		Shares Under Option	Weighted Average Exercise Price

	(In thousands, except exercise price amounts)
Outstanding, beginning of year	2,078	$	57.71	3,012	$	63.79	3,537	$	72.10

Exercised	(12)	42.38		(99)	42.09		—	—
Forfeited	—	—		(2)	49.10		—	—
Expired	(601)	80.53		(833)	81.56		(525)	119.83
Outstanding, end of year(1)	1,465	48.48		2,078	57.71		3,012	63.79
Expected to vest	—	—		—	—		—	—
Exercisable, end of year(1)	1,465	48.48		2,078	57.71		3,012	63.79

(1)As of December 31, 2023, options exercisable and outstanding had a weighted average remaining contractual life of 3.1 years and aggregate intrinsic value of $33,000.

Schedule of Restricted Stock and Restricted Stock Units Activity

The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2023, 2022, and 2021:


	2023			2022			2021
	Units	Weighted Average Grant-Date Fair Value		Units	Weighted Average Grant-Date Fair Value		Units	Weighted Average Grant-Date Fair Value

	(In thousands, except per share amounts)
Non-vested, beginning of year	1,885	$	23.08	2,073	$	19.98	1,552	$	28.43
Granted	661	41.60		847	29.90		1,506	16.46
Vested(3)	(975)	23.31		(978)	22.39		(857)	29.13
Forfeited	(69)	32.44		(57)	23.49		(128)	19.78
Expired	(22)	27.81		—	—		—	—
Non-vested, end of year(1)(2)	1,480	30.69		1,885	23.08		2,073	19.98

(1)As of December 31, 2023, there was $15 million of total unrecognized compensation cost related to 1,479,880 unvested stock-settled restricted stock units.

(2)As of December 31, 2023, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.6 years.

(3)The grant date fair values of the stock-settled awards vested during 2023, 2022, and 2021 were approximately $23 million, $22 million, and $25 million, respectively.

The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2023, 2022, and 2021:


	For the Year Ended December 31,
	2023	2022	2021

	(In thousands)
Non-vested, beginning of year	5,709	6,402	4,423
Adjustment from ALTM transaction(1)	—	143	—
Granted(2)	1,972	2,568	4,441
Vested	(2,851)	(2,970)	(2,049)
Forfeited	(340)	(434)	(413)
Expired	(12)	—	—
Non-vested, end of year(3)	4,478	5,709	6,402

(1)Following the BCP Business Combination, certain employees were granted restricted stock phantom units based on APA’s common stock price to replace the equivalent value in restricted stock phantom units based on ALTM’s common stock price.

(2)Restricted stock phantom units granted during 2023, 2022, and 2021 included 1,972,116, 2,512,602, and 4,375,546 awards, respectively, based on the per-share market price of APA common stock. Restricted stock phantom units granted during 2022 and 2021 included 55,546 and 65,327 awards, respectively, based on the per-share market price of ALTM common stock prior to the deconsolidation of Altus on February 22, 2022.

(3)The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2023 was approximately $54 million.

The following table summarizes cash-settled conditional restricted stock phantom unit activity for the years ended December 31, 2023, 2022, and 2021:


	For the Year Ended December 31,
	2023	2022	2021

	(In thousands)
Non-vested, beginning of year	4,835	4,531	3,417
Granted	1,536	1,676	1,782
Vested	(1,593)	(656)	(76)
Forfeited	(99)	(106)	(240)
Expired	(50)	(610)	(352)
Non-vested, end of year(1)	4,629	4,835	4,531

(1)As of December 31, 2023, the outstanding liability for the unvested cash-settled conditional restricted stock phantom units that had not been recognized was approximately $24 million.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Instruments (Details) - January—June 2024 - Natural Gas MMBTU in Thousands	12 Months Ended
	Dec. 31, 2023 $ / MMBTU MMBTU
Basis Swap Purchased \| NYMEX Henry Hub/IF Waha
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) \| MMBTU	16,380
Weighted average price differential (in USD per MMBtu ) \| $ / MMBTU	(1.15)
Basis Swap Sold \| NYMEX Henry Hub/IF HSC
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) \| MMBTU	16,380
Weighted average price differential (in USD per MMBtu ) \| $ / MMBTU	(0.10)

INCOME TAXES - Schedule of Foreign Tax Credit Carryforward (Details) $ in Millions	Dec. 31, 2023 USD ($)
Foreign
Tax Credit Carryforward [Line Items]
Tax credit carryforward, amount	$ 2,204

OTHER CURRENT LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Payables and Accruals [Abstract]
Accrued operating expenses	$ 162	$ 145
Accrued exploration and development	371	333
Accrued compensation and benefits	390	514
Accrued interest	93	97
Accrued income taxes	138	90
Current asset retirement obligation	76	55
Current operating lease liability	116	167
Current decommissioning contingency for sold Gulf of Mexico properties	60	450
Other	338	292
Total Other current liabilities	$ 1,744	$ 2,143

RETIREMENT AND DEFERRED COMPENSATION PLANS (Tables)

12 Months Ended

Dec. 31, 2023

Retirement Benefits [Abstract]

Schedule of Changes in Benefit Obligation, Fair Value of Plan Assets and Funded Status of Pension and Postretirement Benefit Plans

The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2023, 2022, and 2021, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. The Company uses a measurement date of December 31 for its pension and postretirement benefit plans.


	2023						2022						2021
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits

	(In millions)
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	$	108		$	15		$	211		$	20		$	233		$	20
Service cost	1			1			2			1			3			1
Interest cost	5			1			3			—			3			—
Foreign currency exchange rates	6			—			(21)			—			(2)			—
Actuarial losses (gains)	3			—			(79)			(5)			(5)			1
Plan settlements	—			—			—			—			(17)			—
Benefits paid	(5)			(3)			(8)			(3)			(4)			(4)
Retiree contributions	—			1			—			2			—			2
Projected benefit obligation at end of year	118			15			108			15			211			20
Change in Plan Assets
Fair value of plan assets at beginning of year	137			—			254			—			262			—
Actual return (loss) on plan assets	8			—			(87)			—			11			—
Foreign currency exchange rates	8			—			(26)			—			(3)			—
Employer contributions	2			1			4			2			5			2
Plan settlements	—			—			—			—			(17)			—
Benefits paid	(5)			(3)			(8)			(4)			(4)			(4)
Retiree contributions	—			2			—			2			—			2
Fair value of plan assets at end of year	150			—			137			—			254			—
Funded status at end of year	$	32		$	(15)		$	29		$	(15)		$	43		$	(20)
Amounts recognized in Consolidated Balance Sheet
Current liability	$	—		$	(2)		$	—		$	(2)		$	—		$	(2)
Non-current asset (liability)	32			(13)			29			(13)			43			(18)
	$	32		$	(15)		$	29		$	(15)		$	43		$	(20)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$	(12)		$	16		$	(10)		$	18		$	1		$	14

Weighted Average Assumptions used as of December 31
Discount rate	4.80		%	5.00		%	5.00		%	5.29		%	1.80		%	2.57		%
Salary increases	4.60		%	N/A			4.70		%	N/A			4.90		%	N/A
Expected return on assets	4.80		%	N/A			4.70		%	N/A			1.90		%	N/A
Healthcare cost trend
Initial	N/A			6.25		%	N/A			6.50		%	N/A			6.25		%
Ultimate in 2030	N/A			5.25		%	N/A			5.25		%	N/A			5.00		%

Schedule of Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset

A breakout of allocations for the Company's plan asset holdings are summarized below:


	Percentage of Plan Assets at Year-End
	2023		2022
Asset Category
Global equities	—	%	6	%
Multi-asset credit	59	%	40	%
Nominal bonds	6	%	24	%
Inflation-linked bonds	33	%	28	%
Cash	2	%	2	%
Total	100	%	100	%

Schedule of Fair Values of Plan Assets for Each Major Asset Category Based on Nature and Significant Concentration of Risks in Plan Assets

The following tables present the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets at December 31, 2023 and 2022:


	December 31,
	2023		2022

	(In millions)
Asset Category
Global equities	$	—	$	9
Multi-asset credit	88		55
Nominal bonds	9		32
Inflation-linked bonds	50		39
Cash	3		2
Total	$	150	$	137

Schedule of Components of Net Periodic Cost and Underlying Weighted Average Actuarial Assumptions Used for Pension and Postretirement Benefit Plans

The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31, 2023, 2022, and 2021:


	2023						2022						2021
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits

	(In millions)
Components of Net Periodic Benefit Cost
Service cost	$	1		$	1		$	2		$	1		$	3		$	1
Interest cost	5			1			3			—			3			—
Expected return on assets	(7)			—			(4)			—			(4)			—
Amortization of loss	—			(2)			—			(1)			—			(1)
Settlement loss	—			—			—			—			—			—
Net periodic benefit cost	$	(1)		$	—		$	1		$	—		$	2		$	—
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	5.00		%	5.29		%	1.80		%	2.57		%	1.40		%	2.06		%
Salary increases	4.70		%	N/A			4.90		%	N/A			4.50		%	N/A
Expected return on assets	4.70		%	N/A			1.90		%	N/A			1.50		%	N/A
Healthcare cost trend
Initial	N/A			6.50		%	N/A			6.25		%	N/A			6.00		%
Ultimate in 2030	N/A			5.25		%	N/A			5.00		%	N/A			5.00		%

Schedule of Expected Future Benefit Payment

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:


	Pension Benefits		Postretirement Benefits

	(In millions)
2024	$	5	$	2
2025	5		2
2026	5		1
2027	6		1
2028	6		1
Years 2029-2033	34		6

ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accumulated Other Comprehensive Income (Loss) [Line Items]
Equity	$ 3,691	$ 1,345	$ (717)	$ (645)
Pension and postretirement benefit plan (Note 12)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Equity	15	14	22
AOCI, Parent
Accumulated Other Comprehensive Income (Loss) [Line Items]
Equity	$ 15	$ 14	$ 22	$ 14

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References + Details

- Definition

Amount of equity (deficit) attributable to parent and noncontrolling interest. Excludes temporary equity.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
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-Name Accounting Standards Codification
-Section 45
-Paragraph 24
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-URI https://asc.fasb.org//1943274/2147483421/250-10-45-24

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section 45
-Paragraph 23
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147483421/250-10-45-23

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
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-Section 45
-Paragraph 5
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-URI https://asc.fasb.org//1943274/2147483421/250-10-45-5

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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-Section 65
-Paragraph 5
-Subparagraph (c)(2)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479654/326-10-65-5

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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-Section 65
-Paragraph 6
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480528/815-20-65-6

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 20
-Name Accounting Standards Codification
-Section 65
-Paragraph 6
-Subparagraph (h)(1)
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 20
-Name Accounting Standards Codification
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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-Section 65
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 20
-Name Accounting Standards Codification
-Section 65
-Paragraph 6
-Subparagraph (h)(1)(iv)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480528/815-20-65-6

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 20
-Name Accounting Standards Codification
-Section 65
-Paragraph 6
-Subparagraph (i)(3)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480528/815-20-65-6

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 848
-SubTopic 10
-Name Accounting Standards Codification
-Section 65
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+ Details

ASSET RETIREMENT OBLIGATION - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Additional abandonment liabilities associated with its drilling and development program	$ 14	$ 4
Revisions in estimated liabilities	$ 356	$ (148)

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Principal Sources of Change In Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Extractive Industries [Abstract]
Sales, net of production costs	$ (5,408)	$ (7,131)	$ (4,707)
Net change in prices and production costs	(7,089)	8,690	9,376
Discoveries and improved recovery, net of related costs	1,869	1,142	1,749
Change in future development costs	(413)	(343)	(839)
Previously estimated development costs incurred during the period	825	669	545
Revision of quantities	(262)	2,646	1,983
Purchases of minerals in-place	1	911	1
Accretion of discount	2,260	1,489	626
Change in income taxes	1,467	(2,467)	(1,583)
Sales of minerals in-place	(18)	(363)	(116)
Change in production rates and other	(793)	(1)	13
Change in the discounted future net cash flows, Total	$ (7,561)	$ 5,242	$ 7,048

CAPITALIZED EXPLORATORY WELL COSTS

12 Months Ended

Dec. 31, 2023

Extractive Industries [Abstract]

CAPITALIZED EXPLORATORY WELL COSTS

The following summarizes the changes in capitalized exploratory well costs for the years ended December 31, 2023, 2022, and 2021. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Capitalized well costs at beginning of year	$	474	$	321	$	197
Additions pending determination of proved reserves	265		287		174

Reclassifications to proved properties	(135)		(110)		(40)
Charged to exploration expense	(18)		(24)		(10)
Capitalized well costs at end of year	$	586	$	474	$	321

The following provides an aging of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling as of December 31:


	2023		2022		2021

	(In millions)
Exploratory well costs capitalized for a period of one year or less	$	156	$	215	$	198
Exploratory well costs capitalized for a period greater than one year	430		259		123
Capitalized well costs at end of year	$	586	$	474	$	321

Number of projects with exploratory well costs capitalized for a period greater than one year	33		21		13

Projects with exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether reserves can be attributed to these projects. Exploratory well costs capitalized for a period greater than one year since completion of drilling were $430 million at December 31, 2023, with $421 million related to Suriname exploration and appraisal. Detailed engineering and feasibility studies are underway in Block 58 offshore Suriname, and a final investment decision is expected near the end of 2024. In addition, ongoing analysis of well results and appraisal activity is continuing. The remaining projects pertain to onshore drilling activity in Egypt for which continued testing and evaluation is ongoing.

Dry hole expenses from suspended exploratory well costs previously capitalized for greater than one year at December 31, 2022 totaled $16 million. These expenses pertained to projects in the North Sea and Egypt.

The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2023, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed:


	Total		2022		2021		2020 and Prior

	(In millions)
Suriname	$	421	$	178	$	153	$	90
Egypt	9		—		—		9

	$	430	$	178	$	153	$	99

DEBT AND FINANCING COSTS - Unsecured 2022 Committed Bank Credit Facilities (Details)		12 Months Ended
	Apr. 29, 2022 USD ($) credit_agreement option	Dec. 31, 2022 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2023 GBP (£)	Dec. 31, 2022 GBP (£)	Apr. 29, 2022 GBP (£) credit_agreement
USD Agreement \| Line of Credit
Debt Instrument [Line Items]
Debt instrument, term	5 years
Line of credit facility, committed amount	$ 1,800,000,000
Increase of committed amount	$ 2,300,000,000
Line of credit facility, number of extension options \| option	2
Line of credit facility, extension term	1 year
Line of credit outstanding		$ 566,000,000	$ 372,000,000
USD Agreement \| Line of Credit \| Apache Corp
Debt Instrument [Line Items]
Line of credit facility maximum borrowing capacity	$ 300,000,000
USD Agreement \| Letter of Credit \| Line of Credit
Debt Instrument [Line Items]
Line of credit facility maximum borrowing capacity	750,000,000
Current borrowing capacity	$ 150,000,000
Letters of credit outstanding, amount		$ 20,000,000	$ 0
GBP Agreement \| Line of Credit
Debt Instrument [Line Items]
Debt instrument, term	5 years
Line of credit facility, committed amount \| £						£ 1,500,000,000
Line of credit facility, number of extension options \| option	2
Line of credit facility, extension term	1 year
GBP Agreement \| Letter of Credit \| Line of Credit
Debt Instrument [Line Items]
Letters of credit outstanding, amount \| £				£ 348,000,000	£ 652,000,000
Syndicated credit facility \| Line of Credit \| Apache Corp
Debt Instrument [Line Items]
Covenant term, benchmark amount	$ 1,000,000,000
Syndicated credit facility \| Unsecured Debt
Debt Instrument [Line Items]
Number of credit agreements \| credit_agreement	2					2
Syndicated credit facility \| Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility fee, percentage		0.225%
Debt covenant, adjusted debt-to-capital ratio	0.60					0.60
Debt-to-capital ratio			0.20	0.20
Debt covenant, debt secured as percentage of consolidated net tangible assets			15.00%	15.00%
Debt covenant, debt secured as percentage of consolidated net tangible assets, threshold amount			$ 1,900,000,000
Syndicated credit facility \| Revolving Credit Facility \| Line of Credit
Debt Instrument [Line Items]
Line of credit outstanding		$ 566,000,000	$ 372,000,000
Syndicated credit facility \| Base Rate \| Revolving Credit Facility
Debt Instrument [Line Items]
Debt basis spread on variable rate		0.40%
Syndicated credit facility \| SOFR \| Revolving Credit Facility
Debt Instrument [Line Items]
Debt basis spread on variable rate		1.40%
Former Facility \| Line of Credit \| Apache Corp
Debt Instrument [Line Items]
Commitment amount terminated	$ 4,000,000,000
Minimum \| USD Agreement \| Base Rate
Debt Instrument [Line Items]
Debt basis spread on variable rate	0.10%
Minimum \| USD Agreement \| SOFR
Debt Instrument [Line Items]
Debt basis spread on variable rate	1.10%
Maximum \| USD Agreement \| Base Rate
Debt Instrument [Line Items]
Debt basis spread on variable rate	0.675%
Maximum \| USD Agreement \| SOFR
Debt Instrument [Line Items]
Debt basis spread on variable rate	1.675%

EQUITY METHOD INTERESTS

12 Months Ended

Dec. 31, 2023

Equity Method Investments and Joint Ventures [Abstract]

EQUITY METHOD INTERESTS

As of December 31, 2023 and 2022, the Company recorded $437 million and $624 million, respectively, for ownership of its Kinetik Shares. The Company’s Kinetik Shares are treated as an interest in equity securities measured at fair value. The Company elected the fair value option for measuring its equity method interest in Kinetik based on practical expedience, variances in reporting timelines, and cost-benefit considerations. The fair value of the Company’s interest in Kinetik is determined using observable share prices on a major exchange, a Level 1 fair value measurement. Fair value adjustments are recorded as a component of “Other, net” under “Revenues and other” in the Company’s statement of consolidated operations.

The Company’s initial interest in Kinetik was measured at fair value based on the Company’s ownership of approximately 12.9 million Kinetik Shares as of February 22, 2022. In March 2022, the Company sold four million of its Kinetik Shares for cash proceeds of $224 million. Refer to Note 2 —Acquisitions and Divestitures for further detail. During the second quarter of 2022, Kinetik issued a two-for-one split of its common stock, resulting in the Company owning approximately 17.7 million Kinetik Shares. In December 2023, the Company sold 7.5 million of its Kinetik Shares for cash proceeds of $228 million.

The Company has received approximately 2.9 million Kinetik Shares as paid-in-kind dividends through December 31, 2023. As of December 31, 2023, the Company owned 13.1 million Kinetik Shares, representing approximately 9 percent of Kinetik’s outstanding common stock.

The Company recorded changes in the fair value of its equity method interest in Kinetik totaling gains of $41 million and $72 million during 2023 and 2022, respectively. The balance of the Company’s equity method interest in Kinetik was also impacted by the sales of Kinetik Shares noted above during 2023 and 2022.

The following table represents related party sales and costs associated with Kinetik:


	For the Year Ended December 31,
	2023		2022

	(In millions)
Natural gas and NGLs sales	$	92	$	18
Purchased oil and gas sales	29		—
	$	121	$	18

Gathering, processing, and transmission costs	$	108	$	93
Purchased oil and gas costs	80		—
Lease operating expenses	7		—
	$	195	$	93

As of December 31, 2023 and 2022, the Company has recorded accrued costs payable to Kinetik of approximately $28 million and $18 million, respectively, and accrued receivables from Kinetik of approximately $16 million and $13 million, respectively.

NATURE OF OPERATIONS	12 Months Ended
NATURE OF OPERATIONS	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of operations	Nature of Operations APA Corporation (APA or the Company) is an independent energy company that owns consolidated subsidiaries that explore for, develop, and produce natural gas, crude oil, and natural gas liquids. The Company’s upstream business has oil and gas operations in three geographic areas: the United States (U.S.), Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active exploration and appraisal operations ongoing in Suriname, as well as interests in Uruguay and other international locations that may, over time, result in reportable discoveries and development opportunities. Prior to the BCP Business Combination defined below, the Company’s midstream business was operated by Altus Midstream Company (ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). On March 1, 2021, Apache Corporation, the Company’s predecessor registrant, consummated a holding company reorganization (the Holding Company Reorganization), pursuant to which Apache Corporation became a direct, wholly owned subsidiary of APA Corporation, and all of Apache Corporation’s outstanding shares automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to Apache Corporation pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache Corporation as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized the Company’s operating and legal structure to more closely align with its growing international presence, making it more consistent with other companies that have subsidiaries operating around the globe. As a holding company, APA Corporation’s primary assets are its ownership interests in its subsidiaries.

REDEMABLE NONCONTROLLING INTEREST - ALTUS

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

REDEMABLE NONCONTROLLING INTEREST - ALTUS

REDEEMABLE NONCONTROLLING INTEREST — ALTUS

Preferred Units Issuance

On June 12, 2019, Altus Midstream LP issued and sold Preferred Units for an aggregate issue price of $625 million in a private offering exempt from the registration requirements of the Securities Act. Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers.

Classification

Prior to the deconsolidation of Altus on February 22, 2022, at December 31, 2021, the carrying amount of the Preferred Units was recorded as “Redeemable Noncontrolling Interest — Altus Preferred Unit Limited Partners” and classified as temporary equity on the Company’s consolidated balance sheet based on the terms of the Preferred Units, including the redemption rights with respect thereto.

Measurement

Altus applied a two-step approach to subsequent measurement of the redeemable noncontrolling interest related to the Preferred Units by first allocating a portion of the net income of Altus Midstream LP in accordance with the terms of the partnership agreement. An additional adjustment to the carrying value of the Preferred Unit redeemable noncontrolling interest at each period end was recorded, if applicable. The amount of such adjustment was determined based upon the accreted value method to reflect the passage of time until the Preferred Units were exchangeable at the option of the holder. Accordingly, prior to the deconsolidation of Altus on February 22, 2022, the Company recorded a net loss attributable to Altus Preferred Unit limited partners totaling $70 million and net income attributable to Altus Preferred Unit limited partners totaling $162 million during 2022 and 2021, respectivelyCAPITAL STOCK

Common Stock Outstanding

The following table provides changes to the Company’s common shares outstanding for the years ended December 31, 2023, 2022, and 2021:


	For the Year Ended December 31,
	2023	2022	2021
Balance, beginning of year	311,559,149	346,930,765	377,482,630
Shares issued for stock-based compensation plans:
Treasury shares issued	2,016	1,996	3,133
Common shares issued	725,914	791,381	649,231
Treasury shares acquired	(8,711,178)	(36,164,993)	(31,204,229)
Balance, end of year	303,575,901	311,559,149	346,930,765

Net Income per Common Share

The following table provides a reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2023, 2022, and 2021:


	2023					2022					2021
	Income		Shares	Per Share		Income		Shares	Per Share		Income		Shares	Per Share

	(In millions, except per share amounts)
Basic:


Income attributable to common stock	$	2,855	308	$	9.26	$	3,674	332	$	11.05	$	973	374	$	2.60
Effect of Dilutive Securities:
Stock compensation awards	$	—	1	$	(0.01)	$	—	1	$	(0.03)	$	—	1	$	(0.01)
Diluted:


Income attributable to common stock	$	2,855	309	$	9.25	$	3,674	333	$	11.02	$	973	375	$	2.59

The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 1.9 million, 2.4 million, and 3.3 million for the years ended December 31, 2023, 2022, and 2021, respectively.

Stock Repurchase Program

During 2018, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. During the fourth quarter of 2021, the Company’s Board of Directors authorized the purchase of an additional 40 million shares of the Company’s common stock. During the third quarter of 2022, the Company's Board of Directors further authorized the purchase of an additional 40 million shares of the Company's common stock.

During 2023, the Company repurchased 8.7 million shares at an average price of $37.81 per share, and as of December 31, 2023, the Company had remaining authorization to repurchase 43.9 million shares. During 2022, the Company repurchased 36.2 million shares at an average price of $39.34 per share. During 2021, the Company repurchased 31.2 million shares at an average price of $27.14 per share.

Subsequent to year-end 2023 and through the date of this filing on February 22, 2024, the Company repurchased 3.0 million shares at an average price of $33.27 per share. As of February 22, 2024, the Company had remaining authorization to repurchase up to 40.9 million shares.

The Company is not obligated to acquire any additional shares. Shares may be purchased either in the open market or through privately held negotiated transactions.

Common Stock Dividend

The Company’s Board of Directors approved an increase in APA’s quarterly dividend from $0.025 per share to $0.0625 per share in the third quarter of 2021 and approved a further increase to $0.125 per share in the fourth quarter of 2021. During the third quarter of 2022, the Company’s Board of Directors approved another increase to its quarterly dividend to $0.25 per share, representing a return to pre-Covid-19 dividend levels. For the years ended December 31, 2023, 2022, and 2021, the Company declared common stock dividends totaling $1.00 per share, $0.75 per share, and $0.2375 per share, respectively.

Stock Compensation Plans

The Company maintains several stock-based compensation plans, which include stock options, restricted stock, and conditional restricted stock unit plans. In 2021, pursuant to the Holding Company Reorganization, Apache’s outstanding common shares were converted into equivalent corresponding shares of APA. APA assumed sponsorship of all stock compensation plans. All cash-settled awards previously indexed to Apache’s stock price were subsequently indexed to APA’s stock price, and all unvested stock-settled awards will be settled in APA stock upon vesting.

On May 12, 2016, the Company’s shareholders approved the 2016 Omnibus Compensation Plan (the 2016 Plan), which is used to provide eligible employees with equity-based incentives by granting incentive stock options, non-qualified stock options, performance awards, restricted stock awards, restricted stock units, stock appreciation rights, cash awards, or any combination of the foregoing. As of December 31, 2023, 9.4 million shares were authorized and available for grant under the 2016 Plan. Previously approved plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2016 Plan. All new grants are issued from the 2016 Plan. In 2018, the Company began issuing cash-settled awards (phantom units) under the restricted stock and conditional restricted stock unit plans. The phantom units represent a hypothetical interest in the Company’s stock and, once vested, are settled in cash.

Costs related to the plans are capitalized or expensed to “Lease operating expenses,” “Exploration,” or “General and administrative” in the Company’s statement of consolidated operations based on the nature of each employee’s activities. The following table summarizes the Company’s stock-settled and cash-settled compensation costs for the years ended December 31, 2023, 2022, and 2021:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Stock-settled and cash-settled compensation expensed:
Lease operating expenses	$	27	$	82	$	39
Exploration	7		29		10
General and administrative	50		193		108
Total stock-settled and cash-settled compensation expensed	84		304		157
Stock-settled and cash-settled compensation capitalized	13		44		18
Total stock-settled and cash-settled compensation costs	$	97	$	348	$	175

Stock Options

As of December 31, 2023, the Company had outstanding options to purchase shares of its common stock under the 2016 Plan and the 2011 Omnibus Equity Compensation Plan (the 2011 Plan and, with the 2016 Plan, the Omnibus Plans). The Omnibus Plans were submitted to and approved by the Company’s shareholders. New shares of common stock will be issued for employee stock option exercises. Under the Omnibus Plans, the exercise price of each option equals the closing price of APA’s common stock on the date of grant. Options granted become exercisable ratably over a three-year period and expire 10 years after granted.

The following table summarizes stock option activity for the years ended December 31, 2023, 2022, and 2021:


	2023			2022			2021
	Shares Under Option	Weighted Average Exercise Price		Shares Under Option	Weighted Average Exercise Price		Shares Under Option	Weighted Average Exercise Price

	(In thousands, except exercise price amounts)
Outstanding, beginning of year	2,078	$	57.71	3,012	$	63.79	3,537	$	72.10

Exercised	(12)	42.38		(99)	42.09		—	—
Forfeited	—	—		(2)	49.10		—	—
Expired	(601)	80.53		(833)	81.56		(525)	119.83
Outstanding, end of year(1)	1,465	48.48		2,078	57.71		3,012	63.79
Expected to vest	—	—		—	—		—	—
Exercisable, end of year(1)	1,465	48.48		2,078	57.71		3,012	63.79

(1)As of December 31, 2023, options exercisable and outstanding had a weighted average remaining contractual life of 3.1 years and aggregate intrinsic value of $33,000.

During the years ended December 31, 2023, 2022, and 2021, there were no options issued and 12,183, 98,646, and no options, respectively, exercised.

Restricted Stock Units and Restricted Stock Phantom Units

The Company has restricted stock unit and restricted stock phantom unit plans for eligible employees, including officers. The value of the stock-settled restricted stock unit awards is established by the market price on the date of grant and is recorded as compensation expense ratably over the vesting terms. The restricted stock phantom unit awards represent a hypothetical interest in either the Company’s common stock or, prior to the BCP Business Combination, in ALTM’s common stock, as applicable, and, once vested, are settled in cash. Compensation expense related to the cash-settled awards is recorded as a liability and remeasured at the end of each reporting period over the applicable vesting term.

For the years ended December 31, 2023, 2022, and 2021, compensation costs charged to expense for the restricted stock units and restricted stock phantom units was $73 million, $153 million, and $95 million, respectively. As of December 31, 2023, 2022, and 2021, capitalized compensation costs for the restricted stock units and restricted stock phantom units were $11 million, $22 million, and $15 million, respectively.

The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2023, 2022, and 2021:


	2023			2022			2021
	Units	Weighted Average Grant-Date Fair Value		Units	Weighted Average Grant-Date Fair Value		Units	Weighted Average Grant-Date Fair Value

	(In thousands, except per share amounts)
Non-vested, beginning of year	1,885	$	23.08	2,073	$	19.98	1,552	$	28.43
Granted	661	41.60		847	29.90		1,506	16.46
Vested(3)	(975)	23.31		(978)	22.39		(857)	29.13
Forfeited	(69)	32.44		(57)	23.49		(128)	19.78
Expired	(22)	27.81		—	—		—	—
Non-vested, end of year(1)(2)	1,480	30.69		1,885	23.08		2,073	19.98

(1)As of December 31, 2023, there was $15 million of total unrecognized compensation cost related to 1,479,880 unvested stock-settled restricted stock units.

(2)As of December 31, 2023, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.6 years.

(3)The grant date fair values of the stock-settled awards vested during 2023, 2022, and 2021 were approximately $23 million, $22 million, and $25 million, respectively.

The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2023, 2022, and 2021:


	For the Year Ended December 31,
	2023	2022	2021

	(In thousands)
Non-vested, beginning of year	5,709	6,402	4,423
Adjustment from ALTM transaction(1)	—	143	—
Granted(2)	1,972	2,568	4,441
Vested	(2,851)	(2,970)	(2,049)
Forfeited	(340)	(434)	(413)
Expired	(12)	—	—
Non-vested, end of year(3)	4,478	5,709	6,402

(3)The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2023 was approximately $54 million.

In January 2024, the Company awarded 819,836 restricted stock units and 2,356,255 restricted stock phantom units based on APA’s weighted-average per-share market price of $33.73 under the 2016 Plan to eligible employees. Total compensation cost for the restricted stock units and the restricted stock phantom units, absent any forfeitures, is estimated to be $28 million and $80 million, respectively, and was calculated based on the per-share fair market value of a share of the Company’s common stock as of the grant date. Compensation cost will be recognized over a three-year vesting period for both plans. The restricted stock phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of the Company’s common stock, a Level 1 fair value measurement.

Performance Program

To provide long-term incentives for the Company’s employees to deliver competitive shareholder returns, the Company makes annual grants of cash-settled conditional restricted stock phantom units to eligible employees. APA has a performance program for certain eligible employees with payout for a portion of the shares based upon measurement of total shareholder return (TSR) of APA common stock as compared to a designated peer group during a three-year performance period. Payout for the remaining portion of the shares is based on performance and financial objectives as defined in the plan. The overall results of the objectives are calculated at the end of the award’s stated performance period and, if a payout is warranted, applied to the target number of restricted stock units awarded. The performance shares will immediately vest 50 percent at the end of the three-year performance period, with the remaining 50 percent vesting at the end of the following year. Grants from the performance programs outstanding at December 31, 2023, are as described below:

•In January 2020, the Company’s Board of Directors approved the 2020 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,687,307 units. A total of 999,896 phantom units were outstanding as of December 31, 2023. The results for the performance period yielded a payout of 155 percent of target.

•In January 2021, the Company’s Board of Directors approved the 2021 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,959,856 units. A total of 1,803,083 phantom units were outstanding as of December 31, 2023. The results for the performance period yielded a payout of 118 percent of target.

•In January 2022, the Company’s Board of Directors approved the 2022 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,093,034 units. The actual number of phantom units awarded will be between zero and 200 percent of target. A total of 1,040,100 phantom units were outstanding as of December 31, 2023, from which a minimum of zero to a maximum of 2,080,200 units could be awarded.

•In January 2023, the Company’s Board of Directors approved the 2023 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 822,200 units. The actual number of phantom units awarded will be between zero and 200 percent of target. A total of 784,977 phantom units were outstanding as of December 31, 2023, from which a minimum of zero to a maximum of 1,569,954 units could be awarded.

Compensation expense related to the conditional cash-settled awards is recorded as a liability and remeasured at the end of each reporting period over the applicable vesting term. Compensation costs charged to expense under the cash-settled performance programs were expenses of $2 million, $143 million, and $57 million during 2023, 2022, and 2021, respectively. Capitalized compensation costs under the cash-settled performance programs were expenses of approximately $100 thousand, $21 million, and $3 million during 2023, 2022, and 2021, respectively.

The following table summarizes cash-settled conditional restricted stock phantom unit activity for the years ended December 31, 2023, 2022, and 2021:


	For the Year Ended December 31,
	2023	2022	2021

	(In thousands)
Non-vested, beginning of year	4,835	4,531	3,417
Granted	1,536	1,676	1,782
Vested	(1,593)	(656)	(76)
Forfeited	(99)	(106)	(240)
Expired	(50)	(610)	(352)
Non-vested, end of year(1)	4,629	4,835	4,531

(1)As of December 31, 2023, the outstanding liability for the unvested cash-settled conditional restricted stock phantom units that had not been recognized was approximately $24 million.

In January 2024, the Company’s Board of Directors approved the 2024 Performance Program, pursuant to the 2016 Plan. A portion of the award is based upon measurement of TSR similar to prior year awards, and the remaining portion of the award is based on performance and financial objectives as defined in the 2024 Performance Program. Eligible employees received conditional phantom units and cash incentives. The conditional phantom units totaled 644,399 units, with the ultimate units to be awarded ranging from zero to a maximum of 1,288,798 units. These phantom units represent a hypothetical interest in the Company’s common stock, and, once vested, are settled in cash. These phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of the Company’s common stock, a Level 1 fair value measurement. The cash incentives totaled $14 million, with the ultimate payout ranging from zero to $28 million. Final payout of the awards will be determined at the end of a three-year performance period.

- Definition

The entire disclosure for equity.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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-Name Accounting Standards Codification
-Section 50
-Paragraph 13
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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-Paragraph 14
-Subparagraph (b)
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-URI https://asc.fasb.org//1943274/2147481112/505-10-50-14

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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-Paragraph 2
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481062/946-235-50-2

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481062/946-235-50-2

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 505
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481004/946-505-50-6

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
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-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480237/815-40-50-6

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480008/505-10-S99-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(e)(1))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480678/235-10-S99-1

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 505
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org//505/tableOfContent

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481112/505-10-50-13

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481112/505-10-50-13

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (i)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481112/505-10-50-13

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 14
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481112/505-10-50-14

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
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-URI https://asc.fasb.org//1943274/2147481112/505-10-50-14

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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-Name Accounting Standards Codification
-Section 50
-Paragraph 18
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481112/505-10-50-18

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481112/505-10-50-18

+ Details

COMMITMENTS AND CONTINGENCIES - Additional Information (Details) $ in Millions							12 Months Ended
	Sep. 10, 2020 defendant	Sep. 11, 2019 USD ($) plaintiff	Dec. 20, 2017 action	Jul. 17, 2017 action defendant	Mar. 21, 2016 USD ($)	Mar. 20, 2016 USD ($)	Dec. 31, 2023 USD ($) bond contract	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2013 USD ($) netProfitInterest	Jun. 21, 2023 surety	Apr. 05, 2022 letter	Dec. 31, 2017 AUD ($)	Apr. 30, 2017 AUD ($)	Mar. 12, 2014 USD ($)
Commitment And Contingencies [Line Items]
Accrued liability for legal contingencies							$ 83,000,000
Environmental tax and royalty obligations															$ 100,000,000
Retain right of obligations							45,000,000
Maximum cost considered to be recognized for additional reserve							300,000
Undiscounted reserve for environmental remediation							5,000,000
Number of prior letters notifying unable to fund decommissioning obligations \| letter												2
Decommissioning costs incurred							819,000,000
Decommissioning costs reimbursed amount from trust							293,000,000
Decommissioning costs reimbursed amount from the letters of credit							336,000,000
Standby loan agreed to provide related to ARO							400,000,000
Decommissioning contingency for sold							824,000,000
Decommissioning contingency for sold properties							764,000,000	$ 738,000,000
Current decommissioning contingency for sold Gulf of Mexico properties							60,000,000	450,000,000
Decommissioning security for sold properties							199,000,000
Decommissioning security for sold Gulf of Mexico properties (Note 11)							21,000,000	217,000,000
Current decommissioning security for sold Gulf of Mexico assets							178,000,000	450,000,000
Losses on previously sold Gulf of Mexico properties							212,000,000	157,000,000	$ 446,000,000
Sureties issued bonds directly \| surety											2
Sureties issued bonds to issuing bank \| surety											2
Fixed operating lease expenses							168,000,000	145,000,000	128,000,000
Short-term lease expense							$ 71,000,000	$ 62,000,000	20,000,000
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]							Current debt	Current debt
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]							LONG-TERM DEBT (Note 9)	LONG-TERM DEBT (Note 9)
Depreciation on finance lease asset							$ 2,000,000	$ 2,000,000	2,000,000
Interest on finance lease asset							1,000,000	2,000,000	2,000,000
Variable lease payment							$ 74,000,000	$ 90,000,000	$ 64,000,000
Gulf Of Mexico Shelf Operations And Properties \| Disposed of by Sale
Commitment And Contingencies [Line Items]
Proceeds from sale of operations and properties										$ 3,750,000,000
Trust account for disposal group, number of net profits interests \| netProfitInterest										2
Number of bonds held \| bond							2
Number of debt instruments held \| contract							5
Minimum
Commitment And Contingencies [Line Items]
AROs, estimated liability							$ 824,000,000
Maximum
Commitment And Contingencies [Line Items]
AROs, estimated liability							1,200,000,000
Apollo Exploration Lawsuit
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages					$ 200,000,000
Apollo Exploration Lawsuit \| Minimum
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages						$ 1,100,000,000
Australian Operations Divestiture Dispute \| Apache Australia Operation
Commitment And Contingencies [Line Items]
Gain contingency, unrecorded amount														$ 80
Loss contingency estimate of possible loss													$ 200
Canadian Operations Divestiture Dispute
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages		$ 60,000,000
Number of plaintiffs \| plaintiff		4
Litigation settlement, payment to resolve all claims							$ 7,000,000
California Litigation
Commitment And Contingencies [Line Items]
Number of actions filed \| action			2	3
Number of defendants \| defendant				30
Delaware Litigation
Commitment And Contingencies [Line Items]
Number of defendants \| defendant	25

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	$ 37,099	$ 54,543	$ 39,021
Production costs	(12,791)	(16,090)	(12,378)
Development costs	(5,934)	(5,501)	(5,567)
Income tax expense	(4,117)	(6,935)	(2,789)
Net cash flows	14,257	26,017	18,287
10 percent discount rate	(4,216)	(8,415)	(5,927)
Discounted future net cash flows	$ 10,041	17,602	12,360
Estimated future net cash flow before income tax expenses	10.00%
Total estimated future net cash flows before income tax expense discounted at 10 percent per annum	$ 13,600	22,600	14,900
United States
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	21,417	31,577	22,852
Production costs	(8,328)	(10,763)	(8,323)
Development costs	(2,238)	(1,733)	(1,632)
Income tax expense	(949)	(1,575)	(134)
Net cash flows	9,902	17,506	12,763
10 percent discount rate	(3,749)	(6,811)	(5,294)
Discounted future net cash flows	6,153	10,695	7,469
EGYPT
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	9,921	12,819	9,337
Production costs	(1,690)	(2,086)	(1,712)
Development costs	(1,235)	(1,471)	(1,402)
Income tax expense	(2,222)	(2,729)	(1,887)
Net cash flows	4,774	6,533	4,336
10 percent discount rate	(943)	(1,400)	(983)
Discounted future net cash flows	3,831	5,133	3,353
EGYPT \| Noncontrolling Interests
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Discounted future net cash flows	1,300	1,700	1,100
North Sea
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	5,761	10,147	6,832
Production costs	(2,773)	(3,241)	(2,343)
Development costs	(2,461)	(2,297)	(2,533)
Income tax expense	(946)	(2,631)	(768)
Net cash flows	(419)	1,978	1,188
10 percent discount rate	476	(204)	350
Discounted future net cash flows	$ 57	$ 1,774	$ 1,538

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Reserve Quantities [Line Items]
Proved properties	$ 44,007	$ 41,597
Unproved properties	853	759
Capitalized costs, gross	44,860	42,356
Accumulated DD&A	(35,114)	(33,632)
Capitalized costs, net	9,746	8,724
United States
Reserve Quantities [Line Items]
Proved properties	20,758	19,638
Unproved properties	267	247
Capitalized costs, gross	21,025	19,885
Accumulated DD&A	(15,587)	(14,902)
Capitalized costs, net	5,438	4,983
EGYPT
Reserve Quantities [Line Items]
Proved properties	13,777	13,014
Unproved properties	71	77
Capitalized costs, gross	13,848	13,091
Accumulated DD&A	(11,678)	(11,157)
Capitalized costs, net	2,170	1,934
North Sea
Reserve Quantities [Line Items]
Proved properties	9,472	8,945
Unproved properties	3	11
Capitalized costs, gross	9,475	8,956
Accumulated DD&A	(7,849)	(7,573)
Capitalized costs, net	1,626	1,383
Other International
Reserve Quantities [Line Items]
Proved properties	0	0
Unproved properties	512	424
Capitalized costs, gross	512	424
Accumulated DD&A	0	0
Capitalized costs, net	$ 512	$ 424

CAPITALIZED EXPLORATORY WELL COSTS - Aging of Suspended Well Balances (Details) $ in Millions	Dec. 31, 2023 USD ($) Project	Dec. 31, 2022 USD ($) Project	Dec. 31, 2021 USD ($) Project	Dec. 31, 2020 USD ($)
Extractive Industries [Abstract]
Exploratory well costs capitalized for a period of one year or less	$ 156	$ 215	$ 198
Exploratory well costs capitalized for a period greater than one year	430	259	123
Capitalized exploratory well costs	$ 586	$ 474	$ 321	$ 197
Number of projects with exploratory well costs capitalized for a period greater than one year \| Project	33	21	13

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Schedule of Net Income Before Income Taxes

Net income before income taxes was composed of the following:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
U.S.	$	627	$	2,675	$	629
Foreign	2,256		3,059		1,262
Total	$	2,883	$	5,734	$	1,891

Schedule of Total Provision for Income Taxes

The total income tax provision (benefit) consisted of the following:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Current income taxes:
Federal	$	2	$	1	$	16
State	6		11		—
Foreign	1,330		1,495		636
	1,338		1,507		652
Deferred income taxes:
Federal	(1,708)		—		—
State	(32)		—		—
Foreign	78		145		(74)
	(1,662)		145		(74)
Total	$	(324)	$	1,652	$	578

Schedule of Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense

A reconciliation of the tax on the Company’s net income before income taxes and total income tax provision (benefit) is shown below:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Income tax expense at U.S. statutory rate	$	605	$	1,204	$	397
State income tax, less federal effect(1)	(23)		9		—
Taxes related to foreign operations	752		745		298
Tax credits	—		(4)		(10)






Net change in tax contingencies	5		1		16


Valuation allowances(1)	(1,842)		(646)		(90)
Tax adjustments attributable to BCP Business Combination	—		126		—
Remeasurement of U.K. deferred tax liability	174		208		—
Tax attributable to Altus Preferred Unit limited partners	—		—		(34)
All other, net	5		9		1
	$	(324)	$	1,652	$	578

(1)The change in state valuation allowance is included as a component of state income tax.

Schedule of Net Deferred Tax (Asset) Liability

The net deferred income tax (asset) liability consisted of the following as of December 31:


	2023		2022

	(In millions)
Deferred tax assets:

U.S. and state net operating losses	$	2,050	$	2,029
Capital losses	8		357
Foreign net operating losses	43		27
Tax credits and other tax incentives	26		26
Foreign tax credits	2,204		2,241
Accrued expenses and liabilities	129		156
Asset retirement obligation	850		672
Property and equipment	38		44
Equity investments	8		—
Net interest expense limitation	125		74
Lease liability	71		114
Decommissioning contingency for sold Gulf of Mexico properties	210		275

Total deferred tax assets	5,762		6,015
Valuation allowance	(2,630)		(4,918)
Net deferred tax assets	3,132		1,097
Deferred tax liabilities:


Equity investments	—		1
Property and equipment	1,573		1,023
Right-of-use asset	69		110
Decommissioning security for sold Gulf of Mexico properties	44		148
Other	59		90
Total deferred tax liabilities	1,745		1,372
Net deferred income tax (asset) liability	$	(1,387)	$	275

Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows:


	2023		2022

	(In millions)
Assets:
Other assets
Deferred tax asset	$	1,758	$	39
Liabilities:
Deferred credits and other noncurrent liabilities
Deferred tax liability	371		314
Net deferred income tax (asset) liability	$	(1,387)	$	275

Summary of Valuation Allowance

In 2023, 2022, and 2021, the Company’s valuation allowance decreased by $2.3 billion, $1.0 billion, and $89 million, respectively, as detailed in the table below:


	2023		2022		2021

	(In millions)
Balance at beginning of year	$	4,918	$	5,902	$	5,991
State(1)	(63)		(111)		1
U.S.	(2,235)		(706)		(97)
Foreign	10		(167)		7

Balance at end of year	$	2,630	$	4,918	$	5,902

(1)Reported as a component of state income taxes.

Schedule of Net Operating Losses

On December 31, 2023, the Company had net operating losses as follows:

Amount

Expiration

(In millions)

U.S.

8,027

2027 - Indefinite

State

6,553

Various

Foreign

119

2024 - Indefinite

Schedule of Foreign Tax Credit Carryforward

On December 31, 2023, the Company had foreign tax credits as follows:


	Amount		Expiration
	(In millions)
Foreign tax credits	$	2,204	2025-2026

Schedule of Reconciliation of Beginning and Ending Amount of Unrecognized Tax Benefits

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:


	2023		2022		2021

	(In millions)
Balance at beginning of year	$	89	$	116	$	93
Additions based on tax positions related to prior year	4		—		16
Additions based on tax positions related to the current year	—		—		7
Reductions for tax positions of prior years	—		(27)		—
Balance at end of year	$	93	$	89	$	116

Schedule of Key Jurisdictions of Company's Earliest Open Tax Years

The Company’s earliest open tax years in its key jurisdictions are as follows:

Jurisdiction


U.S.			2014
Egypt			2005
U.K.			2022

EQUITY METHOD INTERESTS - Additional Information (Details) shares in Millions, $ in Millions		1 Months Ended		3 Months Ended		12 Months Ended
	Mar. 11, 2022 shares	Dec. 31, 2023 USD ($) shares	Mar. 31, 2022 shares	Jun. 30, 2022 shares	Mar. 31, 2022 USD ($) shares	Dec. 31, 2023 USD ($) shares	Dec. 31, 2022 USD ($)	Feb. 22, 2022 USD ($) shares
Schedule of Equity Method Investments [Line Items]
Equity method interests		$ 437				$ 437	$ 624
Shares sold (in shares) \| shares					4.0
Accrued costs payable		658				658	771
Accrued receivables		$ 1,610				$ 1,610	1,466
Kinetik
Schedule of Equity Method Investments [Line Items]
Equity method interests								$ 802
Equity method investment, number of shares (in shares) \| shares		13.1		17.7		13.1		12.9
Shares sold (in shares) \| shares	4.0	7.5	4.0
Aggregate issue price of Preferred Units		$ 228			$ 224
Dividends paid-in-kind (in shares) \| shares						2.9
Interest percentage		9.00%				9.00%
Gain on changes in fair value of equity method interest						$ 41	72
Accrued costs payable		$ 28				28	18
Accrued receivables		$ 16				$ 16	$ 13
Kinetik \| Kinetik
Schedule of Equity Method Investments [Line Items]
Stock split conversion ratio				2

STATEMENT OF CONSOLIDATED CASH FLOWS - USD ($)	12 Months Ended
STATEMENT OF CONSOLIDATED CASH FLOWS - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME INCLUDING NONCONTROLLING INTERESTS	$ 3,207,000,000	$ 4,082,000,000	$ 1,313,000,000
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized derivative instrument losses (gains), net	(51,000,000)	67,000,000	(69,000,000)
Gain on divestitures, net	(8,000,000)	(1,180,000,000)	(67,000,000)
Exploratory dry hole expense and unproved leasehold impairments	114,000,000	207,000,000	97,000,000
Depreciation, depletion, and amortization	1,540,000,000	1,233,000,000	1,360,000,000
Asset retirement obligation accretion	116,000,000	117,000,000	113,000,000
Impairments	61,000,000	0	208,000,000
Provision for (benefit from) deferred income taxes	(1,662,000,000)	145,000,000	(74,000,000)
(Gain) loss from extinguishment of debt	(9,000,000)	67,000,000	104,000,000
Losses on previously sold Gulf of Mexico properties	212,000,000	157,000,000	446,000,000
Other	26,000,000	(73,000,000)	28,000,000
Changes in operating assets and liabilities:
Receivables	(157,000,000)	(93,000,000)	(386,000,000)
Inventories	13,000,000	(1,000,000)	(9,000,000)
Drilling advances and other current assets	269,000,000	(15,000,000)	71,000,000
Deferred charges and other long-term assets	270,000,000	69,000,000	(42,000,000)
Accounts payable	(84,000,000)	(4,000,000)	245,000,000
Accrued expenses	(400,000,000)	303,000,000	127,000,000
Deferred credits and noncurrent liabilities	(328,000,000)	(138,000,000)	31,000,000
NET CASH PROVIDED BY OPERATING ACTIVITIES	3,129,000,000	4,943,000,000	3,496,000,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas property	(2,313,000,000)	(1,770,000,000)	(1,101,000,000)
Acquisition of Delaware Basin properties	(24,000,000)	(591,000,000)	0
Leasehold and property acquisitions	(20,000,000)	(37,000,000)	(9,000,000)
Proceeds from asset divestitures	29,000,000	778,000,000	256,000,000
Proceeds from sale of Kinetik shares	228,000,000	224,000,000	0
Deconsolidation of Altus cash and cash equivalents	0	(143,000,000)	0
Other, net	(38,000,000)	28,000,000	21,000,000
NET CASH USED IN INVESTING ACTIVITIES	(2,138,000,000)	(1,511,000,000)	(833,000,000)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from (repayments of) lines of credit	(194,000,000)	24,000,000	392,000,000
Payments on Apache fixed-rate debt	(65,000,000)	(1,493,000,000)	(1,795,000,000)
Distributions to noncontrolling interest – Egypt	(238,000,000)	(362,000,000)	(279,000,000)
Dividends paid to APA common stockholders	(308,000,000)	(207,000,000)	(52,000,000)
Treasury stock activity, net	(329,000,000)	(1,423,000,000)	(847,000,000)
Other, net	(15,000,000)	(28,000,000)	(42,000,000)
NET CASH USED IN FINANCING ACTIVITIES	(1,149,000,000)	(3,489,000,000)	(2,623,000,000)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(158,000,000)	(57,000,000)	40,000,000
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	245,000,000	302,000,000	262,000,000
CASH AND CASH EQUIVALENTS AT END OF PERIOD	87,000,000	245,000,000	302,000,000
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	329,000,000	322,000,000	442,000,000
Income taxes paid, net of refunds	$ 1,271,000,000	$ 1,431,000,000	$ 633,000,000

RETIREMENT AND DEFERRED COMPENSATION PLANS - Expected Future Benefit Payment (Details) $ in Millions	Dec. 31, 2023 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2024	$ 5
2025	5
2026	5
2027	6
2028	6
Years 2029-2033	34
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2024	2
2025	2
2026	1
2027	1
2028	1
Years 2029-2033	$ 6

CAPITAL STOCK - Schedule of Performance Program Activities (Details) - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Units
Employee-related liabilities, current	$ 390	$ 514
Performance Program \| Cash-settled conditional restricted stock unit
Units
Non-vested, beginning balance (in shares)	4,835	4,531	3,417
Granted, Shares (in shares)	1,536	1,676	1,782
Vested, Shares (in shares)	(1,593)	(656)	(76)
Forfeited, Shares (in shares)	(99)	(106)	(240)
Expired, Shares (in shares)	(50)	(610)	(352)
Non-vested, ending balance (in shares)	4,629	4,835	4,531
Employee-related liabilities, current	$ 24

CAPITALIZED EXPLORATORY WELL COSTS (Tables)

12 Months Ended

Dec. 31, 2023

Extractive Industries [Abstract]

Schedule of Capitalized Exploratory Well Costs, Roll Forward


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Capitalized well costs at beginning of year	$	474	$	321	$	197
Additions pending determination of proved reserves	265		287		174

Reclassifications to proved properties	(135)		(110)		(40)
Charged to exploration expense	(18)		(24)		(10)
Capitalized well costs at end of year	$	586	$	474	$	321

Schedule of Aging of Capitalized Exploratory Well Costs


	2023		2022		2021

	(In millions)
Exploratory well costs capitalized for a period of one year or less	$	156	$	215	$	198
Exploratory well costs capitalized for a period greater than one year	430		259		123
Capitalized well costs at end of year	$	586	$	474	$	321

Number of projects with exploratory well costs capitalized for a period greater than one year	33		21		13

Schedule of Projects with Exploratory Well Costs Capitalized for More than One Year


	Total		2022		2021		2020 and Prior

	(In millions)
Suriname	$	421	$	178	$	153	$	90
Egypt	9		—		—		9

	$	430	$	178	$	153	$	99

CAPITAL STOCK - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	2 Months Ended	3 Months Ended				12 Months Ended
	Jan. 31, 2024	Feb. 22, 2024	Sep. 30, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options and restricted stock, anti-dilutive (in shares)							1,900,000	2,400,000	3,300,000
Number of shares authorized to be repurchased (in shares)										40,000,000
Additional number of shares authorized to be repurchased (in shares)			40,000,000	40,000,000
Treasury shares acquired (in shares)							8,711,178	36,164,993	31,204,229
Treasure stock acquired, average price (in USD per share)							$ 37.81	$ 39.34	$ 27.14
Remaining authorized repurchase amount (in shares)							43,900,000
Common stock, dividends, per share (in USD per share)			$ 0.25	$ 0.125	$ 0.0625	$ 0.025	$ 1.00	$ 0.75	$ 0.2375
Shares authorized and available for grant (in shares)							9,400,000
Shares issued in the period (in shares)							0	0	0
Exercised (in shares)							12,183	98,646	0
Total stock-settled and cash-settled compensation expensed							$ 84	$ 304	$ 157
Stock-settled and cash-settled compensation capitalized							$ 13	44	18
Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Treasury shares acquired (in shares)		3,000,000
Treasure stock acquired, average price (in USD per share)		$ 33.27
Remaining authorized repurchase amount (in shares)		40,900,000
Period in which stock options become exercisable	3 years
Weighted average grant date fair value per share (in USD per share)	$ 33.73
Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period in which stock options become exercisable							3 years
Period in which stock options expires after grant date							10 years
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed							$ 73	153	95
Stock-settled and cash-settled compensation capitalized							$ 11	$ 22	$ 15
Awards granted during period (in shares)							661,000	847,000	1,506,000
Weighted average grant date fair value per share (in USD per share)							$ 41.60	$ 29.90	$ 16.46
Restricted Stock \| Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	819,836
Total compensation cost related to non-vested awards not yet recognized	$ 28
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)							1,972,000	2,568,000	4,441,000
Total compensation cost related to non-vested awards not yet recognized							$ 54
Phantom Units \| Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	2,356,255
Total compensation cost related to non-vested awards not yet recognized	$ 80
Award, remeasurement basis (in shares)	1

COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Schedule of Lease Cost

The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2023:


	Operating Leases		Finance Lease
Weighted average remaining lease term	6.9 years		9.7 years
Weighted average discount rate	5.3	%	4.4	%

Schedule of Operating Lease, Liability, Maturity

At December 31, 2023, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:


Net Minimum Commitments(1)	Operating Leases(2)		Finance Lease(3)		Purchase Obligations(4)(5)

	(In millions)
2024	$	116	$	3	$	250
2025	35		3		197
2026	21		4		766
2027	23		4		143
2028	22		4		141
Thereafter	129		23		208
Total future minimum payments	346		41		$	1,705
Less: imputed interest	(65)		(9)		N/A
Total lease liabilities	281		32		N/A
Current portion	116		2		N/A
Non-current portion	$	165	$	30	N/A

(1)Excludes commitments for jointly owned fields and facilities for which the Company is not the operator.

(2)Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense.

(3)Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building.

(4)Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $182 million, $183 million, and $198 million in 2023, 2022, and 2021, respectively.

(5)Under terms agreed to in the Egypt merged concession agreement entered into in 2021, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. As of December 31, 2023, the Company has spent $2.9 billion and believes it will be able to satisfy the remaining obligation within its current exploration and development program.

Schedule of Finance Lease, Liability, Maturity

At December 31, 2023, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:


Net Minimum Commitments(1)	Operating Leases(2)		Finance Lease(3)		Purchase Obligations(4)(5)

	(In millions)
2024	$	116	$	3	$	250
2025	35		3		197
2026	21		4		766
2027	23		4		143
2028	22		4		141
Thereafter	129		23		208
Total future minimum payments	346		41		$	1,705
Less: imputed interest	(65)		(9)		N/A
Total lease liabilities	281		32		N/A
Current portion	116		2		N/A
Non-current portion	$	165	$	30	N/A

(1)Excludes commitments for jointly owned fields and facilities for which the Company is not the operator.

(3)Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building.

Schedule of Long-term Purchase Commitment

At December 31, 2023, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:


Net Minimum Commitments(1)	Operating Leases(2)		Finance Lease(3)		Purchase Obligations(4)(5)

	(In millions)
2024	$	116	$	3	$	250
2025	35		3		197
2026	21		4		766
2027	23		4		143
2028	22		4		141
Thereafter	129		23		208
Total future minimum payments	346		41		$	1,705
Less: imputed interest	(65)		(9)		N/A
Total lease liabilities	281		32		N/A
Current portion	116		2		N/A
Non-current portion	$	165	$	30	N/A

(1)Excludes commitments for jointly owned fields and facilities for which the Company is not the operator.

(3)Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building.

RETIREMENT AND DEFERRED COMPENSATION PLANS - Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset (Details)	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	100.00%	100.00%
Global equities
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	0.00%	6.00%
Multi-asset credit
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	59.00%	40.00%
Nominal bonds
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	6.00%	24.00%
Inflation-linked bonds
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	33.00%	28.00%
Cash
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	2.00%	2.00%

INCOME TAXES - Total Provision for Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current income taxes:
Federal	$ 2	$ 1	$ 16
State	6	11	0
Foreign	1,330	1,495	636
Total current income taxes	1,338	1,507	652
Deferred income taxes:
Federal	(1,708)	0	0
State	(32)	0	0
Foreign	78	145	(74)
Total deferred income taxes	(1,662)	145	(74)
Total	$ (324)	$ 1,652	$ 578

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Additional Information (Details) MMBTU in Thousands, MBoe in Thousands, $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2021 USD ($) MMBTU	Dec. 31, 2023 MBoe	Dec. 31, 2022 MBoe	Dec. 31, 2021 MBoe
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		112	34	102
Revision of previous estimate		46	75	107
PSCs, discounted future net cash flows \| $	$ 750
PSCs, percentage of reserves consolidated	96.00%
Percentage of estimated proved developed reserves classified as proved not producing		10.00%
North America
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		96	22	77
Permian Basin
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		67	9	59
Sale of mineral in place			26	28
Texas Gulf Coast
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		27	8	18
Delaware Basin
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		2	5
Purchase of mineral in place			39
International Regions
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		16	12	25
EGYPT
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		15	9	22
North Sea
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		1	3	3
Changes in Product Prices
Reserve Quantities [Line Items]
Revision of previous estimate		83	5	85
Changes in Engineering and Performance
Reserve Quantities [Line Items]
Revision of previous estimate		37	70	22
Changes in Engineering and Performance \| United States
Reserve Quantities [Line Items]
Revision of previous estimate			18
Production Sharing Contracts Modernization Impact
Reserve Quantities [Line Items]
Revision of previous estimate	53		43
Other Revisions
Reserve Quantities [Line Items]
Revision of previous estimate				35
Other Revisions \| EGYPT
Reserve Quantities [Line Items]
Revision of previous estimate				57
Other Revisions \| North Sea
Reserve Quantities [Line Items]
Revision of previous estimate			9
Production Sharing Contracts Modernization Impact, Undeveloped Reserves
Reserve Quantities [Line Items]
Revision of previous estimate \| MMBTU	4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Allowance for Credit Loss Roll-forward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Allowance for credit loss at beginning of year	$ 117	$ 109	$ 95
Additional provisions for the year	16	9	19
Uncollectible accounts written off, net of recoveries	(19)	(1)	(5)
Allowance for credit loss at end of year	$ 114	$ 117	$ 109

MAJOR CUSTOMERS (Details) - Customer Concentration Risk - Oil and Gas Production Revenues	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Egyptian General Petroleum Corporation
Revenue, Major Customer [Line Items]
Concentration risk percentage	15.00%	15.00%	14.00%
CFE International
Revenue, Major Customer [Line Items]
Concentration risk percentage			10.00%

DEBT AND FINANCING COSTS - Uncommitted Lines of Credit (Details) - Uncommitted Lines of Credit - Line of Credit £ in Millions	Dec. 31, 2023 USD ($)	Dec. 31, 2023 GBP (£)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 GBP (£)
Debt Instrument [Line Items]
Line of credit outstanding	$ 0		$ 0
Letter of Credit
Debt Instrument [Line Items]
Letters of credit outstanding, amount	$ 2,000,000	£ 416	$ 17,000,000	£ 199

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 835
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482900/835-30-50-1

Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(f))
-Publisher FASB
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+ Details

- Definition

The carrying value as of the balance sheet date of the current and noncurrent portions of long-term obligations drawn from a line of credit, which is a bank's commitment to make loans up to a specific amount. Examples of items that might be included in the application of this element may consist of letters of credit, standby letters of credit, and revolving credit arrangements, under which borrowings can be made up to a maximum amount as of any point in time conditional on satisfaction of specified terms before, as of and after the date of drawdowns on the line. Includes short-term obligations that would normally be classified as current liabilities but for which (a) postbalance sheet date issuance of a long term obligation to refinance the short term obligation on a long term basis, or (b) the enterprise has entered into a financing agreement that clearly permits the enterprise to refinance the short-term obligation on a long term basis and the following conditions are met (1) the agreement does not expire within 1 year and is not cancelable by the lender except for violation of an objectively determinable provision, (2) no violation exists at the BS date, and (3) the lender has entered into the financing agreement is expected to be financially capable of honoring the agreement.

+ References + Details

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST - USD ($) $ in Millions	Total	Noncontrolling interest - Egypt	Noncontrolling interest - Altus	APA SHAREHOLDERS’ EQUITY (DEFICIT)	Common Stock	Paid-In Capital	Accumulated Deficit	Treasury Stock	Accumulated Other Comprehensive Income	Noncontrolling Interests	Noncontrolling Interests Noncontrolling interest - Egypt	Noncontrolling Interests Noncontrolling interest - Altus	Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners
Beginning balance at Dec. 31, 2020													$ 608
Increase (Decrease) in Temporary Equity [Roll Forward]
Net income attributable to Altus Preferred Unit limited partners													162
Distributions payable to Altus Preferred Unit limited partners													(12)
Distributions to noncontrolling interest		$ (279)									$ (279)		(46)
Ending balance at Dec. 31, 2021													712
Beginning balance at Dec. 31, 2020	$ (645)			$ (1,639)	$ 262	$ 11,735	$ (10,461)	$ (3,189)	$ 14	$ 994
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) attributable to common stock	973			973			973
Net income (loss) attributable to noncontrolling interest		174	$ 4								174	$ 4
Distributions to noncontrolling interest		(279)									(279)		(46)
Common dividends	(87)			(87)		(87)
Common stock activity, net	(6)			(6)		(6)
Treasury stock activity, net	(847)			(847)				(847)
Compensation expense	21			21		21
Other	(25)			(10)		(18)			8	(15)
Ending balance at Dec. 31, 2021	(717)			(1,595)	262	11,645	(9,488)	(4,036)	22	878
Increase (Decrease) in Temporary Equity [Roll Forward]
Net income attributable to Altus Preferred Unit limited partners													(70)
Distributions to noncontrolling interest		(362)									(362)
Deconsolidation of Altus			(72)									(72)	(642)
Ending balance at Dec. 31, 2022													0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) attributable to common stock	3,674			3,674			3,674
Net income (loss) attributable to noncontrolling interest		464	14								464	14
Distributions to noncontrolling interest		(362)									(362)
Common dividends	(245)			(245)		(245)
Common stock activity, net	(6)			(6)		(6)
Deconsolidation of Altus			(72)									$ (72)	(642)
Treasury stock activity, net	(1,423)			(1,423)				(1,423)
Compensation expense	26			26		26
Other	(8)			(8)					(8)
Ending balance at Dec. 31, 2022	1,345			423	262	11,420	(5,814)	(5,459)	14	922
Increase (Decrease) in Temporary Equity [Roll Forward]
Distributions to noncontrolling interest		(238)									(238)
Ending balance at Dec. 31, 2023													$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) attributable to common stock	2,855			2,855			2,855
Net income (loss) attributable to noncontrolling interest		352	$ 0								352
Distributions to noncontrolling interest		$ (238)									$ (238)
Common dividends	(308)			(308)		(308)
Common stock activity, net	(13)			(13)	1	(14)
Treasury stock activity, net	(331)			(331)				(331)
Compensation expense	23			23		23
Other	6			6		5			1
Ending balance at Dec. 31, 2023	$ 3,691			$ 2,655	$ 263	$ 11,126	$ (2,959)	$ (5,790)	$ 15	$ 1,036

CAPITALIZED EXPLORATORY WELL COSTS - Capitalized Exploratory Well Costs Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Capitalized well costs at beginning of year	$ 474	$ 321	$ 197
Additions pending determination of proved reserves	265	287	174
Reclassifications to proved properties	(135)	(110)	(40)
Charged to exploration expense	(18)	(24)	(10)
Capitalized well costs at end of year	$ 586	$ 474	$ 321

ASSET RETIREMENT OBLIGATION

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2023 and 2022:


	For the Year Ended December 31,
	2023		2022

	(In millions)
Asset retirement obligation at beginning of the year	$	1,995	$	2,130
Liabilities incurred	14		4
Liabilities acquired	—		4
Liabilities divested	—		(73)
Liabilities settled	(43)		(39)
Accretion expense	116		117
Revisions in estimated liabilities	356		(148)

Asset retirement obligation at end of the year	2,438		1,995
Less current portion	(76)		(55)
Asset retirement obligation, long-term	$	2,362	$	1,940

The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties and other long-lived assets. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property or other long-lived asset balance.

During 2023 and 2022, the Company recorded $14 million and $4 million, respectively, in abandonment liabilities resulting from the Company’s exploration and development capital program. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period. During 2023, net abandonment costs were revised upward by approximately $356 million, primarily reflecting changes in estimates of timing, activity costs, and foreign currency exchange rates on service costs in the North Sea. During 2022, net abandonment costs were revised downward by approximately $148 million to reflect changes in estimates of timing and foreign currency exchange rates on service costs, primarily in the North Sea, partially offset by an upward revision in the U.S.

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
NET INCOME INCLUDING NONCONTROLLING INTERESTS	$ 3,207	$ 4,082	$ 1,313
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Pension and postretirement benefit plan	1	(8)	7
Share of equity method interests other comprehensive income	0	0	1
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS	3,208	4,074	1,321
Comprehensive income (loss) attributable to Altus Preferred Unit limited partners	0	(70)	162
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	2,856	3,666	981
Noncontrolling interest - Egypt
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Comprehensive income (loss) attributable to noncontrolling interest	352	464	174
Noncontrolling interest - Altus
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Comprehensive income (loss) attributable to noncontrolling interest	$ 0	$ 14	$ 4

EQUITY METHOD INTERESTS (Tables)

12 Months Ended

Dec. 31, 2023

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Equity Method Investment Information

The following table represents related party sales and costs associated with Kinetik:


	For the Year Ended December 31,
	2023		2022

	(In millions)
Natural gas and NGLs sales	$	92	$	18
Purchased oil and gas sales	29		—
	$	121	$	18

Gathering, processing, and transmission costs	$	108	$	93
Purchased oil and gas costs	80		—
Lease operating expenses	7		—
	$	195	$	93

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

12 Months Ended

Dec. 31, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, as well as fluctuations in exchange rates in connection with transactions denominated in foreign currencies. The Company manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production and foreign currency transactions. The Company utilizes various types of derivative financial instruments, including forward contracts, futures contracts, swaps, and options, to manage fluctuations in cash flows resulting from changes in commodity prices or foreign currency values.

Counterparty Risk

The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of December 31, 2023, the Company had derivative positions with four counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments resulting from lower commodity prices or changes in currency exchange rates.

Derivative Instruments

Commodity Derivative Instruments

As of December 31, 2023, the Company had the following open natural gas financial basis swap contracts:


		Basis Swap Purchased		Basis Swap Sold
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential	MMBtu (in 000’s)	Weighted Average Price Differential
January—June 2024	NYMEX Henry Hub/IF Waha	16,380	$(1.15)	—	—
January—June 2024	NYMEX Henry Hub/IF HSC	—	—	16,380	$(0.10)

Fair Value Measurements

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:


	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount
	(In millions)
December 31, 2023
Assets:
Commodity derivative instruments	$	—	$	6	$	—	$	6	$	—	$	6





December 31, 2022
Assets:
Commodity derivative instruments	$	—	$	5	$	—	$	5	$	—	$	5

Liabilities:
Commodity derivative instruments	$	—	$	50	$	—	$	50	$	—	$	50

(1)The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties and reclassifications between long-term and short-term balances.

The fair values of the Company’s derivative instruments are not actively quoted in the open market. The Company primarily uses a market approach to estimate the fair values of these derivatives on a recurring basis, utilizing futures pricing for the underlying positions provided by a reputable third party, a Level 2 fair value measurement.

Derivative Activity Recorded in the Consolidated Balance Sheet

All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:


	For the Year Ended December 31,
	2023		2022

	(In millions)
Current Assets: Other current assets	$	6	$	—
Other Assets: Deferred charges and other	—		5
Total derivative assets	$	6	$	5

Current Liabilities: Other current liabilities	$	—	$	50

Total derivative liabilities	$	—	$	50

Derivative Activity Recorded in the Statement of Consolidated Operations

The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Realized:
Commodity derivative instruments	$	48	$	(34)	$	25

Foreign currency derivative instruments	—		(13)		—

Realized gains (losses), net	48		(47)		25
Unrealized:
Commodity derivative instruments	51		(36)		(20)
Pipeline capacity embedded derivatives	—		—		7

Preferred Units embedded derivative	—		(31)		82
Unrealized gains (losses), net	51		(67)		69
Derivative instrument gains (losses), net	$	99	$	(114)	$	94

Derivative instrument gains and losses are recorded in “Derivative instrument gains (losses), net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains (losses) for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument (gains) losses, net” under “Adjustments to reconcile net income to net cash provided by operating activities.”

OTHER CURRENT LIABILITIES

12 Months Ended

Dec. 31, 2023

Payables and Accruals [Abstract]

OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities as of December 31:


	2023		2022

	(In millions)
Accrued operating expenses	$	162	$	145
Accrued exploration and development	371		333

Accrued compensation and benefits	390		514
Accrued interest	93		97
Accrued income taxes	138		90
Current asset retirement obligation	76		55
Current operating lease liability	116		167

Current decommissioning contingency for sold Gulf of Mexico properties	60		450
Other	338		292
Total Other current liabilities	$	1,744	$	2,143

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions.

Use of Estimates

Fair Value Measurements

Revenue Recognition

Upstream

Refer to Note 17—Business Segment Information for a disaggregation of revenue by product and reporting segment.

Altus Midstream

Payment Terms and Contract Balances

Cash and Cash Equivalents

Accounts Receivable and Allowance for Credit Losses

Inventories

Property and Equipment

Other Property and Equipment

Oil and Gas Property

The following table represents non-cash impairment charges of the carrying value of the Company’s unproved properties:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)






Unproved properties:
U.S.	$	10	$	20	$	22
Egypt	—		4		8
North Sea	11		—		1
Other International	1		—		—
Total unproved properties	$	22	$	24	$	31

For the years ended December 31, 2023, 2022, and 2021, the Company recorded no impairments of proved properties.

Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction.

Gathering, Processing, and Transmission Facilities

Gathering, Processing, and Transmission (GPT) Facilities

For the years ended December 31, 2023, 2022, and 2021, the Company recorded no impairments of GPT facilities.

Asset Retirement Costs and Obligations

Capitalized Interest

Equity Method Interests

Commitments and Contingencies

Derivative Instruments and Hedging Activities

Income Taxes

Earnings Per Share

Stock-Based Compensation

Treasury Stock

The Company follows the weighted-average-cost method of accounting for treasury stock transactions.

New Pronouncements Issued But Not Yet Adopted

INCOME TAXES - Schedule of Components of Net Deferred Tax (Asset) Liability (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Deferred tax assets:
U.S. and state net operating losses	$ 2,050	$ 2,029
Capital losses	8	357
Foreign net operating losses	43	27
Tax credits and other tax incentives	26	26
Foreign tax credits	2,204	2,241
Accrued expenses and liabilities	129	156
Asset retirement obligation	850	672
Property and equipment	38	44
Equity investments	8	0
Net interest expense limitation	125	74
Lease liability	71	114
Decommissioning contingency for sold Gulf of Mexico properties	210	275
Total deferred tax assets	5,762	6,015
Valuation allowance	(2,630)	(4,918)	$ (5,902)	$ (5,991)
Net deferred tax assets	3,132	1,097
Deferred tax liabilities:
Equity investments	0	1
Property and equipment	1,573	1,023
Right-of-use asset	69	110
Decommissioning security for sold Gulf of Mexico properties	44	148
Other	59	90
Total deferred tax liabilities	1,745	1,372
Net deferred income tax asset	$ (1,387)
Net deferred income tax liability		$ 275

ACCUMULATED OTHER COMPREHENSIVE INCOME

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

ACCUMULATED OTHER COMPREHENSIVE INCOME

Components of accumulated other comprehensive income include the following:


	As of December 31,
	2023		2022		2021

	(In millions)

Pension and postretirement benefit plan (Note 12)	$	15	$	14	$	22
Accumulated other comprehensive income	$	15	$	14	$	22

COMMITMENTS AND CONTINGENCIES - Company's Weighted Average Lease Term and Discount Rate related to Leases (Details)	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Operating leases, weighted average remaining lease term	6 years 10 months 24 days
Finance leases, weighted average remaining lease term	9 years 8 months 12 days
Operating leases, weighted average discount rate	5.30%
Finance leases, weighted average discount rate	4.40%

ACQUISITIONS AND DIVESTITURES - 2022 Activity (Details) - USD ($) shares in Millions, $ in Millions			1 Months Ended		3 Months Ended			12 Months Ended
	Mar. 11, 2022	Feb. 22, 2022	Dec. 31, 2023	Mar. 31, 2022	Sep. 30, 2022	Mar. 31, 2022	Jun. 30, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Feb. 21, 2022
Business Acquisition [Line Items]
Proceeds from asset divestitures								$ 29	$ 778	$ 256
Deconsolidation gain		$ 609
Deconsolidation, net amount of balance sheet		193
Equity method interests			$ 437					437	624
Shares sold (in shares)						4.0
Kinetik
Business Acquisition [Line Items]
Equity method interests		$ 802
Shares sold (in shares)	4.0		7.5	4.0
Proceeds from sale of stock			$ 228			$ 224
Apache Midstream LLC \| ALTM
Business Acquisition [Line Items]
Ownership percentage by parent											79.00%
BCP Business Combination \| Altus Midstream \| ALTM
Business Acquisition [Line Items]
Ownership percentage by noncontrolling owners		20.00%
BCP Business Combination \| BCP Business Combination Contributor \| Kinetik
Business Acquisition [Line Items]
Ownership percentage by parent		75.00%
BCP Business Combination \| Common Class C \| Altus Midstream
Business Acquisition [Line Items]
Business acquisition, equity interest issued or issuable, number of shares (in shares)		50.0
Disposed of by Sale \| Non-Core Assets And Leasehold
Business Acquisition [Line Items]
Proceeds from asset divestitures								29	52
Gain (loss) on sale of oil and gas properties								8	36
Disposed of by Sale \| Non-Core Mineral Rights
Business Acquisition [Line Items]
Proceeds from asset divestitures									726
Gain (loss) on sale of oil and gas properties									560
Delaware Basin
Business Acquisition [Line Items]
Asset acquisition consideration transferred					$ 615
Payments to acquire oil and gas property								24
Asset acquisition, proved properties amount					581
Asset acquisition, unproved leasehold amount					38
Abandonment obligations					$ 4
Permian Region
Business Acquisition [Line Items]
Payments to acquire oil and gas property								$ 20
Payments to acquire leasehold and property									$ 37	9
Permian Region \| Disposed of by Sale
Business Acquisition [Line Items]
Proceeds from asset divestitures							$ 176
Gain (loss) on sale of oil and gas properties							$ 63
Permian Region \| Disposed of by Sale \| Non-Core Assets And Leasehold
Business Acquisition [Line Items]
Proceeds from asset divestitures										80
Gain (loss) on sale of oil and gas properties										$ 4

ACCUMULATED OTHER COMPREHENSIVE INCOME (Tables)

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

Schedule of Components of Accumulated Other Comprehensive Income (loss)

Components of accumulated other comprehensive income include the following:


	As of December 31,
	2023		2022		2021

	(In millions)

Pension and postretirement benefit plan (Note 12)	$	15	$	14	$	22
Accumulated other comprehensive income	$	15	$	14	$	22

ASSET RETIREMENT OBLIGATION (Tables)

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Changes to Asset Retirement Obligation

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2023 and 2022:


	For the Year Ended December 31,
	2023		2022

	(In millions)
Asset retirement obligation at beginning of the year	$	1,995	$	2,130
Liabilities incurred	14		4
Liabilities acquired	—		4
Liabilities divested	—		(73)
Liabilities settled	(43)		(39)
Accretion expense	116		117
Revisions in estimated liabilities	356		(148)

Asset retirement obligation at end of the year	2,438		1,995
Less current portion	(76)		(55)
Asset retirement obligation, long-term	$	2,362	$	1,940

REDEMABLE NONCONTROLLING INTEREST - ALTUS (Details) - USD ($) $ in Millions		12 Months Ended
	Jun. 12, 2019	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Class of Stock [Line Items]
Net income (loss) attributable to Altus Preferred Unit limited partners		$ 0	$ (70)	$ 162
Altus Midstream LP \| Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners
Class of Stock [Line Items]
Aggregate issue price of Preferred Units	$ 625
Proceeds from issuance or sale of equity	$ 611

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
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Reference 2: http://www.xbrl.org/2003/role/recommendedDisclosureRef
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Reference 4: http://www.xbrl.org/2009/role/commonPracticeRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

ACQUISITIONS AND DIVESTITURES - 2023 Activity (Details) - USD ($) shares in Millions, $ in Millions		1 Months Ended		3 Months Ended		12 Months Ended
	Mar. 11, 2022	Dec. 31, 2023	Mar. 31, 2022	Mar. 31, 2022	Jun. 30, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Shares sold (in shares)				4.0
Proceeds from asset divestitures						$ 29	$ 778	$ 256
Disposed of by Sale \| Non-Core Assets And Leasehold
Business Acquisition [Line Items]
Proceeds from asset divestitures						29	52
Gain (loss) on sale of oil and gas properties						8	$ 36
Permian Region
Business Acquisition [Line Items]
Payments to acquire oil and gas property						$ 20
Permian Region \| Disposed of by Sale
Business Acquisition [Line Items]
Proceeds from asset divestitures					$ 176
Gain (loss) on sale of oil and gas properties					$ 63
Permian Region \| Disposed of by Sale \| Non-Core Assets And Leasehold
Business Acquisition [Line Items]
Proceeds from asset divestitures								80
Gain (loss) on sale of oil and gas properties								$ 4
Kinetik
Business Acquisition [Line Items]
Shares sold (in shares)	4.0	7.5	4.0
Proceeds from sale of stock		$ 228		$ 224

MAJOR CUSTOMERS	12 Months Ended
MAJOR CUSTOMERS	Dec. 31, 2023
Risks and Uncertainties [Abstract]
MAJOR CUSTOMERS	MAJOR CUSTOMERS The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. During each of 2023 and 2022, sales to EGPC accounted for approximately 15 percent of the Company’s worldwide crude oil, natural gas, and NGLs revenues. During 2021, sales to EGPC and CFE International accounted for approximately 14 percent and 10 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs revenues. Management does not believe that the loss of any one of these customers would have a material adverse effect on the results of operations.

INCOME TAXES - Net Deferred Tax Assets and Liabilities in the Consolidated Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Deferred tax asset (Note 10)	$ 1,758	$ 39
Deferred tax liability (Note 10)	371	314
Net deferred income tax asset	$ (1,387)
Net deferred income tax liability		$ 275

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Non-Cash Impairments of Proved and Unproved Property and Equipment (Details) - Oil And Gas Properties, Unproved - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Schedule Of Significant Accounting Policies [Line Items]
Impairments	$ 22	$ 24	$ 31
UNITED STATES
Schedule Of Significant Accounting Policies [Line Items]
Impairments	10	20	22
EGYPT
Schedule Of Significant Accounting Policies [Line Items]
Impairments	0	4	8
North Sea
Schedule Of Significant Accounting Policies [Line Items]
Impairments	11	0	1
Other International
Schedule Of Significant Accounting Policies [Line Items]
Impairments	$ 1	$ 0	$ 0

INCOME TAXES - Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income tax expense at U.S. statutory rate	$ 605	$ 1,204	$ 397
State income tax, less federal effect	(23)	9	0
Taxes related to foreign operations	752	745	298
Tax credits	0	(4)	(10)
Net change in tax contingencies	5	1	16
Valuation allowances	(1,842)	(646)	(90)
Tax adjustments attributable to BCP Business Combination	0	126	0
Remeasurement of U.K. deferred tax liability	174	208	0
Tax attributable to Altus Preferred Unit limited partners	0	0	(34)
All other, net	5	9	1
Total	$ (324)	$ 1,652	$ 578

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities (Details) - Oil and Gas, Exploration and Production - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	$ 7,385	$ 9,223	$ 6,501
Depreciation, depletion, and amortization	1,500	1,186	1,255
Asset retirement obligation accretion	116	116	109
Lease operating expenses	1,436	1,445	1,243
Gathering, processing, and transmission	334	380	360
Exploration expenses	195	305	155
Production taxes	204	263	188
Income tax	1,496	2,105	996
Operating costs	5,281	5,800	4,306
Results of operations	2,104	3,423	2,195
United States
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	3,018	4,144	3,280
Depreciation, depletion, and amortization	709	564	511
Asset retirement obligation accretion	40	34	30
Lease operating expenses	593	515	391
Gathering, processing, and transmission	249	315	309
Exploration expenses	14	24	28
Production taxes	204	263	188
Income tax	254	510	383
Operating costs	2,063	2,225	1,840
Results of operations	955	1,919	1,440
EGYPT
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	3,029	3,521	2,085
Depreciation, depletion, and amortization	521	390	477
Asset retirement obligation accretion	0	0	0
Lease operating expenses	474	526	469
Gathering, processing, and transmission	33	22	12
Exploration expenses	119	84	63
Production taxes	0	0	0
Income tax	828	1,100	479
Operating costs	1,975	2,122	1,500
Results of operations	1,054	1,399	585
North Sea
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	1,338	1,558	1,136
Depreciation, depletion, and amortization	270	232	267
Asset retirement obligation accretion	76	82	79
Lease operating expenses	369	404	383
Gathering, processing, and transmission	52	43	39
Exploration expenses	19	35	34
Production taxes	0	0	0
Income tax	414	495	134
Operating costs	1,200	1,291	936
Results of operations	138	267	200
Other International
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	0	0	0
Depreciation, depletion, and amortization	0	0	0
Asset retirement obligation accretion	0	0	0
Lease operating expenses	0	0	0
Gathering, processing, and transmission	0	0	0
Exploration expenses	43	162	30
Production taxes	0	0	0
Income tax	0	0	0
Operating costs	43	162	30
Results of operations	$ (43)	$ (162)	$ (30)

CAPITAL STOCK - Summary of Stock Options Activities (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Shares Under Option
Outstanding, beginning of year, Shares (in shares)	2,078,000	3,012,000	3,537,000
Exercised, Shares (in shares)	(12,183)	(98,646)	0
Forfeited, Shares (in shares)	0	(2,000)	0
Expired, Shares (in shares)	(601,000)	(833,000)	(525,000)
Outstanding, end of year, Shares (in shares)	1,465,000	2,078,000	3,012,000
Expected to vest, Shares (in shares)	0	0	0
Exercisable, end of year, Shares (in shares)	1,465,000	2,078,000	3,012,000
Weighted Average Exercise Price
Outstanding, beginning of year, weighted average exercise price (in USD per share)	$ 57.71	$ 63.79	$ 72.10
Exercised, weighted average exercise price (in USD per share)	42.38	42.09	0
Forfeited, weighted average exercise price (in USD per share)	0	49.10	0
Expired, weighted average exercise price (in USD per share)	80.53	81.56	119.83
Outstanding, end of year, weighted average exercise price (in USD per share)	48.48	57.71	63.79
Expected to vest, weighted average exercise price (in USD per share)	0	0	0
Exercisable, end of year, weighted average exercise price (in USD per share)	$ 48.48	$ 57.71	$ 63.79
Weighted average remaining contractual life for options outstanding	3 years 1 month 6 days
Weighted average remaining contractual life for exercisable	3 years 1 month 6 days
Aggregate intrinsic value for options outstanding exercisable	$ 33
Aggregate intrinsic value for options outstanding	$ 33

Insider Trading Arrangements	3 Months Ended
Insider Trading Arrangements	Dec. 31, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

OTHER CURRENT ASSETS (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Inventories	$ 453	$ 427
Drilling advances	88	89
Prepaid assets and other	46	31
Current decommissioning security for sold Gulf of Mexico assets	178	450
Total Other current assets	$ 765	$ 997

INCOME TAXES - Reconciliation of Beginning and Ending Amount of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of year	$ 93	$ 89	$ 116	$ 93
Additions based on tax positions related to prior year	4	0	16
Additions based on tax positions related to the current year	0	0	7
Reductions for tax positions of prior years	0	(27)	0
Balance at end of year	$ 93	$ 89	$ 116	$ 93

INCOME TAXES - Net Operating Losses (Details) $ in Millions	Dec. 31, 2023 USD ($)
U.S.
Schedule Of Income Tax [Line Items]
Net operating losses	$ 8,027
State
Schedule Of Income Tax [Line Items]
Net operating losses	6,553
Foreign
Schedule Of Income Tax [Line Items]
Net operating losses	$ 119

COMMITMENTS AND CONTINGENCIES - Schedule of Future Minimum Lease Payments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Leases
2024	$ 116
2025	35
2026	21
2027	23
2028	22
Thereafter	129
Total future minimum payments	346
Less: imputed interest	(65)
Total lease liabilities	281
Current portion	116	$ 167
Non-current portion	$ 165
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other current liabilities (Note 7)	Other current liabilities (Note 7)
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other	Other
Finance Lease
2024	$ 3
2025	3
2026	4
2027	4
2028	4
Thereafter	23
Total future minimum payments	41
Less: imputed interest	(9)
Total lease liabilities	32	$ 34
Current portion	2
Non-current portion	30
Purchase Obligations
2024	250
2025	197
2026	766
2027	143
2028	141
Thereafter	208
Total future minimum payments	1,705
Total costs under take or pay and throughout obligation	182	$ 183	$ 198
Purchase commitment, remaining minimum amount committed	3,500
Purchase commitment, amount incurred	$ 2,900

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)

12 Months Ended

Dec. 31, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

As of December 31, 2023, the Company had the following open natural gas financial basis swap contracts:


		Basis Swap Purchased		Basis Swap Sold
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential	MMBtu (in 000’s)	Weighted Average Price Differential
January—June 2024	NYMEX Henry Hub/IF Waha	16,380	$(1.15)	—	—
January—June 2024	NYMEX Henry Hub/IF HSC	—	—	16,380	$(0.10)

Schedule of Derivative Assets Measured at Fair Value

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:


	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount
	(In millions)
December 31, 2023
Assets:
Commodity derivative instruments	$	—	$	6	$	—	$	6	$	—	$	6





December 31, 2022
Assets:
Commodity derivative instruments	$	—	$	5	$	—	$	5	$	—	$	5

Liabilities:
Commodity derivative instruments	$	—	$	50	$	—	$	50	$	—	$	50

Schedule of Derivative Liabilities Measured at Fair Value

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:


	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount
	(In millions)
December 31, 2023
Assets:
Commodity derivative instruments	$	—	$	6	$	—	$	6	$	—	$	6





December 31, 2022
Assets:
Commodity derivative instruments	$	—	$	5	$	—	$	5	$	—	$	5

Liabilities:
Commodity derivative instruments	$	—	$	50	$	—	$	50	$	—	$	50

Schedule of Derivative Instruments on Consolidated Balance Sheet and Statement of Consolidated Operations

The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:


	For the Year Ended December 31,
	2023		2022

	(In millions)
Current Assets: Other current assets	$	6	$	—
Other Assets: Deferred charges and other	—		5
Total derivative assets	$	6	$	5

Current Liabilities: Other current liabilities	$	—	$	50

Total derivative liabilities	$	—	$	50

The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Realized:
Commodity derivative instruments	$	48	$	(34)	$	25

Foreign currency derivative instruments	—		(13)		—

Realized gains (losses), net	48		(47)		25
Unrealized:
Commodity derivative instruments	51		(36)		(20)
Pipeline capacity embedded derivatives	—		—		7

Preferred Units embedded derivative	—		(31)		82
Unrealized gains (losses), net	51		(67)		69
Derivative instrument gains (losses), net	$	99	$	(114)	$	94

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References + Details

BUSINESS SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2023

Segment Reporting [Abstract]

BUSINESS SEGMENT INFORMATION

As of December 31, 2023, the Company’s consolidated subsidiaries are engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and the U.S. The Company’s Upstream business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Midstream business was operated by ALTM, which owned, developed, and operated a midstream energy asset network in the Permian Basin of West Texas. The Company also has active exploration and appraisal operations ongoing in Suriname, as well as interests in Uruguay and other international locations that may, over time, result in reportable discoveries and development opportunities. Financial information for each segment is presented below:


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream

	(In millions)
2023
Oil revenues	$	2,683	$	1,073	$	2,241	$	—	$	—	$	5,997
Natural gas revenues	346		237		297		—		—		880
Natural gas liquids revenues	—		28		480		—		—		508
Oil, natural gas, and natural gas liquids production revenues	3,029		1,338		3,018		—		—		7,385
Purchased oil and gas sales	—		—		894		—		—		894
	3,029		1,338		3,912		—		—		8,279
Operating Expenses:
Lease operating expenses	474		369		593		—		—		1,436
Gathering, processing, and transmission	33		52		249		—		—		334
Purchased oil and gas costs	—		—		742		—		—		742
Taxes other than income	—		—		207		—		—		207
Exploration(4)	119		19		14		—		43		195
Depreciation, depletion, and amortization	524		271		745		—		—		1,540
Asset retirement obligation accretion	—		76		40		—		—		116
Impairments	—		50		11		—		—		61
	1,150		837		2,601		—		43		4,631
Operating Income (Loss)	$	1,879	$	501	$	1,311	$	—	$	(43)	3,648
Other Income (Expense):
Gain on divestitures, net											8
Losses on previously sold Gulf of Mexico properties											(212)
Derivative instrument gains, net											99
Other											18
General and administrative											(351)
Transaction, reorganization, and separation											(15)
Financing costs, net											(312)
Income Before Income Taxes											$	2,883

Total Assets(3)	$	3,503	$	1,970	$	9,221	$	—	$	550	$	15,244
Net Property and Equipment	$	2,209	$	1,628	$	5,689	$	—	$	512	$	10,038
Additions to Net Property and Equipment	$	834	$	131	$	1,255	$	—	$	93	$	2,313


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream

	(In millions)
2022
Oil revenues	$	3,145	$	1,232	$	2,458	$	—	$	—	$	6,835
Natural gas revenues	370		281		918		—		—		1,569
Natural gas liquids revenues	6		45		768		—		(3)		816
Oil, natural gas, and natural gas liquids production revenues	3,521		1,558		4,144		—		(3)		9,220
Purchased oil and gas sales	—		—		1,850		5		—		1,855
Midstream service affiliate revenues	—		—		—		16		(16)		—
	3,521		1,558		5,994		21		(19)		11,075
Operating Expenses:
Lease operating expenses	526		404		515		—		(1)		1,444
Gathering, processing, and transmission	22		43		315		5		(18)		367
Purchased oil and gas costs	—		—		1,776		—		—		1,776
Taxes other than income	—		—		265		3		—		268
Exploration(4)	84		35		24		—		162		305
Depreciation, depletion, and amortization	400		238		593		2		—		1,233
Asset retirement obligation accretion	—		82		34		1		—		117

	1,032		802		3,522		11		143		5,510
Operating Income (Loss)	$	2,489	$	756	$	2,472	$	10	$	(162)	5,565
Other Income (Expense):
Gain on divestitures, net											1,180
Losses on previously sold Gulf of Mexico properties											(157)
Derivative instrument losses, net											(114)
Other											148
General and administrative											(483)
Transaction, reorganization, and separation											(26)
Financing costs, net											(379)
Income Before Income Taxes											$	5,734

Total Assets(3)	$	3,148	$	1,911	$	7,574	$	—	$	514	$	13,147
Net Property and Equipment	$	1,976	$	1,386	$	5,226	$	—	$	424	$	9,012
Additions to Net Property and Equipment	$	695	$	210	$	1,439	$	—	$	263	$	2,607


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream

	(In millions)
2021
Oil revenues	$	1,806	$	929	$	1,850	$	—	$	—	$	4,585
Natural gas revenues	270		183		754		—		—		1,207
Natural gas liquids revenues	9		24		676		—		(3)		706
Oil, natural gas, and natural gas liquids production revenues	2,085		1,136		3,280		—		(3)		6,498
Purchased oil and gas sales	—		—		1,476		11		—		1,487
Midstream service affiliate revenues	—		—		—		127		(127)		—
	2,085		1,136		4,756		138		(130)		7,985
Operating Expenses:
Lease operating expenses	469		383		391		—		(2)		1,241
Gathering, processing, and transmission	12		39		309		32		(128)		264
Purchased oil and gas costs	—		—		1,575		5		—		1,580
Taxes other than income	—		—		190		14		—		204
Exploration(4)	63		34		28		—		30		155
Depreciation, depletion, and amortization	524		270		554		12		—		1,360
Asset retirement obligation accretion	—		79		30		4		—		113
Impairments	26		22		—		160		—		208
	1,094		827		3,077		227		(100)		5,125
Operating Income (Loss)	$	991	$	309	$	1,679	$	(89)	$	(30)	2,860
Other Income (Expense):
Gain on divestitures, net											67
Losses on previously sold Gulf of Mexico properties											(446)
Derivative instrument gains, net											94
Other											228
General and administrative											(376)
Transaction, reorganization, and separation											(22)
Financing costs, net											(514)
Income Before Income Taxes											$	1,891

Total Assets(3)	$	2,796	$	2,199	$	6,269	$	1,698	$	341	$	13,303
Net Property and Equipment	$	1,720	$	1,646	$	4,507	$	187	$	275	$	8,335
Additions to Net Property and Equipment	$	319	$	159	$	523	$	3	$	151	$	1,155

(1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the years ended December 31, 2023, 2022, and 2021 of:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Oil	$	729	$	989	$	420
Natural gas	95		117		47
Natural gas liquids	—		2		2

(2)Includes a noncontrolling interest in Egypt for all periods presented and a noncontrolling interest in Altus Midstream for the years 2022 and 2021.

(3)Intercompany balances are excluded from total assets.

(4)Exploration expense under Intersegment Eliminations & Other primarily reflects the Company’s Suriname exploration activities.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-22

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-15

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 31
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-31

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 42
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-42

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 40
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-40

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org//280/tableOfContent

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 26
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-26

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 34
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-34

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 41
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-41

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-21

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-21

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

+ Details

RETIREMENT AND DEFERRED COMPENSATION PLANS

12 Months Ended

Dec. 31, 2023

Retirement Benefits [Abstract]

RETIREMENT AND DEFERRED COMPENSATION PLANS

The Company provides retirement benefits to its U.S. employees through the use of multiple plans: a 401(k) savings plan, a money purchase retirement plan, a non-qualified retirement savings plan, and a non-qualified restorative retirement savings plan. The 401(k) savings plan provides participating employees the ability to elect to contribute up to 50 percent of eligible compensation to the plan with the Company making matching contributions up to a maximum of 8 percent of each employee’s annual eligible compensation. In addition, the Company contributes 6 percent of each participating employee’s annual eligible compensation to a money purchase retirement plan. The 401(k) savings plan and the money purchase retirement plan are subject to certain annually-adjusted, government-mandated restrictions that limit the amount of employee and Company contributions. For certain eligible employees, the Company also provides a non-qualified retirement savings plan or a non-qualified restorative retirement savings plan. These plans allow the deferral of up to 50 percent of each employee’s base salary, up to 75 percent of each employee’s annual bonus (that accepts employee contributions) and the Company’s matching contributions in excess of the government mandated limitations imposed in the 401(k) savings plan and money purchase retirement plan.

Vesting in the Company’s contributions in the 401(k) savings plan, the money purchase retirement plan, the non-qualified retirement savings plan and the non-qualified restorative retirement savings plan occurs at the rate of 20 percent for every completed year of employment. Upon a change in control of ownership of APA, immediate and full vesting occurs.

The aggregate annual cost to the Company of all U.S. and international savings plans, the money purchase retirement plan, non-qualified retirement savings plan, and non-qualified restorative retirement savings plan was $44 million, $40 million, and $31 million for 2023, 2022, and 2021, respectively.

The Company also provides a funded noncontributory defined benefit pension plan (U.K. Pension Plan) covering certain employees of the Company’s North Sea operations in the U.K. The plan provides defined pension benefits based on years of service and final salary. The plan applies only to employees who were part of BP North Sea’s pension plan as of April 2, 2003, prior to the acquisition of BP North Sea by the Company effective July 1, 2003.

Additionally, the Company offers postretirement medical benefits to U.S. employees who meet certain eligibility requirements. Eligible participants receive medical benefits up until the age of 65 or at the date they become eligible for Medicare, provided the participant remits the required portion of the cost of coverage. The plan is contributory with participants’ contributions adjusted annually. The postretirement benefit plan does not cover benefit expenses once a covered participant becomes eligible for Medicare.


	2023						2022						2021
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits

	(In millions)
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	$	108		$	15		$	211		$	20		$	233		$	20
Service cost	1			1			2			1			3			1
Interest cost	5			1			3			—			3			—
Foreign currency exchange rates	6			—			(21)			—			(2)			—
Actuarial losses (gains)	3			—			(79)			(5)			(5)			1
Plan settlements	—			—			—			—			(17)			—
Benefits paid	(5)			(3)			(8)			(3)			(4)			(4)
Retiree contributions	—			1			—			2			—			2
Projected benefit obligation at end of year	118			15			108			15			211			20
Change in Plan Assets
Fair value of plan assets at beginning of year	137			—			254			—			262			—
Actual return (loss) on plan assets	8			—			(87)			—			11			—
Foreign currency exchange rates	8			—			(26)			—			(3)			—
Employer contributions	2			1			4			2			5			2
Plan settlements	—			—			—			—			(17)			—
Benefits paid	(5)			(3)			(8)			(4)			(4)			(4)
Retiree contributions	—			2			—			2			—			2
Fair value of plan assets at end of year	150			—			137			—			254			—
Funded status at end of year	$	32		$	(15)		$	29		$	(15)		$	43		$	(20)
Amounts recognized in Consolidated Balance Sheet
Current liability	$	—		$	(2)		$	—		$	(2)		$	—		$	(2)
Non-current asset (liability)	32			(13)			29			(13)			43			(18)
	$	32		$	(15)		$	29		$	(15)		$	43		$	(20)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$	(12)		$	16		$	(10)		$	18		$	1		$	14

Weighted Average Assumptions used as of December 31
Discount rate	4.80		%	5.00		%	5.00		%	5.29		%	1.80		%	2.57		%
Salary increases	4.60		%	N/A			4.70		%	N/A			4.90		%	N/A
Expected return on assets	4.80		%	N/A			4.70		%	N/A			1.90		%	N/A
Healthcare cost trend
Initial	N/A			6.25		%	N/A			6.50		%	N/A			6.25		%
Ultimate in 2030	N/A			5.25		%	N/A			5.25		%	N/A			5.00		%

As of December 31, 2023, 2022, and 2021, the accumulated benefit obligation for the U.K. Pension Plan was $112 million, $89 million, and $205 million, respectively.

The Company’s defined benefit pension plan assets are held by a non-related trustee who has been instructed to invest the assets under a cash flow driven investment strategy. The Company intends to invest in primarily low risk debt securities that will provide a reasonable rate of return focused on cash flow timing such that the benefits promised to members are provided when due. The U.K. Pension Plan policy is to target an ongoing funding level of 100 percent through prudent investments and includes policies and strategies such as investment goals, risk management practices, and permitted and prohibited investments. A breakout of allocations for the Company's plan asset holdings are summarized below:


	Percentage of Plan Assets at Year-End
	2023		2022
Asset Category
Global equities	—	%	6	%
Multi-asset credit	59	%	40	%
Nominal bonds	6	%	24	%
Inflation-linked bonds	33	%	28	%
Cash	2	%	2	%
Total	100	%	100	%

The plan’s assets do not include any direct ownership of equity or debt securities of the Company. The fair value of plan assets at December 31, 2023 and 2022 are based upon unadjusted quoted prices for identical instruments in active markets, which is a Level 1 fair value measurement. The following tables present the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets at December 31, 2023 and 2022:


	December 31,
	2023		2022

	(In millions)
Asset Category
Global equities	$	—	$	9
Multi-asset credit	88		55
Nominal bonds	9		32
Inflation-linked bonds	50		39
Cash	3		2
Total	$	150	$	137

The expected long-term rate of return on assets assumptions are derived relative to the yield on long-dated fixed-interest bonds issued by the U.K. government (gilts). For equities, outperformance relative to gilts is assumed to be 3.5 percent per year.


	2023						2022						2021
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits

	(In millions)
Components of Net Periodic Benefit Cost
Service cost	$	1		$	1		$	2		$	1		$	3		$	1
Interest cost	5			1			3			—			3			—
Expected return on assets	(7)			—			(4)			—			(4)			—
Amortization of loss	—			(2)			—			(1)			—			(1)
Settlement loss	—			—			—			—			—			—
Net periodic benefit cost	$	(1)		$	—		$	1		$	—		$	2		$	—
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	5.00		%	5.29		%	1.80		%	2.57		%	1.40		%	2.06		%
Salary increases	4.70		%	N/A			4.90		%	N/A			4.50		%	N/A
Expected return on assets	4.70		%	N/A			1.90		%	N/A			1.50		%	N/A
Healthcare cost trend
Initial	N/A			6.50		%	N/A			6.25		%	N/A			6.00		%
Ultimate in 2030	N/A			5.25		%	N/A			5.00		%	N/A			5.00		%

The Company expects to contribute approximately $2 million to its pension plan and $2 million to its postretirement benefit plan in 2024. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:


	Pension Benefits		Postretirement Benefits

	(In millions)
2024	$	5	$	2
2025	5		2
2026	5		1
2027	6		1
2028	6		1
Years 2029-2033	34		6

- Definition

The entire disclosure for retirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 70
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480794/715-70-50-1

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 17
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480482/715-20-55-17

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(03)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(i)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (q)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (l)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org//715/tableOfContent

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
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-Subparagraph (o)
-Publisher FASB
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
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-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480126/715-20-S99-2

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 60
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480266/715-60-50-3

+ Details

CAPITAL STOCK - Net Income Per Common Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Basic:
Income attributable to common stock	$ 2,855	$ 3,674	$ 973
Income attributable to common stock (in shares)	308	332	374
Income attributable to common stock (in USD per share)	$ 9.26	$ 11.05	$ 2.60
Earnings Per Share, Diluted [Abstract]
Income attributable to common stock	$ 2,855	$ 3,674	$ 973
Income attributable to common stock (in shares)	309	333	375
Income attributable to common stock (in USD per share)	$ 9.25	$ 11.02	$ 2.59
Stock compensation awards
Weighted Average Number of Shares Outstanding, Diluted, Adjustment [Abstract]
Stock compensation awards	$ 0	$ 0	$ 0
Stock compensation awards (in shares)	1	1	1
Stock compensation awards (in USD per share)	$ (0.01)	$ (0.03)	$ (0.01)

INCOME TAXES - Additional Information (Details) - USD ($) shares in Millions, $ in Millions			1 Months Ended		3 Months Ended	12 Months Ended
	Mar. 11, 2022	Jan. 14, 2022	Dec. 31, 2023	Mar. 31, 2022	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax [Line Items]
Shares sold (in shares)					4.0
Tax adjustments attributable to BCP Business Combination						$ 0	$ 126	$ 0
Deferred tax assets, future taxable income estimation, positive income, period						3 years
Deferred income tax benefit						$ 1,708	0	0
Decrease of valuation allowances						2,300	1,000	89
Net interest expense carryforward			$ 580			580
Tax expense recorded for interest and penalties						2	1	1
Accrued for payment of interest and penalties			$ 7			7	5	4
Increase (decrease) of reserve for uncertain tax positions						4	(27)	23
BCP Business Combination
Income Tax [Line Items]
Tax adjustments attributable to BCP Business Combination						126
Kinetik
Income Tax [Line Items]
Shares sold (in shares)	4.0		7.5	4.0
Apache Midstream LLC
Income Tax [Line Items]
Stock exchanged during period (in shares)		12.5
ALTM
Income Tax [Line Items]
Stock exchanged during period (in shares)		12.5
Foreign
Income Tax [Line Items]
Remeasurement of deferred tax liability						174	208
Decrease of valuation allowances						(10)	167	(7)
Net operating losses			$ 119			119
Tax credit carryforward, amount			2,204			2,204
U.S.
Income Tax [Line Items]
Decrease of valuation allowances						2,235	706	97
Net operating losses			8,027			8,027
Operating loss carryforwards subject to annual limitation			107			$ 107
Capital loss carryforward carryover period						5 years
U.S. \| Capital Loss Carryforward
Income Tax [Line Items]
Tax credit carryforward, expired amount						$ 1,700
Tax credit carryforward, amount			34			34
State
Income Tax [Line Items]
Decrease of valuation allowances						63	$ 111	$ (1)
Net operating losses			$ 6,553			$ 6,553

RETIREMENT AND DEFERRED COMPENSATION PLANS - Fair Values of Plan Assets for Each Major Asset Category Based on Nature and Significant Concentration of Risks in Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 150	$ 137
Global equities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	9
Cash
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3	2
Multi-asset credit
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	88	55
Nominal bonds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9	32
Inflation-linked bonds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 50	$ 39

- Definition

Amount of asset segregated and restricted to provide benefit under defined benefit plan. Asset includes, but is not limited to, stock, bond, other investment, earning from investment, and contribution by employer and employee.

+ References + Details

INCOME TAXES - Summary of Valuation Allowance Changes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Balance at beginning of year	$ 4,918	$ 5,902	$ 5,991
Increase (decrease) of valuation allowances	(2,300)	(1,000)	(89)
Balance at end of year	2,630	4,918	5,902
State
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Increase (decrease) of valuation allowances	(63)	(111)	1
U.S.
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Increase (decrease) of valuation allowances	(2,235)	(706)	(97)
Foreign
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Increase (decrease) of valuation allowances	$ 10	$ (167)	$ 7

CAPITAL STOCK

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

CAPITAL STOCK

REDEEMABLE NONCONTROLLING INTEREST — ALTUS

Preferred Units Issuance

Classification

Measurement

Common Stock Outstanding

The following table provides changes to the Company’s common shares outstanding for the years ended December 31, 2023, 2022, and 2021:


	For the Year Ended December 31,
	2023	2022	2021
Balance, beginning of year	311,559,149	346,930,765	377,482,630
Shares issued for stock-based compensation plans:
Treasury shares issued	2,016	1,996	3,133
Common shares issued	725,914	791,381	649,231
Treasury shares acquired	(8,711,178)	(36,164,993)	(31,204,229)
Balance, end of year	303,575,901	311,559,149	346,930,765

Net Income per Common Share

The following table provides a reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2023, 2022, and 2021:


	2023					2022					2021
	Income		Shares	Per Share		Income		Shares	Per Share		Income		Shares	Per Share

	(In millions, except per share amounts)
Basic:


Income attributable to common stock	$	2,855	308	$	9.26	$	3,674	332	$	11.05	$	973	374	$	2.60
Effect of Dilutive Securities:
Stock compensation awards	$	—	1	$	(0.01)	$	—	1	$	(0.03)	$	—	1	$	(0.01)
Diluted:


Income attributable to common stock	$	2,855	309	$	9.25	$	3,674	333	$	11.02	$	973	375	$	2.59

Stock Repurchase Program

The Company is not obligated to acquire any additional shares. Shares may be purchased either in the open market or through privately held negotiated transactions.

Common Stock Dividend

Stock Compensation Plans


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Stock-settled and cash-settled compensation expensed:
Lease operating expenses	$	27	$	82	$	39
Exploration	7		29		10
General and administrative	50		193		108
Total stock-settled and cash-settled compensation expensed	84		304		157
Stock-settled and cash-settled compensation capitalized	13		44		18
Total stock-settled and cash-settled compensation costs	$	97	$	348	$	175

Stock Options

The following table summarizes stock option activity for the years ended December 31, 2023, 2022, and 2021:


	2023			2022			2021
	Shares Under Option	Weighted Average Exercise Price		Shares Under Option	Weighted Average Exercise Price		Shares Under Option	Weighted Average Exercise Price

	(In thousands, except exercise price amounts)
Outstanding, beginning of year	2,078	$	57.71	3,012	$	63.79	3,537	$	72.10

Exercised	(12)	42.38		(99)	42.09		—	—
Forfeited	—	—		(2)	49.10		—	—
Expired	(601)	80.53		(833)	81.56		(525)	119.83
Outstanding, end of year(1)	1,465	48.48		2,078	57.71		3,012	63.79
Expected to vest	—	—		—	—		—	—
Exercisable, end of year(1)	1,465	48.48		2,078	57.71		3,012	63.79

(1)As of December 31, 2023, options exercisable and outstanding had a weighted average remaining contractual life of 3.1 years and aggregate intrinsic value of $33,000.

During the years ended December 31, 2023, 2022, and 2021, there were no options issued and 12,183, 98,646, and no options, respectively, exercised.

Restricted Stock Units and Restricted Stock Phantom Units

The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2023, 2022, and 2021:


	2023			2022			2021
	Units	Weighted Average Grant-Date Fair Value		Units	Weighted Average Grant-Date Fair Value		Units	Weighted Average Grant-Date Fair Value

	(In thousands, except per share amounts)
Non-vested, beginning of year	1,885	$	23.08	2,073	$	19.98	1,552	$	28.43
Granted	661	41.60		847	29.90		1,506	16.46
Vested(3)	(975)	23.31		(978)	22.39		(857)	29.13
Forfeited	(69)	32.44		(57)	23.49		(128)	19.78
Expired	(22)	27.81		—	—		—	—
Non-vested, end of year(1)(2)	1,480	30.69		1,885	23.08		2,073	19.98

(1)As of December 31, 2023, there was $15 million of total unrecognized compensation cost related to 1,479,880 unvested stock-settled restricted stock units.

(2)As of December 31, 2023, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.6 years.

(3)The grant date fair values of the stock-settled awards vested during 2023, 2022, and 2021 were approximately $23 million, $22 million, and $25 million, respectively.

The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2023, 2022, and 2021:


	For the Year Ended December 31,
	2023	2022	2021

	(In thousands)
Non-vested, beginning of year	5,709	6,402	4,423
Adjustment from ALTM transaction(1)	—	143	—
Granted(2)	1,972	2,568	4,441
Vested	(2,851)	(2,970)	(2,049)
Forfeited	(340)	(434)	(413)
Expired	(12)	—	—
Non-vested, end of year(3)	4,478	5,709	6,402

(3)The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2023 was approximately $54 million.

Performance Program

The following table summarizes cash-settled conditional restricted stock phantom unit activity for the years ended December 31, 2023, 2022, and 2021:


	For the Year Ended December 31,
	2023	2022	2021

	(In thousands)
Non-vested, beginning of year	4,835	4,531	3,417
Granted	1,536	1,676	1,782
Vested	(1,593)	(656)	(76)
Forfeited	(99)	(106)	(240)
Expired	(50)	(610)	(352)
Non-vested, end of year(1)	4,629	4,835	4,531

(1)As of December 31, 2023, the outstanding liability for the unvested cash-settled conditional restricted stock phantom units that had not been recognized was approximately $24 million.

- Definition

The entire disclosure for equity.

+ References

+ Details

CONSOLIDATED BALANCE SHEET - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
CURRENT ASSETS:
Cash and cash equivalents	$ 87	$ 245
Receivables, net of allowance of $114 and $117	1,610	1,466
Other current assets (Note 5)	765	997
Total current assets	2,462	2,708
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of successful efforts accounting:	44,860	42,356
Gathering, processing, and transmission facilities	448	449
Other	634	613
Less: Accumulated depreciation, depletion, and amortization	(35,904)	(34,406)
Property and equipment, net	10,038	9,012
OTHER ASSETS:
Equity method interests (Note 6)	437	624
Decommissioning security for sold Gulf of Mexico properties (Note 11)	21	217
Deferred tax asset (Note 10)	1,758	39
Deferred charges and other	528	547
Assets	15,244	13,147
CURRENT LIABILITIES:
Accounts payable	658	771
Current debt	2	2
Other current liabilities (Note 7)	1,744	2,143
Total current liabilities	2,404	2,916
LONG-TERM DEBT (Note 9)	5,186	5,451
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Deferred tax liability (Note 10)	371	314
Asset retirement obligation (Note 8)	2,362	1,940
Decommissioning contingency for sold Gulf of Mexico properties (Note 11)	764	738
Other	466	443
Total deferred credits and other noncurrent liabilities	3,963	3,435
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 420,595,901 and 419,869,987 shares issued, respectively	263	262
Paid-in capital	11,126	11,420
Accumulated deficit	(2,959)	(5,814)
Treasury stock, at cost, 117,020,000 and 108,310,838 shares, respectively	(5,790)	(5,459)
Accumulated other comprehensive income	15	14
APA SHAREHOLDERS’ EQUITY	2,655	423
TOTAL EQUITY	3,691	1,345
TOTAL LIABILITIES AND EQUITY	15,244	13,147
Noncontrolling interest - Egypt
EQUITY:
Noncontrolling interest	$ 1,036	$ 922

DEBT AND FINANCING COSTS - Overview (Details) - USD ($) $ in Millions			12 Months Ended
	Oct. 17, 2022	Jan. 18, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
(Gain) loss from extinguishment of debt			$ (9)	$ 67	$ 104
2.625% notes due 2023 \| Senior Notes
Debt Instrument [Line Items]
Current maturities	$ 123
Debt interest rate	2.625%
Redemption price, percentage of principal amount redeemed	100.00%
Senior Notes \| 3.25% notes due 2022
Debt Instrument [Line Items]
Current maturities		$ 213
Debt interest rate		3.25%
Redemption price, percentage of principal amount redeemed		100.00%
Open Market Repurchase \| Senior Notes
Debt Instrument [Line Items]
Debt repurchased principle amount			74	15	22
Debt instrument repurchase program			65	16	20
Discount (premium) to par of debt repurchase			10	1	2
(Gain) loss from extinguishment of debt			$ (9)	1	(1)
Debt Repurchase, Cash Tender Offers \| Senior Notes
Debt Instrument [Line Items]
Debt repurchased principle amount				1,100	1,700
Debt instrument repurchase program				1,200	1,800
(Gain) loss from extinguishment of debt				66	105
Unamortized debt issuance costs and discount				$ 11	$ 11

STATEMENT OF CONSOLIDATED OPERATIONS - USD ($)
shares in Millions

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Derivative instrument gains (losses), net

$ 99,000,000

$ (114,000,000)

$ 94,000,000

Gain on divestitures, net

8,000,000

1,180,000,000

67,000,000

Losses on previously sold Gulf of Mexico properties

(212,000,000)

(157,000,000)

(446,000,000)

Other, net

18,000,000

148,000,000

228,000,000

Total revenues and other

8,192,000,000

12,132,000,000

7,928,000,000

OPERATING EXPENSES:

Lease operating expenses

^[1]

1,436,000,000

1,444,000,000

1,241,000,000

Taxes other than income

207,000,000

268,000,000

204,000,000

Exploration

195,000,000

305,000,000

155,000,000

General and administrative

351,000,000

483,000,000

376,000,000

Transaction, reorganization, and separation

15,000,000

26,000,000

22,000,000

Depreciation, depletion, and amortization

1,540,000,000

1,233,000,000

1,360,000,000

Asset retirement obligation accretion

116,000,000

117,000,000

113,000,000

Impairments

61,000,000

208,000,000

Financing costs, net

312,000,000

379,000,000

514,000,000

Total operating expenses

5,309,000,000

6,398,000,000

6,037,000,000

NET INCOME BEFORE INCOME TAXES

2,883,000,000

5,734,000,000

1,891,000,000

Current income tax provision

1,338,000,000

1,507,000,000

652,000,000

Deferred income tax provision (benefit)

(1,662,000,000)

145,000,000

(74,000,000)

NET INCOME INCLUDING NONCONTROLLING INTERESTS

3,207,000,000

4,082,000,000

1,313,000,000

Net income (loss) attributable to Altus Preferred Unit limited partners

(70,000,000)

162,000,000

NET INCOME ATTRIBUTABLE TO COMMON STOCK

$ 2,855,000,000

$ 3,674,000,000

$ 973,000,000

NET INCOME PER COMMON SHARE:

Basic (in USD per share)

$ 9.26

$ 11.05

$ 2.60

Diluted (in USD per share)

$ 9.25

$ 11.02

$ 2.59

WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:

Basic (in shares)

308

332

374

Diluted (in shares)

309

333

375

Noncontrolling interest - Egypt

OPERATING EXPENSES:

Net income (loss) attributable to noncontrolling interest

$ 352,000,000

$ 464,000,000

$ 174,000,000

Noncontrolling interest - Altus

OPERATING EXPENSES:

Net income (loss) attributable to noncontrolling interest

14,000,000

4,000,000

Oil and gas

Total revenues

8,279,000,000

11,075,000,000

7,985,000,000

Oil and gas, excluding purchased

Total revenues

^[1]

7,385,000,000

9,220,000,000

6,498,000,000

OPERATING EXPENSES:

Gathering, processing, and transmission & purchased oil and gas costs

^[1]

334,000,000

367,000,000

264,000,000

Purchased oil and gas costs

Total revenues

^[1]

894,000,000

1,855,000,000

1,487,000,000

OPERATING EXPENSES:

Gathering, processing, and transmission & purchased oil and gas costs

^[1]

$ 742,000,000

$ 1,776,000,000

$ 1,580,000,000

[1]	(1) For related party transactions associated with Kinetik, refer to Note 6—Equity Method Interest for further detail.

DEBT AND FINANCING COSTS

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

DEBT AND FINANCING COSTS

Overview

The debt of APA and Apache is senior unsecured debt and has equal priority with respect to the payment of both principal and interest. All indentures of Apache for the notes and debentures described below place certain restrictions on Apache, including limits on Apache’s ability to incur debt secured by certain liens. Certain of these indentures also restrict Apache’s ability to enter into certain sale and leaseback transactions and give holders the option to require Apache to repurchase outstanding notes and debentures upon certain changes in control. None of the indentures contain prepayment obligations in the event of a decline in credit ratings.

During 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $9 million gain on these repurchases. The repurchases were partially financed by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility.

On October 17, 2022, Apache redeemed the outstanding $123 million outstanding principal amount of 2.625% notes due January 15, 2023, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed in part by Apache’s borrowing under the Company’s U.S. dollar-denominated revolving credit facility.

During 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of an aggregate $1 million. The Company recognized a $1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.

During 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.

On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility.

During 2021, Apache closed cash tender offers for certain outstanding notes, accepting for purchase $1.7 billion aggregate principal amount of notes covered by the tender offers. Apache paid holders an aggregate cash purchase price of $1.8 billion, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $105 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs, in connection with the note purchases.

During 2021, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $22 million for an aggregate purchase price of $20 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $2 million. The Company recognized a $1 million net gain on extinguishment of debt as part of these transactions.

The Company records gains and losses on extinguishment of debt in “Financing costs, net” in the Company’s statement of consolidated operations.

The following table presents the carrying value of the Company’s debt as of December 31, 2023 and 2022:


	December 31,
	2023		2022

	(In millions)

4.625% notes due 2025(1)	$	51	$	51
7.7% notes due 2026	78		78
7.95% notes due 2026	132		132
4.875% due 2027(1)	108		108
4.375% notes due 2028(1)	325		325
7.75% notes due 2029(1)(2)	235		235
4.25% notes due 2030(1)	516		579
6.0% notes due 2037(1)	443		443
5.1% notes due 2040(1)	1,333		1,333
5.25% notes due 2042(1)	399		399
4.75% notes due 2043(1)	428		428
4.25% notes due 2044(1)	211		221
7.375% debentures due 2047	150		150
5.35% notes due 2049(1)	387		387
7.625% debentures due 2096	39		39
Apache notes and debentures before unamortized discount and debt issuance costs(3)	4,835		4,908


Syndicated credit facilities(4)	372		566
Apache finance lease obligations	32		34
Unamortized discount	(26)		(27)
Debt issuance costs	(25)		(28)
Total debt	5,188		5,453
Current maturities	(2)		(2)
Long-term debt	$	5,186	$	5,451

(1)These notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium, except that the 7.75% notes due 2029 are only redeemable as whole for principal and accrued interest in the event of certain Canadian tax law changes. The remaining notes and debentures are not redeemable.

(2)Assumed by Apache in August 2017 as permitted by terms of these notes originally issued by a subsidiary and guaranteed by Apache.

(3)The fair values of Apache’s notes and debentures were $4.3 billion and $4.2 billion as of December 31, 2023 and 2022, respectively. The Company uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

(4)The carrying amount of borrowings on credit facilities approximates fair value because the interest rates are variable and reflective of market rates.

Maturities for the Company’s notes and debentures excluding discount and debt issuance costs as of December 31, 2023 are as follows:


	(In millions)
2024	$	—
2025	51
2026	210
2027	108
2028	325
Thereafter	4,141
Notes and debentures, excluding discounts and debt issuance costs	$	4,835

Financing Costs, Net

The following table presents the components of the Company’s financing costs, net:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Interest expense	$	351	$	332	$	419
Amortization of debt issuance costs	4		8		8
Capitalized interest	(24)		(18)		(9)
Loss (gain) on extinguishment of debt	(9)		67		104
Interest income	(10)		(10)		(8)
Financing costs, net	$	312	$	379	$	514

Debt issuance costs are charged to financing costs over the life of the related debt issuances. Discount amortization of $1 million, $2 million, and $6 million was recorded as interest expense in 2023, 2022, and 2021, respectively.

Uncommitted Lines of Credit

Each of the Company and Apache from time to time has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of December 31, 2023 and 2022, there were no outstanding borrowings under these facilities. As of December 31, 2023, there were £416 million and $2 million in letters of credit outstanding under these facilities. As of December 31, 2022, there were £199 million and $17 million in letters of credit outstanding under these facilities.

Unsecured 2022 Committed Bank Credit Facilities

On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes that replaced and refinanced Apache’s 2018 unsecured syndicated credit agreement (the Former Facility).

•One agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). The Company may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

•The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

In connection with the Company’s entry into the USD Agreement and the GBP Agreement (each, a 2022 Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under the USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a 2022 Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each 2022 Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.

As of December 31, 2023, there were $372 million of borrowings under the USD Agreement and an aggregate £348 million in letters of credit outstanding under the GBP Agreement. As of December 31, 2023, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2022, there were $566 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £652 million in letters of credit outstanding under the GBP Agreement. The letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which require such support while Apache’s credit rating by Standard & Poor’s remains below BBB; on March 26, 2020, Standard & Poor’s reduced Apache’s rating from BBB to BB+, which was affirmed in 2023.

All borrowings under the USD Agreement bear interest at one of two per annum rate options selected by the borrower, being either an alternate base rate (as defined), plus a margin ranging from 0.10% to 0.675% (Base Rate Margin), or an adjusted term SOFR rate (as defined), plus a margin varying from 1.10% to 1.675% (Applicable Margin). All borrowings under the GBP Agreement bear interest at an adjusted rate per annum determined by reference to the Sterling Overnight Index Average published by the Bank of England, plus the Applicable Margin. Each 2022 Agreement also requires the borrower to pay quarterly a facility fee on total commitments. Margins and facility fees are at varying rates per annum determined by reference to the senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA, or if such indebtedness is not rated and the Apache guaranty is in effect, of Apache (Long-Term Debt Rating). As of December 31, 2023, Apache’s Long-Term Debt Rating applied, and the Base Rate Margin was 0.40%, the Applicable Margin was 1.40%, and the facility fee was 0.225%.

A commission is payable quarterly to lenders under each 2022 Agreement on the face amount of each outstanding letter of credit at a per annum rate equal to the Applicable Margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks.

Borrowers under each 2022 Agreement, which may include certain subsidiaries of APA, may borrow, prepay, and reborrow loans and obtain letters of credit, and APA may obtain letters of credit for the account of its subsidiaries, in each case subject to representations and warranties, covenants, and events of default substantially similar to those in the Former Facility, such as:

•A financial covenant requires APA to maintain an adjusted debt-to-capital ratio of not greater than 60 percent at the end of any fiscal quarter. For purposes of this calculation, capital continues to exclude the effects of non-cash write-downs, impairments, and related charges occurring after June 30, 2015. At December 31, 2023, APA’s debt-to-capital ratio as calculated under each 2022 Agreement was 20 percent.

•A negative covenant restricts the ability of APA and its subsidiaries to create liens securing debt on their hydrocarbon-related assets, with exceptions for liens typically arising in the oil and gas industry; liens securing debt incurred to finance the acquisition, construction, improvement, or capital lease of assets, provided that such debt, when incurred, does not exceed the subject purchase price and costs, as applicable, and related expenses; liens on subsidiary assets located outside of the U. S. and Canada; and liens arising as a matter of law, such as tax and mechanics’ liens. Liens on assets also are permitted if debt secured thereby does not exceed 15 percent of APA’s consolidated net tangible assets or approximately $1.9 billion as of December 31, 2023.

•Negative covenants restrict APA’s ability to merge with another entity unless it is the surviving entity, a borrower’s disposition of substantially all of its assets, prohibitions on the ability of certain subsidiaries to make payments to borrowers, and guarantees by APA or certain subsidiaries of debt of non-consolidated entities in excess of the stated threshold.

•Lenders may accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches; if a borrower or certain subsidiaries defaults on other indebtedness in excess of the stated threshold, has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold, or has specified pension plan liabilities in excess of the stated threshold; or APA undergoes a specified change in control. Such acceleration and termination are automatic upon specified insolvency events of a borrower or certain subsidiaries.

Consistent with the Former Facility, the 2022 Agreements do not require collateral, do not have a borrowing base, do not permit lenders to accelerate maturity or refuse to lend based on unspecified material adverse changes, and do not have borrowing restrictions or prepayment obligations in the event of a decline in credit ratings.

The Company was in compliance with the terms of each 2022 Agreement as of December 31, 2023.

Commercial Paper Program

On December 13, 2023, the Company established a commercial paper program under which it from time to time may issue in private placements exempt from registration under the Securities Act short-term unsecured promissory notes (the CP Notes) up to a maximum aggregate face amount of $1.8 billion outstanding at any time. The Company intends to use net proceeds of the CP Notes for general corporate purposes.

Payment of the CP Notes has been unconditionally guaranteed on an unsecured basis by Apache, such guarantee effective until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.

The CP Notes will be sold under customary market terms in the U.S. commercial paper market at a discount from par or at par and bear interest at rates determined at the time of issuance. The maturities of the CP Notes may vary but may not exceed 397 days from the date of issuance.

As of December 31, 2023, the Company had not issued any CP Notes.

Subsequent Event

On January 30, 2024, APA entered into a syndicated credit agreement under which the lenders have committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA (Credit Agreement). Subject to satisfaction of certain limited conditions, APA may borrow under the Credit Agreement to refinance certain indebtedness of Callon, upon or after closing of APA’s pending acquisition of Callon. Refer to Note 2 —Acquisitions and Divestitures for further detail.

Two tranches of term loans would be available to APA for borrowing only on the date of closing of transactions under the Merger Agreement and satisfaction of certain other conditions under the Credit Agreement (Closing Date); of the aggregate $2.0 billion in commitments, $1.5 billion is for term loans that would mature three years after the Closing Date (3-Year Tranche Loans) and $500 million is for term loans that would mature 364 days after the Closing Date (364-Day Tranche Loans).

Indebtedness of Callon that APA could refinance by borrowing under the Credit Agreement on the Closing Date includes indebtedness outstanding under (i) the Amended and Restated Credit Agreement, dated October 19, 2022, among Callon, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (Callon Credit Agreement), (ii) Callon’s 6.375% Senior Notes due 2026 (Callon’s 2026 Notes), (iii) Callon’s 8.00% Senior Notes due 2028 (Callon’s 2028 Notes), and (iv) Callon’s 7.500% Senior Notes due 2030 (Callon’s 2030 Notes, and together with the Callon Credit Agreement, Callon’s 2026 Notes, and Callon’s 2028 Notes, the Callon Indebtedness).

The Credit Agreement has limited conditions to funding on the Closing Date loans requested by APA in accordance with the Credit Agreement, such as consummation of the transactions under the Merger Agreement, no Company Material Adverse Effect (as defined in the Merger Agreement) has occurred, repayment of all indebtedness outstanding under the Callon Credit Agreement and Callon’s 2026 Notes, and Callon having no other material indebtedness for borrowed money except for Callon’s 2028 Notes and Callon’s 2030 Notes or as permitted under the Credit Agreement or the Merger Agreement.

Proceeds of loans made under the Credit Agreement may only be used to refinance the Callon Indebtedness and repay fees and expenses related to transactions under the Credit Agreement and the Merger Agreement. To the extent that borrowings by APA under the Credit Agreement are not so used on or before the date that is 120 days after the Closing Date, APA then must prepay the amount of such unused borrowings.

Apache has guaranteed obligations under the Credit Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than $1.0 billion.

If $400 million or more in aggregate principal amount of Callon’s 2028 Notes and Callon’s 2030 Notes remains outstanding on the date which is 120 days after the Closing Date, Callon then must guarantee APA’s obligations under the Credit Agreement effective until the aggregate outstanding principal amount of Callon’s 2028 Notes and Callon’s 2030 Notes first is less than $400 million.

APA may at any time prepay loans under the Credit Agreement. APA may at any time terminate, or from time to time reduce, the lenders’ commitments under the Credit Agreement. Unless previously terminated, the lenders’ commitments automatically terminate on the first to occur of: (i) the Closing Date, after giving effect to funding of each lender’s commitments on the Closing Date, (ii) APA’s acquisition of Callon pursuant to the Merger Agreement without loans being made under the Credit Agreement, (iii) termination of the Merger Agreement in accordance with its terms, and (iv) the Termination Date (as defined in, and may be extended pursuant to, the Merger Agreement).

All borrowings under the Credit Agreement would be in U.S. Dollars and bear interest at one of the following two rate options, as selected by APA, plus the indicated margin:

•One option is a base rate per annum equal to the greatest of (i) the applicable prime rate, (ii) the greater of the applicable federal funds rate and overnight bank funding rate, plus 0.50%, and (iii) an adjusted secured overnight financing rate published by the Federal Reserve Bank of New York (SOFR) for a one-month interest period plus 1.0%. The margin for this rate option (Term Base Rate Margin) is a rate per annum varying from 0.25% to 1.0% for 364-Day Tranche Loans, 0.375% to 1.125% for 3-Year Tranche Loans until the second anniversary of the Closing Date, and 0.625% to 1.375% for 3-Year Tranche Loans after the second anniversary of the Closing Date, in each case, based on the rating for senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA, or if such indebtedness is not rated and the Apache guaranty is in effect, of Apache. Apache’s Long-Term Debt Rating currently applies.

•The second option is an adjusted SOFR rate, plus a margin at a rate per annum varying from 1.25% to 2.0% for 364-Day Tranche Loans, 1.375% to 2.125% for 3-Year Tranche Loans until the second anniversary of the Closing Date, and 1.625% to 2.375% for 3-Year Tranche Loans after the second anniversary of the Closing Date, in each case, based on the Long-Term Debt Rating (Term Applicable Margin). For SOFR-based interest rates, APA may select an interest period of one, three, or six months.

Currently, the Term Base Rate Margin is 0.625% for 364-Day Tranche Loans and 0.75% for 3-Year Tranche Loans, and the Term Applicable Margin is 1.625% for 364-Day Tranche Loans and 1.75% for 3-Year Tranche Loans.

The Credit Agreement provides for a ticking fee payable by APA at a rate of 0.225% per annum on the daily average undrawn aggregate commitments thereunder; the ticking fee accrues during the period beginning on the date that is 90 days after January 3, 2024 to the earlier of (i) termination or expiration of the commitments or (ii) the Closing Date.

APA is subject to representations and warranties, covenants, and events of default under the Credit Agreement substantially similar to those in APA’s existing 2022 Agreements. The Credit Agreement does not permit lenders to accelerate maturity based on unspecified material adverse changes and does not have prepayment obligations in the event of a decline in credit ratings.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(c))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480678/235-10-S99-1

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 470
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org//470/tableOfContent

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (i)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1C

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1C

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1C

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1E
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1E

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1I
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1I

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1I
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1I

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1I
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1I

+ Details

BUSINESS SEGMENT INFORMATION - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 segment
Segment Reporting [Abstract]
Number of reporting segments	3

RETIREMENT AND DEFERRED COMPENSATION PLANS - Changes in Benefit Obligation, Fair Value of Plan Assets and Funded Status of Pension and Postretirement Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Change in Plan Assets
Fair value of plan assets at beginning of year	$ 137
Fair value of plan assets at end of year	150	$ 137
Pension Benefits
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	108	211	$ 233
Service cost	1	2	3
Interest cost	5	3	3
Foreign currency exchange rates	6	(21)	(2)
Actuarial losses (gains)	3	(79)	(5)
Plan settlements	0	0	(17)
Benefits paid	(5)	(8)	(4)
Retiree contributions	0	0	0
Projected benefit obligation at end of year	118	108	211
Change in Plan Assets
Fair value of plan assets at beginning of year	137	254	262
Actual return (loss) on plan assets	8	(87)	11
Foreign currency exchange rates	8	(26)	(3)
Employer contributions	2	4	5
Plan settlements	0	0	(17)
Benefits paid	(5)	(8)	(4)
Retiree contributions	0	0	0
Fair value of plan assets at end of year	150	137	254
Funded status at end of year	32	29	43
Amounts recognized in Consolidated Balance Sheet
Current liability	0	0	0
Non-current asset	32	29	43
Amounts recognized in Consolidated Balance Sheet	32	29	43
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$ (12)	$ (10)	$ 1
Weighted Average Assumptions used as of December 31
Discount rate	4.80%	5.00%	1.80%
Salary increases	4.60%	4.70%	4.90%
Expected return on assets	4.80%	4.70%	1.90%
Postretirement Benefits
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	$ 15	$ 20	$ 20
Service cost	1	1	1
Interest cost	1	0	0
Foreign currency exchange rates	0	0	0
Actuarial losses (gains)	0	(5)	1
Plan settlements	0	0	0
Benefits paid	(3)	(3)	(4)
Retiree contributions	1	2	2
Projected benefit obligation at end of year	15	15	20
Change in Plan Assets
Fair value of plan assets at beginning of year	0	0	0
Actual return (loss) on plan assets	0	0	0
Foreign currency exchange rates	0	0	0
Employer contributions	1	2	2
Plan settlements	0	0	0
Benefits paid	(3)	(4)	(4)
Retiree contributions	2	2	2
Fair value of plan assets at end of year	0	0	0
Funded status at end of year	(15)	(15)	(20)
Amounts recognized in Consolidated Balance Sheet
Current liability	(2)	(2)	(2)
Non-current liability	(13)	(13)	(18)
Amounts recognized in Consolidated Balance Sheet	(15)	(15)	(20)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$ 16	$ 18	$ 14
Weighted Average Assumptions used as of December 31
Discount rate	5.00%	5.29%	2.57%
Healthcare cost trend
Initial	6.25%	6.50%	6.25%
Ultimate in 2030	5.25%	5.25%	5.00%

CAPITAL STOCK - Performance Program Narrative (Details) - USD ($) $ in Thousands	1 Months Ended			12 Months Ended
	Jan. 31, 2024	Jan. 31, 2023	Jan. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jan. 31, 2021	Jan. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)				9,400,000
Compensation expense				$ 84,000	$ 304,000	$ 157,000
Stock-settled and cash-settled compensation capitalized				$ 13,000	$ 44,000	$ 18,000
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)				1,972,000	2,568,000	4,441,000
Phantom Units \| Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	2,356,255
Award, remeasurement basis (in shares)	1
Performance Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award performance period				3 years
Compensation expense				$ 2,000	$ 143,000	$ 57,000
Stock-settled and cash-settled compensation capitalized				$ 100	$ 21,000	$ 3,000
Performance Program \| Vesting, Tranche One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares vesting percentage				50.00%
Performance Program \| Vesting, Tranche Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares vesting percentage				50.00%
2020 Performance Program \| Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of awards authorized (in shares)								1,687,307
Number of awards outstanding (in shares)				999,896
Shares paid out as percentage of target				155.00%
2021 Performance Program \| Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of awards authorized (in shares)							1,959,856
Number of awards outstanding (in shares)				1,803,083
Shares paid out as percentage of target				118.00%
2022 Performance Program \| Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of awards authorized (in shares)			1,093,034
Number of awards outstanding (in shares)				1,040,100
2022 Performance Program \| Phantom Units \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded as percentage of target			0.00%
Shares authorized and available for grant (in shares)				0
2022 Performance Program \| Phantom Units \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded as percentage of target			200.00%
Shares authorized and available for grant (in shares)				2,080,200
2023 Performance Program \| Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of awards authorized (in shares)		822,200
Number of awards outstanding (in shares)				784,977
2023 Performance Program \| Phantom Units \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded as percentage of target		0.00%
Shares authorized and available for grant (in shares)				0
2023 Performance Program \| Phantom Units \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded as percentage of target		200.00%
Shares authorized and available for grant (in shares)				1,569,954
2024 Performance Program \| Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award performance period	3 years
Award, remeasurement basis (in shares)	1
Cash incentive amount	$ 14,000
2024 Performance Program \| Minimum \| Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash incentive payout amount	0
2024 Performance Program \| Maximum \| Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash incentive payout amount	$ 28,000
2024 Performance Program \| Phantom Units \| Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	644,399
2024 Performance Program \| Phantom Units \| Minimum \| Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)	0
2024 Performance Program \| Phantom Units \| Maximum \| Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)	1,288,798

OTHER CURRENT ASSETS

12 Months Ended

Dec. 31, 2023

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

OTHER CURRENT ASSETS

The following table provides detail of the Company’s other current assets as of December 31:


	2023		2022

	(In millions)
Inventories	$	453	$	427
Drilling advances	88		89
Prepaid assets and other	46		31
Current decommissioning security for sold Gulf of Mexico assets	178		450
Total Other current assets	$	765	$	997

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2023
Audit Information [Abstract]
Auditor Name	Ernst & Young LLP
Auditor Location	Houston, Texas
Auditor Firm ID	42

DEBT AND FINANCING COSTS - Schedule of Long Term Debt by Maturity (Details) $ in Millions	Dec. 31, 2023 USD ($)
Debt Disclosure [Abstract]
2024	$ 0
2025	51
2026	210
2027	108
2028	325
Thereafter	4,141
Notes and debentures, excluding discounts and debt issuance costs	$ 4,835

ACQUISITIONS AND DIVESTITURES - 2024 Activity (Details) - Callon Petroleum Company - Subsequent Event - USD ($) $ / shares in Units, $ in Billions	Jan. 04, 2024	Jan. 03, 2024
Business Acquisition [Line Items]
Consideration transferred		$ 4.5
Business acquisition, equity interests exchange ratio	1.0425
Share price (in USD per share)	$ 38.31
Business combination, ownership percentage by acquiree shareholders	19.00%
Business combination, ownership percentage by acquirer shareholders	81.00%
Business combination, liabilities incurred	$ 2.0

CAPITALIZED EXPLORATORY WELL COSTS - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 430	$ 259	$ 123
Suriname
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 421
North Sea
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year		$ 16

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	$ 5	$ 599
Proved			$ (157)
Unproved	20	66	29
Exploration	432	545	301
Development	2,262		1,086
Development		1,359
Costs incurred	2,719	2,569	1,259
Capitalized interest	24	18	9
Asset retirement costs	371	(136)	149
Egypt PSC modernization impacts – Proved and Unproved			(145)
PSC modernization impacts, reduction in proved properties			165
PSC modernization impacts, increase in unproved properties			20
PSC modernization impacts, incremental value			247
PSC modernization impacts, signature bonus			100
PSC modernization impacts, other post closing adjustments			2
United States
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	1	596
Proved			0
Unproved	20	66	9
Exploration	31	4	6
Development	1,148		545
Development		848
Costs incurred	1,200	1,514	560
Capitalized interest	0	0	0
Asset retirement costs	(4)	79	130
Egypt PSC modernization impacts – Proved and Unproved			0
EGYPT
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	4	3
Proved			(157)
Unproved	0	0	20
Exploration	226	169	86
Development	646		404
Development		568
Costs incurred	876	740	353
Capitalized interest	0	0	0
Asset retirement costs	0	0	0
Egypt PSC modernization impacts – Proved and Unproved			(145)
North Sea
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	0	0
Proved			0
Unproved	0	0	0
Exploration	44	61	39
Development	468		135
Development		(57)
Costs incurred	512	4	174
Capitalized interest	0	1	0
Asset retirement costs	375	(215)	19
Egypt PSC modernization impacts – Proved and Unproved			0
Other International
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	0	0
Proved			0
Unproved	0	0	0
Exploration	131	311	170
Development	0		2
Development		0
Costs incurred	131	311	172
Capitalized interest	24	17	9
Asset retirement costs	$ 0	$ 0	0
Egypt PSC modernization impacts – Proved and Unproved			$ 0

INCOME TAXES - Income Before Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
U.S.	$ 627	$ 2,675	$ 629
Foreign	2,256	3,059	1,262
NET INCOME BEFORE INCOME TAXES	$ 2,883	$ 5,734	$ 1,891

- Definition

Amount of income (loss) from continuing operations, including income (loss) from equity method investments, before deduction of income tax expense (benefit), and income (loss) attributable to noncontrolling interest.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04(11))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147483586/944-220-S99-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-22

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 30
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-30

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 31
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-31

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-05(b)(2))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479557/942-235-S99-1

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Section 25
-Paragraph 1
-SubTopic 20
-Topic 940
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481913/940-20-25-1

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 220
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(10))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147483621/220-10-S99-2

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 942
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-04(15))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147483589/942-220-S99-1

+ Details

NATURE OF OPERATIONS (Details)	12 Months Ended
NATURE OF OPERATIONS (Details)	Dec. 31, 2023 Area
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of geographical areas	3

ACQUISITIONS AND DIVESTITURES	12 Months Ended
ACQUISITIONS AND DIVESTITURES	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
ACQUISITIONS AND DIVESTITURES	ACQUISITIONS AND DIVESTITURES 2024 Activity On January 3, 2024, APA and Callon Petroleum Company (Callon) entered into a definitive agreement (the Merger Agreement), pursuant to which APA will acquire Callon in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon’s net debt. In this all-stock transaction, each eligible outstanding share of Callon common stock will be exchanged for 1.0425 shares of APA common stock, representing an implied value to each Callon share of $38.31 per share based on the closing price of APA common stock on January 3, 2024. After closing, existing APA shareholders are expected to own approximately 81 percent of the combined company, and existing Callon shareholders are expected to own approximately 19 percent of the combined company. APA expects to retire the existing debt at Callon and replace it with APA’s syndicated credit agreement, dated January 30, 2024, under which the lenders have committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA. Refer to Note 9—Debt and Financing Costs for further detail. The transaction has been unanimously approved by the boards of directors of both APA and Callon and is expected to close during the second quarter of 2024, subject to customary closing conditions, termination or expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, and approval of the transaction by shareholders of both APA and Callon. Upon the closing of the transaction, a representative from Callon will be appointed to the APA board of directors (Board of Directors). APA’s executive management team will lead the combined company, with the headquarters remaining in Houston, Texas. 2023 Activity In December 2023, the Company sold 7.5 million of its shares of Kinetik Class A Common Stock (Kinetik Shares) for cash proceeds of $228 million. Refer to Note 6—Equity Method Interests for further detail. During 2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $20 million. During 2023, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $29 million, recognizing an aggregate gain of approximately $8 million upon closing of these transactions. 2022 Activity During the third quarter of 2022, the Company closed on the acquisition of oil and gas assets in the Delaware Basin for a total purchase price of $615 million after post-closing adjustments. Final cash settlements of $24 million were completed during 2023. The Company recorded $581 million for proved properties, $38 million for unproved leasehold, and $4 million for abandonment obligations. During 2022, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $37 million. During 2022, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $52 million, recognizing an aggregate gain of approximately $36 million, upon closing of these transactions. During 2022, the Company completed the sale of certain non-core mineral rights in the Delaware Basin. The Company received total cash proceeds of approximately $726 million after certain post-closing adjustments and recognized an associated gain of approximately $560 million. The BCP Business Combination was completed on February 22, 2022. As consideration for the contribution of the Contributed Interests, ALTM issued 50 million shares of Class C Common Stock (and Altus Midstream LP issued a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. ALTM’s stockholders continued to hold their existing shares of common stock. As a result of the transaction, the Contributor, or its designees, collectively owned approximately 75 percent of the issued and outstanding shares of ALTM common stock. Apache Midstream LLC, a wholly owned subsidiary of APA, which owned approximately 79 percent of the issued and outstanding shares of ALTM common stock prior to the BCP Business Combination, owned approximately 20 percent of the issued and outstanding shares of Kinetik common stock after the transaction closed. As a result of the BCP Business Combination, the Company deconsolidated ALTM on February 22, 2022 and recognized a gain of approximately $609 million that reflects the difference between the Company’s $193 million net effect of deconsolidating ALTM’s balance sheet and the $802 million fair value of the Company’s approximate 20 percent retained ownership in the combined entity. During the first quarter of 2022, the Company sold four million of its Kinetik Shares for cash proceeds of $224 million. Refer to Note 6—Equity Method Interests for further detail. 2021 Activity During the second quarter of 2021, the Company completed the sale of certain non-core assets in the Permian Basin with a net carrying value of $157 million for cash proceeds of $176 million and the assumption of asset retirement obligations of $44 million. The Company recognized a gain of approximately $63 million in connection with the sale. During 2021, the Company also completed the sale of other non-core assets and leasehold, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $80 million. The Company recognized a gain of approximately $4 million upon closing of these transactions. During 2021, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $9 million.

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST (Parenthetical) - $ / shares	3 Months Ended				12 Months Ended
	Sep. 30, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Stockholders' Equity [Abstract]
Common stock, dividends, per share (in USD per share)	$ 0.25	$ 0.125	$ 0.0625	$ 0.025	$ 1.00	$ 0.75	$ 0.2375

DEBT AND FINANCING COSTS - Subsequent Event (Details) - Subsequent Event	Jan. 30, 2024 USD ($) debt_tranche debt_interest_option
Delayed-Drawn Term Loan \| Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, face amount	$ 2,000,000,000
Debt instrument, number of tranches \| debt_tranche	2
Debt instrument, interest rate options \| debt_interest_option	2
Credit facility fee, percentage	0.225%
Debt instrument, ticking fee accrual terms, period	90 days
Delayed-Drawn Term Loan \| Unsecured Debt \| Apache Corp
Debt Instrument [Line Items]
Debt instrument guarantee terms, benchmark amount (less than)	$ 1,000,000,000
Delayed-Drawn Term Loan \| Unsecured Debt \| SOFR \| Term Base Rate Margin
Debt Instrument [Line Items]
Debt basis spread on variable rate	1.00%
Delayed-Drawn Term Loan \| Unsecured Debt \| Greater of the applicable federal funds rate and overnight bank funding rate \| Term Base Rate Margin
Debt Instrument [Line Items]
Debt basis spread on variable rate	0.50%
Delayed-Drawn Term Loan \| Senior Notes \| Callon Petroleum Company
Debt Instrument [Line Items]
Debt, guarantee terms, aggregate outstanding principal amount of acquiree's Notes, benchmark amount	$ 400,000,000
Debt instrument, guarantee terms, aggregate outstanding principal amount of acquiree's notes, period after closing date	120 days
Delayed-Drawn Term Loan, Three Year Tranche Loans \| Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, face amount	$ 1,500,000,000
Debt instrument, term	3 years
Delayed-Drawn Term Loan, Three Year Tranche Loans \| Unsecured Debt \| Term Base Rate Margin
Debt Instrument [Line Items]
Debt, margin rate	0.75%
Delayed-Drawn Term Loan, Three Year Tranche Loans \| Unsecured Debt \| Term Applicable Margin
Debt Instrument [Line Items]
Debt, margin rate	1.75%
Delayed-Drawn Term Loan, Three Year Tranche Loans \| Unsecured Debt \| Debt Instrument Maturity, Tranche One \| Minimum \| Term Base Rate Margin
Debt Instrument [Line Items]
Debt, margin rate	0.375%
Delayed-Drawn Term Loan, Three Year Tranche Loans \| Unsecured Debt \| Debt Instrument Maturity, Tranche One \| Maximum \| Term Base Rate Margin
Debt Instrument [Line Items]
Debt, margin rate	1.125%
Delayed-Drawn Term Loan, Three Year Tranche Loans \| Unsecured Debt \| Debt Instrument Maturity, Tranche Two \| Minimum \| Term Base Rate Margin
Debt Instrument [Line Items]
Debt, margin rate	0.625%
Delayed-Drawn Term Loan, Three Year Tranche Loans \| Unsecured Debt \| Debt Instrument Maturity, Tranche Two \| Maximum \| Term Base Rate Margin
Debt Instrument [Line Items]
Debt, margin rate	1.375%
Delayed-Drawn Term Loan, Three Year Tranche Loans \| Unsecured Debt \| SOFR \| Debt Instrument Maturity, Tranche One \| Minimum \| Term Applicable Margin
Debt Instrument [Line Items]
Debt basis spread on variable rate	1.375%
Delayed-Drawn Term Loan, Three Year Tranche Loans \| Unsecured Debt \| SOFR \| Debt Instrument Maturity, Tranche One \| Maximum \| Term Applicable Margin
Debt Instrument [Line Items]
Debt basis spread on variable rate	2.125%
Delayed-Drawn Term Loan, Three Year Tranche Loans \| Unsecured Debt \| SOFR \| Debt Instrument Maturity, Tranche Two \| Minimum \| Term Applicable Margin
Debt Instrument [Line Items]
Debt basis spread on variable rate	1.625%
Delayed-Drawn Term Loan, Three Year Tranche Loans \| Unsecured Debt \| SOFR \| Debt Instrument Maturity, Tranche Two \| Maximum \| Term Applicable Margin
Debt Instrument [Line Items]
Debt basis spread on variable rate	2.375%
Delayed-Drawn Term Loan, 364-Day Tranche Loans \| Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, face amount	$ 500,000,000
Debt instrument, term	364 days
Delayed-Drawn Term Loan, 364-Day Tranche Loans \| Unsecured Debt \| Term Base Rate Margin
Debt Instrument [Line Items]
Debt, margin rate	0.625%
Delayed-Drawn Term Loan, 364-Day Tranche Loans \| Unsecured Debt \| Term Applicable Margin
Debt Instrument [Line Items]
Debt, margin rate	1.625%
Delayed-Drawn Term Loan, 364-Day Tranche Loans \| Unsecured Debt \| Minimum \| Term Base Rate Margin
Debt Instrument [Line Items]
Debt, margin rate	0.25%
Delayed-Drawn Term Loan, 364-Day Tranche Loans \| Unsecured Debt \| Maximum \| Term Base Rate Margin
Debt Instrument [Line Items]
Debt, margin rate	1.00%
Delayed-Drawn Term Loan, 364-Day Tranche Loans \| Unsecured Debt \| SOFR \| Minimum \| Term Applicable Margin
Debt Instrument [Line Items]
Debt basis spread on variable rate	1.25%
Delayed-Drawn Term Loan, 364-Day Tranche Loans \| Unsecured Debt \| SOFR \| Maximum \| Term Applicable Margin
Debt Instrument [Line Items]
Debt basis spread on variable rate	2.00%
6.375% Senior Notes Due 2026 \| Senior Notes \| Callon Petroleum Company
Debt Instrument [Line Items]
Debt interest rate	6.375%
8.00% Senior Notes Due 2028 \| Senior Notes \| Callon Petroleum Company
Debt Instrument [Line Items]
Debt interest rate	8.00%
7.500% Senior Notes Due 2030 \| Senior Notes \| Callon Petroleum Company
Debt Instrument [Line Items]
Debt interest rate	7.50%

COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

Legal Matters

The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls, which also may include controls related to the potential impacts of climate change. As of December 31, 2023, the Company has an accrued liability of approximately $83 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. The Company’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to the Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. With respect to material matters for which the Company believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.

Argentine Environmental Claims

On March 12, 2014, the Company and its subsidiaries completed the sale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad Anonima (YPF). As part of that sale, YPF assumed responsibility for all of the past, present, and future litigation in Argentina involving Company subsidiaries, except that Company subsidiaries have agreed to indemnify YPF for certain environmental, tax, and royalty obligations capped at an aggregate of $100 million. The indemnity is subject to specific agreed conditions precedent, thresholds, contingencies, limitations, claim deadlines, loss sharing, and other terms and conditions. On April 11, 2014, YPF provided its first notice of claims pursuant to the indemnity. Company subsidiaries have not paid any amounts under the indemnity but will continue to review and consider claims presented by YPF. Further, Company subsidiaries retain the right to enforce certain Argentina-related indemnification obligations against Pioneer Natural Resources Company (Pioneer) in an amount up to $45 million pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer.

Louisiana Restoration

Louisiana surface owners often file lawsuits or assert claims against oil and gas companies, including the Company, claiming that operators and working interest owners in the chain of title are liable for environmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to its original condition, regardless of the value of the underlying property. From time to time, restoration lawsuits and claims are resolved by the Company for amounts that are not material to the Company, while new lawsuits and claims are asserted against the Company. With respect to each of the pending lawsuits and claims, the amount claimed is not currently determinable or is not material. Further, the overall exposure related to these lawsuits and claims is not currently determinable. While adverse judgments against the Company are possible, the Company intends to actively defend these lawsuits and claims.

Starting in November of 2013 and continuing into 2023, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including the Company. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. Without acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, the Company agreed to settle with the State of Louisiana and Louisiana coastal Parishes to resolve any potential liability on the part of the Company for claims that were or could have been asserted by the coastal Parishes and/or the State of Louisiana in the pending litigation. The settlement is subject to court approval, which the parties hope to receive at some point in the first half of 2024. The consideration to be provided by the Company in the settlement will not have a material impact on the Company’s financial position. Following settlement of these various lawsuits, the Company will be a defendant in only one remaining coastal zone lawsuit, which has been filed by the City of New Orleans against a number of oil and gas operators.

Apollo Exploration Lawsuit

In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and area of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The trial court entered final judgment in favor of the Company, ruling that the plaintiffs take nothing by their claims and awarding the Company its attorneys’ fees and costs incurred in defending the lawsuit. The court of appeals affirmed in part and reversed in part the trial court’s judgment thereby reinstating some of plaintiffs’ claims. The Texas Supreme Court granted the Company’s petition for review and heard oral argument in October 2022. On April 28, 2023, the Texas Supreme Court reversed the court of appeals’ decision and remanded the case back to the court of appeals for further proceedings. After plaintiffs’ request for rehearing, on July 21, 2023, the Texas Supreme Court reaffirmed its reversal of the court of appeals’ decision and remand of the case back to the court of appeals for further proceedings.

Australian Operations Divestiture Dispute

Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the Company and its subsidiaries divested Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, the Company filed suit against Quadrant for breach of the Quadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and a counterclaim seeking approximately AUD $200 million in the aggregate. The Company will vigorously prosecute its claim while vigorously defending against Quadrant’s counter claims.

Canadian Operations Divestiture Dispute

Pursuant to a Sale and Purchase Agreement dated July 6, 2017 (Paramount SPA), the Company and its subsidiaries divested their remaining Canadian operations to Paramount Resources LTD (Paramount). Closing occurred on August 16, 2017. On September 11, 2019, four ex-employees of Apache Canada LTD on behalf of themselves and individuals employed by Apache Canada LTD on July 6, 2017, filed an Amended Statement of Claim in a matter styled Stephen Flesch et. al. v Apache Corporation et. al., No. 1901-09160 Court of Queen’s Bench of Alberta against the Company and others seeking class certification and a finding that the Paramount SPA amounted to a Change of Control of the Company, entitling them to accelerated vesting under the Company’s equity plans. In the suit, the class seeks approximately $60 million USD and punitive damages. Without acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, Apache has agreed to a settlement in the Flesch class action matter under which Apache will pay $7 million USD to resolve all claims against the Company asserted by the class. The settlement was approved by the court on October 26, 2023.

California and Delaware Litigation

On July 17, 2017, in three separate actions, San Mateo and Marin Counties, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County filed similar lawsuits against many of the same defendants. On January 22, 2018, the City of Richmond filed a similar lawsuit.

On September 10, 2020, the State of Delaware filed suit, individually and on behalf of the people of the State of Delaware, against over 25 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories.

The Company intends to challenge personal jurisdiction in California and to vigorously defend the Delaware lawsuit.

Kulp Minerals Lawsuit

On or about April 7, 2023, Apache was sued in a purported class action in New Mexico styled Kulp Minerals LLC v. Apache Corporation, Case No. D-506-CV-2023-00352 in the Fifth Judicial District. The Kulp Minerals case has not been certified and seeks to represent a group of owners allegedly owed statutory interest under New Mexico law as a result of purported late oil and gas payments. The amount of this claim is not yet reasonably determinable. The Company intends to vigorously defend against the claims asserted in this lawsuit.

Shareholder and Derivative Lawsuits

On February 23, 2021, a case captioned Plymouth County Retirement System v. Apache Corporation, et al. was filed in the United States District Court for the Southern District of Texas (Houston Division) against the Company and certain current and former officers. The complaint, which is a shareholder lawsuit styled as a class action, alleges that (1) the Company intentionally used unrealistic assumptions regarding the amount and composition of available oil and gas in Alpine High; (2) the Company did not have the proper infrastructure in place to safely and/or economically drill and/or transport those resources even if they existed in the amounts purported; (3) certain statements and omissions artificially inflated the value of the Company’s operations in the Permian Basin; and (4) as a result, the Company’s public statements were materially false and misleading. The Company intends to vigorously defend this lawsuit.

On February 21, 2023, a case captioned Steve Silverman, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. Then, on July 21, 2023, a case captioned Yang-Li-Yu, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. These cases have now been consolidated as In Re APA Corporation Derivative Litigation, Case No. 4:23-cv-00636 in the Southern District of Texas and purport to be derivative actions brought against senior management and Company directors over many of the same allegations included in the Plymouth County Retirement System matter and asserts claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. The defendants intend to vigorously defend these lawsuits.

Environmental Matters

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state, local, and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks.

The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company also conducts periodic reviews, on a Company-wide basis, to identify changes in its environmental risk profile. These reviews evaluate whether there is a probable liability, the amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, the Company may exclude a property from the acquisition, require the seller to remediate the property to the Company’s satisfaction, or agree to assume liability for the remediation of the property. The Company’s general policy is to limit any reserve additions to any incidents or sites that are considered probable to result in an expected remediation cost exceeding $300,000. Any environmental costs and liabilities that are not reserved for are treated as an expense when actually incurred. In the Company’s estimation, neither these expenses nor expenses related to training and compliance programs are likely to have a material impact on its financial condition.

As of December 31, 2023, the Company had an undiscounted reserve for environmental remediation of approximately $5 million.

On September 11, 2020, the Company received a Notice of Violation and Finding of Violation, and accompanying Clean Air Act Information Request, from the U.S. Environmental Protection Agency (EPA) following site inspections in April 2019 at several of the Company’s oil and natural gas production facilities in Lea and Eddy Counties, New Mexico. Then on December 29, 2020, the Company received a Notice of Violation and Opportunity to Confer, and accompanying Clean Air Act Information Request, from the EPA following helicopter flyovers in September 2019 of several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notices and information requests involved alleged emissions control and reporting violations. The Company cooperated with the EPA, responded to the information requests, and negotiated and entered into a consent decree to resolve the alleged violations in both New Mexico and Texas, which will be subject to court approval. The consideration to be provided by the Company in connection with the consent decree will not have a material impact on the Company’s financial position.

The Company is not aware of any environmental claims existing as of December 31, 2023, that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

Potential Decommissioning Obligations on Sold Properties

In 2013, Apache sold its Gulf of Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Following the 2018 reorganization of Fieldwood, Apache held two bonds (Bonds) and five Letters of Credit securing Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets.

On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets will be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOM Assets.

By letter dated April 5, 2022, replacing two prior letters dated September 8, 2021 and February 22, 2022, and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currently obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders on the other Legacy GOM Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOM Assets that were not included in GOM Shelf’s notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.

As of December 31, 2023, Apache has incurred $819 million in decommissioning costs related to Legacy GOM Assets. GOM Shelf did not, and has confirmed that it will not, reimburse Apache for these decommissioning costs. As a result, Apache has sought and will continue to seek reimbursement from its security for these costs. As of December 31, 2023, $293 million has been reimbursed from Trust A and $336 million has been reimbursed from the Letters of Credit. If GOM Shelf does not reimburse Apache for further decommissioning costs incurred with respect to Legacy GOM Assets, then Apache will continue to seek reimbursement from Trust A, to the extent of available funds, and thereafter, will seek reimbursement from the Bonds and the Letters of Credit until all such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets.

If the combination of GOM Shelf’s net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be required to perform or fund, or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, then Apache may be forced to use its available cash to fund the deficit.

As of December 31, 2023, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOM Assets it may be ordered to perform or fund ranges from $824 million to $1.2 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company has recorded a contingent liability of $824 million as of December 31, 2023, representing the estimated costs of decommissioning it may be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $764 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $60 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued.

As of December 31, 2023, the Company has also recorded a $199 million asset, which represents the remaining amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $21 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $178 million is reflected under “Other current assets.”

The Company recognized $212 million, $157 million, and $446 million during 2023, 2022, and 2021, respectively, of “Losses on previously sold Gulf of Mexico properties” to reflect the net impact of changes to the estimated decommissioning liability and decommissioning asset to the Company’s statement of consolidated operations.

On June 21, 2023, the two sureties that issued bonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation, Cause No. 2023-38238 in the 281st Judicial District Court, Harris County Texas. Insurers are seeking to prevent Apache from drawing on the Bonds and Letters of Credit and further allege that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. On July 20, 2023, the 281st Judicial District Court denied the Insurers’ request for a temporary injunction. On July 26, 2023, Apache removed the suit to the United States Bankruptcy Court for the Southern District of Texas (Houston Division) which subsequently held that the sureties’ state court lawsuit violated the terms of the Bankruptcy Confirmation Order and is void. Apache has drawn down the entirety of the Letters of Credit and is vigorously pursuing its claims against the sureties.

Leases and Contractual Obligations

The Company determines if an arrangement is an operating or finance lease at the inception of each contract. If the contract is classified as an operating lease, the Company records an ROU asset and corresponding liability reflecting the total remaining present value of fixed lease payments over the expected term of the lease agreement. The expected term of the lease may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. If the Company’s lease does not provide an implicit rate in the contract, the Company uses its incremental borrowing rate when calculating the present value. In the normal course of business, the Company enters into various lease agreements for real estate, drilling rigs, vessels, aircrafts, and equipment related to its exploration and development activities, which are typically classified as operating leases under the provisions of the standard. ROU assets are reflected within “Deferred charges and other assets” on the Company’s consolidated balance sheet, and the associated operating lease liabilities are reflected within “Other current liabilities” and “Other” within “Deferred Credits and Other Noncurrent Liabilities,” as applicable.

Operating lease expense associated with ROU assets is recognized on a straight-line basis over the lease term. Lease expense is reflected on the statement of consolidated operations commensurate with the leased activities and nature of the services performed. Gross fixed operating lease expense, inclusive of amounts billable to partners and other working interest owners, was $168 million, $145 million, and $128 million for the years ended 2023, 2022, and 2021, respectively. As allowed under the standard, the Company accounts for non-lease and lease components as a single lease component for all asset classes and has elected to exclude short-term leases (those with terms of 12 months or less) from the balance sheet presentation. Costs incurred for short-term leases were $71 million, $62 million, and $20 million in 2023, 2022, and 2021, respectively. In 2023 these costs primarily related to decommissioning work in the Gulf of Mexico. In 2022 and 2021, these costs were primarily related to drilling activities in Block 58 offshore Suriname.

Finance lease assets are included in “Property, Plant, and Equipment” on the consolidated balance sheet, and the associated finance lease liabilities are reflected within “Current debt” and “Long-term debt,” as applicable. Depreciation on the Company’s finance lease asset was $2 million in each of the years 2023, 2022, and 2021. Interest on the Company’s finance lease liability was $1 million, $2 million, and $2 million in 2023, 2022, and 2021, respectively.

The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2023:


	Operating Leases		Finance Lease
Weighted average remaining lease term	6.9 years		9.7 years
Weighted average discount rate	5.3	%	4.4	%

At December 31, 2023, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:


Net Minimum Commitments(1)	Operating Leases(2)		Finance Lease(3)		Purchase Obligations(4)(5)

	(In millions)
2024	$	116	$	3	$	250
2025	35		3		197
2026	21		4		766
2027	23		4		143
2028	22		4		141
Thereafter	129		23		208
Total future minimum payments	346		41		$	1,705
Less: imputed interest	(65)		(9)		N/A
Total lease liabilities	281		32		N/A
Current portion	116		2		N/A
Non-current portion	$	165	$	30	N/A

(1)Excludes commitments for jointly owned fields and facilities for which the Company is not the operator.

(3)Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building.

The lease liability reflected in the table above represents the Company’s fixed minimum payments that are settled in accordance with the lease terms. Actual lease payments during the period may also include variable lease components such as common area maintenance, usage-based sales taxes and rate differentials, or other similar costs that are not determinable at the inception of the lease. Gross variable lease payments, inclusive of amounts billable to partners and other working interest owners were $74 million, $90 million, and $64 million in 2023, 2022, and 2021, respectively.

BUSINESS SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2023

Segment Reporting [Abstract]

Schedule of Financial Segment Information

Financial information for each segment is presented below:


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream

	(In millions)
2023
Oil revenues	$	2,683	$	1,073	$	2,241	$	—	$	—	$	5,997
Natural gas revenues	346		237		297		—		—		880
Natural gas liquids revenues	—		28		480		—		—		508
Oil, natural gas, and natural gas liquids production revenues	3,029		1,338		3,018		—		—		7,385
Purchased oil and gas sales	—		—		894		—		—		894
	3,029		1,338		3,912		—		—		8,279
Operating Expenses:
Lease operating expenses	474		369		593		—		—		1,436
Gathering, processing, and transmission	33		52		249		—		—		334
Purchased oil and gas costs	—		—		742		—		—		742
Taxes other than income	—		—		207		—		—		207
Exploration(4)	119		19		14		—		43		195
Depreciation, depletion, and amortization	524		271		745		—		—		1,540
Asset retirement obligation accretion	—		76		40		—		—		116
Impairments	—		50		11		—		—		61
	1,150		837		2,601		—		43		4,631
Operating Income (Loss)	$	1,879	$	501	$	1,311	$	—	$	(43)	3,648
Other Income (Expense):
Gain on divestitures, net											8
Losses on previously sold Gulf of Mexico properties											(212)
Derivative instrument gains, net											99
Other											18
General and administrative											(351)
Transaction, reorganization, and separation											(15)
Financing costs, net											(312)
Income Before Income Taxes											$	2,883

Total Assets(3)	$	3,503	$	1,970	$	9,221	$	—	$	550	$	15,244
Net Property and Equipment	$	2,209	$	1,628	$	5,689	$	—	$	512	$	10,038
Additions to Net Property and Equipment	$	834	$	131	$	1,255	$	—	$	93	$	2,313


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream

	(In millions)
2022
Oil revenues	$	3,145	$	1,232	$	2,458	$	—	$	—	$	6,835
Natural gas revenues	370		281		918		—		—		1,569
Natural gas liquids revenues	6		45		768		—		(3)		816
Oil, natural gas, and natural gas liquids production revenues	3,521		1,558		4,144		—		(3)		9,220
Purchased oil and gas sales	—		—		1,850		5		—		1,855
Midstream service affiliate revenues	—		—		—		16		(16)		—
	3,521		1,558		5,994		21		(19)		11,075
Operating Expenses:
Lease operating expenses	526		404		515		—		(1)		1,444
Gathering, processing, and transmission	22		43		315		5		(18)		367
Purchased oil and gas costs	—		—		1,776		—		—		1,776
Taxes other than income	—		—		265		3		—		268
Exploration(4)	84		35		24		—		162		305
Depreciation, depletion, and amortization	400		238		593		2		—		1,233
Asset retirement obligation accretion	—		82		34		1		—		117

	1,032		802		3,522		11		143		5,510
Operating Income (Loss)	$	2,489	$	756	$	2,472	$	10	$	(162)	5,565
Other Income (Expense):
Gain on divestitures, net											1,180
Losses on previously sold Gulf of Mexico properties											(157)
Derivative instrument losses, net											(114)
Other											148
General and administrative											(483)
Transaction, reorganization, and separation											(26)
Financing costs, net											(379)
Income Before Income Taxes											$	5,734

Total Assets(3)	$	3,148	$	1,911	$	7,574	$	—	$	514	$	13,147
Net Property and Equipment	$	1,976	$	1,386	$	5,226	$	—	$	424	$	9,012
Additions to Net Property and Equipment	$	695	$	210	$	1,439	$	—	$	263	$	2,607


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream

	(In millions)
2021
Oil revenues	$	1,806	$	929	$	1,850	$	—	$	—	$	4,585
Natural gas revenues	270		183		754		—		—		1,207
Natural gas liquids revenues	9		24		676		—		(3)		706
Oil, natural gas, and natural gas liquids production revenues	2,085		1,136		3,280		—		(3)		6,498
Purchased oil and gas sales	—		—		1,476		11		—		1,487
Midstream service affiliate revenues	—		—		—		127		(127)		—
	2,085		1,136		4,756		138		(130)		7,985
Operating Expenses:
Lease operating expenses	469		383		391		—		(2)		1,241
Gathering, processing, and transmission	12		39		309		32		(128)		264
Purchased oil and gas costs	—		—		1,575		5		—		1,580
Taxes other than income	—		—		190		14		—		204
Exploration(4)	63		34		28		—		30		155
Depreciation, depletion, and amortization	524		270		554		12		—		1,360
Asset retirement obligation accretion	—		79		30		4		—		113
Impairments	26		22		—		160		—		208
	1,094		827		3,077		227		(100)		5,125
Operating Income (Loss)	$	991	$	309	$	1,679	$	(89)	$	(30)	2,860
Other Income (Expense):
Gain on divestitures, net											67
Losses on previously sold Gulf of Mexico properties											(446)
Derivative instrument gains, net											94
Other											228
General and administrative											(376)
Transaction, reorganization, and separation											(22)
Financing costs, net											(514)
Income Before Income Taxes											$	1,891

Total Assets(3)	$	2,796	$	2,199	$	6,269	$	1,698	$	341	$	13,303
Net Property and Equipment	$	1,720	$	1,646	$	4,507	$	187	$	275	$	8,335
Additions to Net Property and Equipment	$	319	$	159	$	523	$	3	$	151	$	1,155

(1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the years ended December 31, 2023, 2022, and 2021 of:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Oil	$	729	$	989	$	420
Natural gas	95		117		47
Natural gas liquids	—		2		2

(2)Includes a noncontrolling interest in Egypt for all periods presented and a noncontrolling interest in Altus Midstream for the years 2022 and 2021.

(3)Intercompany balances are excluded from total assets.

(4)Exploration expense under Intersegment Eliminations & Other primarily reflects the Company’s Suriname exploration activities.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) - USD ($)	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments		$ 61,000,000	$ 0	$ 208,000,000
Equity method investment impairment	$ 160,000,000			160,000,000
Receivables from contracts with customers, net of allowance for doubtful accounts		1,500,000,000	1,300,000,000
Cash and cash equivalent		87,000,000	245,000,000
Restricted cash		0	0
Inventory write-downs		50,000,000
Gathering, processing, and transmission facilities		448,000,000	449,000,000
GPT facilities, accumulated depreciation		373,000,000	367,000,000
Other property and equipment		217,000,000	206,000,000
Transaction, reorganization, and separation		15,000,000	26,000,000	22,000,000
Ongoing consulting and separation costs
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation		7,000,000	15,000,000	17,000,000
EGYPT
Schedule Of Significant Accounting Policies [Line Items]
Inventory And Other, Impairments				26,000,000
North Sea
Schedule Of Significant Accounting Policies [Line Items]
Inventory And Other, Impairments				22,000,000
Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Impairments		0	0	0
Gathering, processing, and transmission facilities
Schedule Of Significant Accounting Policies [Line Items]
Tangible asset Impairment		$ 0	0	0
Other Property and Equipment \| Minimum
Schedule Of Significant Accounting Policies [Line Items]
Useful lives of gas gathering, transmission and processing facilities		3 years
Other Property and Equipment \| Maximum
Schedule Of Significant Accounting Policies [Line Items]
Useful lives of gas gathering, transmission and processing facilities		20 years
Oil And Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Impairments		$ 22,000,000	24,000,000	31,000,000
Oil And Gas Properties, Unproved \| EGYPT
Schedule Of Significant Accounting Policies [Line Items]
Impairments		0	4,000,000	8,000,000
Oil And Gas Properties, Unproved \| North Sea
Schedule Of Significant Accounting Policies [Line Items]
Impairments		$ 11,000,000	$ 0	$ 1,000,000
ALTM \| Third-party investors
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners		21.00%
Apache Egypt \| Sinopec
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners		33.33%

DEBT AND FINANCING COSTS - Financing Costs, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Disclosure [Abstract]
Interest expense	$ 351	$ 332	$ 419
Amortization of debt issuance costs	4	8	8
Capitalized interest	(24)	(18)	(9)
Loss (gain) on extinguishment of debt	(9)	67	104
Interest income	(10)	(10)	(8)
Financing costs, net	312	379	514
Discount of debt amortization	$ 1	$ 2	$ 6

RETIREMENT AND DEFERRED COMPENSATION PLANS - Components of Net Periodic Cost and Underlying Weighted Average Actuarial Assumptions Used for Pension and Postretirement Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Salary increases	4.70%	4.90%	4.50%
Expected return on assets	4.70%	1.90%	1.50%
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 1	$ 2	$ 3
Interest cost	5	3	3
Expected return on assets	(7)	(4)	(4)
Amortization of loss	0	0	0
Settlement loss	0	0	0
Net periodic benefit cost	$ (1)	$ 1	$ 2
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	5.00%	1.80%	1.40%
Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 1	$ 1	$ 1
Interest cost	1	0	0
Expected return on assets	0	0	0
Amortization of loss	(2)	(1)	(1)
Settlement loss	0	0	0
Net periodic benefit cost	$ 0	$ 0	$ 0
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	5.29%	2.57%	2.06%
Healthcare cost trend
Initial	6.50%	6.25%	6.00%
Ultimate in 2030	5.25%	5.00%	5.00%

CONSOLIDATED BALANCE SHEET (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Receivables, allowance	$ 114	$ 117
Common stock, par value (in USD per share)	$ 0.625	$ 0.625
Common stock, shares authorized (in shares)	860,000,000	860,000,000
Common stock, shares issued (in shares)	420,595,901	419,869,987
Treasury stock, shares (in shares)	117,020,000	108,310,838

CAPITAL STOCK - Summary of Stock-settled and Cash-settled Compensation Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	$ 84	$ 304	$ 157
Stock-settled and cash-settled compensation capitalized	13	44	18
Total stock-settled and cash-settled compensation costs	97	348	175
Lease operating expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	27	82	39
Exploration
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	7	29	10
General and administrative
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	$ 50	$ 193	$ 108

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 35
-Paragraph 1D
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480483/718-10-35-1D

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 35
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480483/718-10-35-3

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)(1)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)(2)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)(3)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (c)(1)(i)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (c)(1)(ii)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (c)(1)(iii)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (c)(1)(iv)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (c)(1)(iv)(01)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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Reference 26: http://www.xbrl.org/2003/role/disclosureRef
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Reference 27: http://www.xbrl.org/2003/role/disclosureRef
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Reference 28: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Schedule of Allowance for Doubtful Accounts

The following table presents changes to the Company’s allowance for credit loss:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Allowance for credit loss at beginning of year	$	117	$	109	$	95
Additional provisions for the year	16		9		19
Uncollectible accounts written off, net of recoveries	(19)		(1)		(5)
Allowance for credit loss at end of year	$	114	$	117	$	109

Schedule of Non-cash Impairments of Proved and Unproved Properties

The following table represents non-cash impairment charges of the carrying value of the Company’s unproved properties:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)






Unproved properties:
U.S.	$	10	$	20	$	22
Egypt	—		4		8
North Sea	11		—		1
Other International	1		—		—
Total unproved properties	$	22	$	24	$	31

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Oil and Gas Reserve Information (Details) MBoe in Thousands	12 Months Ended
	Dec. 31, 2023 MBoe MBbls MMcf	Dec. 31, 2022 MBoe MBbls MMcf	Dec. 31, 2021 MBoe MBbls MMcf	Dec. 31, 2020 MBoe MBbls MMcf
Reserve Quantities [Line Items]
Proved developed reserves	735,859	801,315	827,772	797,843
Proved undeveloped reserves	71,621	88,454	85,190	75,840
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	889,769	912,962	873,683
Extensions, discoveries and other additions	112,249	33,805	101,619
Purchases of minerals in-place	64	39,110	457
Revisions of previous estimates	(45,931)	74,523	107,038
Production	(147,840)	(144,631)	(141,642)
Sales of minerals in-place	(831)	(26,000)	(28,193)
Ending balance	807,480	889,769	912,962
United States
Reserve Quantities [Line Items]
Proved developed reserves	500,354	530,823	551,384	532,994
Proved undeveloped reserves	65,931	76,386	65,288	53,408
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	607,209	616,672	586,402
Extensions, discoveries and other additions	95,677	21,592	76,871
Purchases of minerals in-place	64	39,110	457
Revisions of previous estimates	(56,532)	33,217	64,847
Production	(79,302)	(77,382)	(83,712)
Sales of minerals in-place	(831)	(26,000)	(28,193)
Ending balance	566,285	607,209	616,672
EGYPT
Reserve Quantities [Line Items]
Proved developed reserves	165,162	174,633	184,563	164,870
Proved undeveloped reserves	5,690	8,735	12,683	13,449
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	183,368	197,246	178,319
Extensions, discoveries and other additions	15,344	9,278	21,765
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	24,490	29,647	39,071
Production	(52,350)	(52,803)	(41,909)
Sales of minerals in-place	0	0	0
Ending balance	170,852	183,368	197,246
North Sea
Reserve Quantities [Line Items]
Proved developed reserves	70,343	95,859	91,825	99,979
Proved undeveloped reserves	0	3,333	7,219	8,983
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	99,192	99,044	108,962
Extensions, discoveries and other additions	1,228	2,935	2,983
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	(13,889)	11,659	3,120
Production	(16,188)	(14,446)	(16,021)
Sales of minerals in-place	0	0	0
Ending balance	70,343	99,192	99,044
Noncontrolling Interests \| EGYPT
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved developed reserves (Energy) \| MBoe	57	61	66	59
Crude Oil and Condensate
Reserve Quantities [Line Items]
Proved developed reserves	342,923	368,338	364,687	389,483
Proved undeveloped reserves	36,202	33,669	34,928	44,017
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	402,007	399,615	433,500
Extensions, discoveries and other additions	56,893	19,972	33,547
Purchases of minerals in-place	20	16,362	126
Revisions of previous estimates	(5,017)	42,124	18,188
Production	(74,003)	(68,641)	(66,364)
Sales of minerals in-place	(775)	(7,425)	(19,382)
Ending balance	379,125	402,007	399,615
Crude Oil and Condensate \| United States
Reserve Quantities [Line Items]
Proved developed reserves	179,542	177,708	180,968	206,936
Proved undeveloped reserves	30,948	22,239	18,168	25,516
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	199,947	199,136	232,452
Extensions, discoveries and other additions	43,613	9,776	17,869
Purchases of minerals in-place	20	16,362	126
Revisions of previous estimates	(3,520)	7,793	(4,479)
Production	(28,795)	(25,695)	(27,450)
Sales of minerals in-place	(775)	(7,425)	(19,382)
Ending balance	210,490	199,947	199,136
Crude Oil and Condensate \| EGYPT
Reserve Quantities [Line Items]
Proved developed reserves	102,305	108,050	106,646	95,981
Proved undeveloped reserves	5,254	8,557	11,003	11,228
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	116,607	117,649	107,209
Extensions, discoveries and other additions	12,979	7,580	13,390
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	10,505	22,433	22,727
Production	(32,532)	(31,055)	(25,677)
Sales of minerals in-place	0	0	0
Ending balance	107,559	116,607	117,649
Crude Oil and Condensate \| North Sea
Reserve Quantities [Line Items]
Proved developed reserves	61,076	82,580	77,073	86,566
Proved undeveloped reserves	0	2,873	5,757	7,273
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	85,453	82,830	93,839
Extensions, discoveries and other additions	301	2,616	2,288
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	(12,002)	11,898	(60)
Production	(12,676)	(11,891)	(13,237)
Sales of minerals in-place	0	0	0
Ending balance	61,076	85,453	82,830
Crude Oil and Condensate \| Noncontrolling Interests \| EGYPT
Reserve Quantities [Line Items]
Proved developed reserves	36,000	39,000	39,000	36,000
Natural Gas Liquids
Reserve Quantities [Line Items]
Proved developed reserves	154,946	160,975	166,677	153,368
Proved undeveloped reserves	18,401	19,080	16,685	15,587
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	180,055	183,362	168,955
Extensions, discoveries and other additions	26,082	5,501	21,143
Purchases of minerals in-place	21	10,985	191
Revisions of previous estimates	(9,332)	9,917	22,862
Production	(23,446)	(23,370)	(24,806)
Sales of minerals in-place	(33)	(6,340)	(4,983)
Ending balance	173,347	180,055	183,362
Natural Gas Liquids \| United States
Reserve Quantities [Line Items]
Proved developed reserves	153,486	158,745	164,172	150,599
Proved undeveloped reserves	18,401	19,004	16,380	15,141
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	177,749	180,552	165,740
Extensions, discoveries and other additions	25,711	5,456	21,055
Purchases of minerals in-place	21	10,985	191
Revisions of previous estimates	(8,568)	9,991	22,724
Production	(22,993)	(22,895)	(24,175)
Sales of minerals in-place	(33)	(6,340)	(4,983)
Ending balance	171,887	177,749	180,552
Natural Gas Liquids \| EGYPT
Reserve Quantities [Line Items]
Proved developed reserves	0	0	446	716
Proved undeveloped reserves	0	0	30	126
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	0	476	842
Extensions, discoveries and other additions	0	0	7
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	0	(407)	(180)
Production	0	(69)	(193)
Sales of minerals in-place	0	0	0
Ending balance	0	0	476
Natural Gas Liquids \| North Sea
Reserve Quantities [Line Items]
Proved developed reserves	1,460	2,230	2,059	2,053
Proved undeveloped reserves	0	76	275	320
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	2,306	2,334	2,373
Extensions, discoveries and other additions	371	45	81
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	(764)	333	318
Production	(453)	(406)	(438)
Sales of minerals in-place	0	0	0
Ending balance	1,460	2,306	2,334
Natural Gas Liquids \| Noncontrolling Interests \| EGYPT
Reserve Quantities [Line Items]
Proved developed reserves			159	281
Natural Gas
Reserve Quantities [Line Items]
Proved developed reserves \| MMcf	1,427,939	1,632,012	1,778,442	1,529,950
Proved undeveloped reserves \| MMcf	102,107	214,234	201,464	97,417
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance \| MMcf	1,846,246	1,979,906	1,627,367
Extensions, discoveries and other additions \| MMcf	175,641	49,991	281,577
Purchases of minerals in-place \| MMcf	136	70,584	839
Revisions of previous estimates \| MMcf	(189,496)	134,893	395,924
Production \| MMcf	(302,345)	(315,718)	(302,833)
Sales of minerals in-place \| MMcf	(136)	(73,410)	(22,968)
Ending balance \| MMcf	1,530,046	1,846,246	1,979,906
Natural Gas \| United States
Reserve Quantities [Line Items]
Proved developed reserves \| MMcf	1,003,956	1,166,218	1,237,461	1,052,756
Proved undeveloped reserves \| MMcf	99,495	210,862	184,441	76,504
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance \| MMcf	1,377,080	1,421,902	1,129,260
Extensions, discoveries and other additions \| MMcf	158,118	38,157	227,684
Purchases of minerals in-place \| MMcf	136	70,584	839
Revisions of previous estimates \| MMcf	(266,664)	92,599	279,610
Production \| MMcf	(165,083)	(172,752)	(192,523)
Sales of minerals in-place \| MMcf	(136)	(73,410)	(22,968)
Ending balance \| MMcf	1,103,451	1,377,080	1,421,902
Natural Gas \| EGYPT
Reserve Quantities [Line Items]
Proved developed reserves \| MMcf	377,144	399,502	464,826	409,035
Proved undeveloped reserves \| MMcf	2,612	1,068	9,899	12,572
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance \| MMcf	400,570	474,725	421,607
Extensions, discoveries and other additions \| MMcf	14,188	10,191	50,209
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	83,907	45,725	99,143
Production	(118,909)	(130,071)	(96,234)
Sales of minerals in-place	0	0	0
Ending balance \| MMcf	379,756	400,570	474,725
Natural Gas \| North Sea
Reserve Quantities [Line Items]
Proved developed reserves \| MMcf	46,839	66,292	76,155	68,159
Proved undeveloped reserves \| MMcf	0	2,304	7,124	8,341
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance \| MMcf	68,596	83,279	76,500
Extensions, discoveries and other additions \| MMcf	3,335	1,643	3,684
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	(6,739)	(3,431)	17,171
Production	(18,353)	(12,895)	(14,076)
Sales of minerals in-place	0	0	0
Ending balance \| MMcf	46,839	68,596	83,279
Natural Gas \| Noncontrolling Interests \| EGYPT
Reserve Quantities [Line Items]
Proved developed reserves \| MMcf	127,000	134,000	158,000	141,000

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Assets and Liabilities and Locations on Consolidated Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets, current	$ 6	$ 0
Derivative assets, noncurrent	0	5
Derivative assets	$ 6	$ 5
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Deferred charges and other, Other current assets (Note 5)	Deferred charges and other, Other current assets (Note 5)
Derivative liabilities, current	$ 0	$ 50
Derivative liabilities	$ 0	$ 50
Derivative Liability, Statement of Financial Position [Extensible Enumeration]	Other current liabilities (Note 7)	Other current liabilities (Note 7)

- Definition

Fair value, after the effects of master netting arrangements, of a financial asset or other contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes assets not subject to a master netting arrangement and not elected to be offset.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 210
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Publisher FASB
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
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Reference 3: http://www.xbrl.org/2003/role/exampleRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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- Definition

Fair value, after the effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes liabilities not subject to a master netting arrangement and not elected to be offset.

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+ Details

CAPITAL STOCK - Schedule of Restricted Stock Activities (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Weighted Average Grant-Date Fair Value
Total fair value of restricted stock awards vested	$ 23	$ 22	$ 25
Restricted Stock
Units
Non-vested, beginning balance (in shares)	1,885,000	2,073,000	1,552,000
Granted, Shares (in shares)	661,000	847,000	1,506,000
Vested, Shares (in shares)	(975,000)	(978,000)	(857,000)
Forfeited, Shares (in shares)	(69,000)	(57,000)	(128,000)
Expired, shares (in shares)	(22,000)	0	0
Non-vested, ending balance (in shares)	1,480,000	1,885,000	2,073,000
Weighted Average Grant-Date Fair Value
Non-vested Beginning Balance, Weighted Average Grant Date Fair Value (in USD per share)	$ 23.08	$ 19.98	$ 28.43
Granted, Weighted Average Grant-Date Fair Value (in USD per share)	41.60	29.90	16.46
Vested, Weighted Average Grant-Date Fair Value (in USD per share)	23.31	22.39	29.13
Forfeited, Weighted Average Grant-Date Fair Value (in USD per share)	32.44	23.49	19.78
Expired, Weighted Average Grant-Date Fair Value (in USD per share)	27.81	0	0
Non-vested Ending Balance, Weighted Average Grant Date Fair Value (in USD per share)	$ 30.69	$ 23.08	$ 19.98
Weighted-average remaining life of unvested restricted stock units	7 months 6 days
Phantom Units
Units
Non-vested, beginning balance (in shares)	5,709,000	6,402,000	4,423,000
Adjustment from ALTM transaction (in shares)	0	143,000	0
Granted, Shares (in shares)	1,972,000	2,568,000	4,441,000
Vested, Shares (in shares)	(2,851,000)	(2,970,000)	(2,049,000)
Forfeited, Shares (in shares)	(340,000)	(434,000)	(413,000)
Expired, shares (in shares)	(12,000)	0	0
Non-vested, ending balance (in shares)	4,478,000	5,709,000	6,402,000
Weighted Average Grant-Date Fair Value
Total compensation cost related to non-vested awards not yet recognized	$ 54
Phantom Units Issued Based on Per-Share Market Price of Apache Common Stock
Units
Granted, Shares (in shares)	1,972,116	2,512,602	4,375,546
Phantom Units Issued Based on Per-Share Market Price of ALTM Common Stock
Units
Granted, Shares (in shares)		55,546	65,327
Stock Settled Restricted Stock Units
Units
Non-vested, beginning balance (in shares)
Non-vested, ending balance (in shares)	1,479,880
Weighted Average Grant-Date Fair Value
Total compensation cost related to non-vested awards not yet recognized	$ 15

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 counterparty
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Number of derivative counterparties	4

INCOME TAXES

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

INCOME TAXES

Net income before income taxes was composed of the following:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
U.S.	$	627	$	2,675	$	629
Foreign	2,256		3,059		1,262
Total	$	2,883	$	5,734	$	1,891

The total income tax provision (benefit) consisted of the following:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Current income taxes:
Federal	$	2	$	1	$	16
State	6		11		—
Foreign	1,330		1,495		636
	1,338		1,507		652
Deferred income taxes:
Federal	(1,708)		—		—
State	(32)		—		—
Foreign	78		145		(74)
	(1,662)		145		(74)
Total	$	(324)	$	1,652	$	578

The total income tax provision differs from the amounts computed by applying the U.S. statutory income tax rate to income (loss) before income taxes. A reconciliation of the tax on the Company’s net income before income taxes and total income tax provision (benefit) is shown below:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Income tax expense at U.S. statutory rate	$	605	$	1,204	$	397
State income tax, less federal effect(1)	(23)		9		—
Taxes related to foreign operations	752		745		298
Tax credits	—		(4)		(10)






Net change in tax contingencies	5		1		16


Valuation allowances(1)	(1,842)		(646)		(90)
Tax adjustments attributable to BCP Business Combination	—		126		—
Remeasurement of U.K. deferred tax liability	174		208		—
Tax attributable to Altus Preferred Unit limited partners	—		—		(34)
All other, net	5		9		1
	$	(324)	$	1,652	$	578

(1)The change in state valuation allowance is included as a component of state income tax.

The net deferred income tax (asset) liability reflects the net tax impact of temporary differences between the asset and liability amounts carried on the balance sheet under GAAP and amounts utilized for income tax purposes. The net deferred income tax (asset) liability consisted of the following as of December 31:


	2023		2022

	(In millions)
Deferred tax assets:

U.S. and state net operating losses	$	2,050	$	2,029
Capital losses	8		357
Foreign net operating losses	43		27
Tax credits and other tax incentives	26		26
Foreign tax credits	2,204		2,241
Accrued expenses and liabilities	129		156
Asset retirement obligation	850		672
Property and equipment	38		44
Equity investments	8		—
Net interest expense limitation	125		74
Lease liability	71		114
Decommissioning contingency for sold Gulf of Mexico properties	210		275

Total deferred tax assets	5,762		6,015
Valuation allowance	(2,630)		(4,918)
Net deferred tax assets	3,132		1,097
Deferred tax liabilities:


Equity investments	—		1
Property and equipment	1,573		1,023
Right-of-use asset	69		110
Decommissioning security for sold Gulf of Mexico properties	44		148
Other	59		90
Total deferred tax liabilities	1,745		1,372
Net deferred income tax (asset) liability	$	(1,387)	$	275

Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows:


	2023		2022

	(In millions)
Assets:
Other assets
Deferred tax asset	$	1,758	$	39
Liabilities:
Deferred credits and other noncurrent liabilities
Deferred tax liability	371		314
Net deferred income tax (asset) liability	$	(1,387)	$	275

On July 14, 2022, the Energy (Oil and Gas) Profits Levy Act of 2022 (the Energy Profits Levy) was enacted, receiving Royal Assent. Under the law, an additional levy was assessed at a 25 percent rate and is effective for the period of May 26, 2022, through December 31, 2025. The Finance Act 2023 included amendments to the Energy Profits Levy that increased the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. As a result, the Company recorded a deferred tax expense of $208 million and $174 million related to the remeasurement of the U.K. deferred tax liability in 2022 and 2023, respectively.

On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (CAMT) on applicable corporations with an average annual adjusted financial statement income that exceeds $1 billion for any three consecutive years preceding the tax year at issue. The CAMT is effective for tax years beginning after December 31, 2022. The Company is not an applicable corporation in 2023 but will be subject to CAMT beginning on January 1, 2024. The Company is continuing to evaluate the provisions of the IRA and its effects on the Company’s consolidated financial statements.

On January 14, 2022, Apache Midstream LLC, a wholly owned subsidiary of Apache, exchanged 12.5 million Common Units in Altus Midstream LP for 12.5 million shares of ALTM Class A Common Stock, in a taxable exchange. On February 22, 2022, as a result of the BCP Business Combination, the Company deconsolidated ALTM. On March 11, 2022, the Company sold four million of its Kinetik Shares. The Company recorded tax expense of $126 million associated with the BCP Business Combination. The tax impact of the BCP Business Combination was fully offset by a change in valuation allowance. Refer to Note 2— Acquisitions and Divestitures for further detail.

The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize the existing deferred tax assets. The Company showed positive income over the three-year period ended December 31, 2023. During the fourth quarter of 2023, as a result of increases in projections of future taxable income and the absence of objective negative evidence (such as a cumulative loss in recent years), the Company determined there was sufficient positive evidence to release a majority of the U.S. valuation allowance, which resulted in a non-cash deferred income tax benefit of $1.7 billion. The remaining U.S. valuation allowance relates primarily to foreign tax credit and capital loss carryforwards.

In 2023, 2022, and 2021, the Company’s valuation allowance decreased by $2.3 billion, $1.0 billion, and $89 million, respectively, as detailed in the table below:


	2023		2022		2021

	(In millions)
Balance at beginning of year	$	4,918	$	5,902	$	5,991
State(1)	(63)		(111)		1
U.S.	(2,235)		(706)		(97)
Foreign	10		(167)		7

Balance at end of year	$	2,630	$	4,918	$	5,902

(1)Reported as a component of state income taxes.

On December 31, 2023, the Company had net operating losses as follows:

Amount

Expiration

(In millions)

U.S.

8,027

2027 - Indefinite

State

6,553

Various

Foreign

119

2024 - Indefinite

The Company has a U.S. net operating loss carryforward of $8.0 billion, which includes $107 million of net operating loss subject to annual limitation under Section 382 of the Internal Revenue Code (Code). Net operating losses generated in tax years beginning after 2017 are subject to an 80 percent taxable income limitation with indefinite carryover under the 2017 Tax Cuts and Jobs Act. The Company also has state net operating losses of $6.6 billion, foreign net operating losses of $119 million, and a net interest expense carryover of $580 million under Section 163(j) of the Code with indefinite carryover. In 2023, $1.7 billion of U.S. capital loss carryforward expired unutilized with $34 million remaining, which has a five year carryover period expiring in 2027. The Company has recorded a valuation allowance against some of the U.S. net operating losses, a majority of the state net operating losses, the foreign net operating losses, and the U.S. capital loss because it is more likely than not that these net operating losses and the capital loss carryforward will not be realized. The Company believes it is more likely than not that the deferred tax assets related to the remaining U.S. and state net operating losses, and the net interest expense carryover will be utilized prior to their expiration.

On December 31, 2023, the Company had foreign tax credits as follows:


	Amount		Expiration
	(In millions)
Foreign tax credits	$	2,204	2025-2026

The Company has a $2.2 billion U.S. foreign tax credit carryforward. The Company has recorded a full valuation allowance against the U.S. foreign tax credits listed above because it is more likely than not that these attributes will expire unutilized.

The Company accounts for income taxes in accordance with ASC Topic 740, “Income Taxes,” which prescribes a minimum recognition threshold that a tax position must meet before being recognized in the financial statements. Tax positions generally refer to a position taken in a previously filed income tax return or expected to be included in a tax return to be filed in the future that is reflected in the measurement of current and deferred income tax assets and liabilities. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:


	2023		2022		2021

	(In millions)
Balance at beginning of year	$	89	$	116	$	93
Additions based on tax positions related to prior year	4		—		16
Additions based on tax positions related to the current year	—		—		7
Reductions for tax positions of prior years	—		(27)		—
Balance at end of year	$	93	$	89	$	116

The Company records interest and penalties related to unrecognized tax benefits as a component of income tax expense. Each quarter, the Company assesses the amounts provided for and, as a result, may increase or reduce the amount of interest and penalties. During each of the years ended December 31, 2023, 2022, and 2021, the Company recorded tax expense of $2 million, $1 million, and $1 million, respectively, for interest and penalties. At December 31, 2023, 2022, and 2021, the Company had an accrued liability for interest and penalties of $7 million, $5 million, and $4 million, respectively.

In 2023, 2022, and 2021, the Company recorded a $4 million net increase, a $27 million net decrease, and a $23 million net increase, respectively, in its reserve for uncertain tax positions.

On September 26, 2022, the Company received a Statutory Notice of Deficiency from the IRS disallowing certain net operating loss carryback and research and development credit refund claims. As a result of the disallowance, on December 14, 2022, the Company filed a petition with the U.S. Tax Court challenging the tax adjustments and requesting a redetermination of the deficiencies stated in the notice.

The Company and its subsidiaries are subject to U.S. federal income tax as well as income tax in various states and foreign jurisdictions. The Company’s uncertain tax positions are related to tax years that may be subject to examination by the relevant taxing authority. The Company’s earliest open tax years in its key jurisdictions are as follows:

Jurisdiction


U.S.			2014
Egypt			2005
U.K.			2022

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

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-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482603/740-30-50-2

+ Details

CAPITALIZED EXPLORATORY WELL COSTS - Aging by Geographic Area of Exploratory Well Costs Capitalized Greater than One Year (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 430	$ 259	$ 123
2022
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	178
2021
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	153
2020 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	99
Suriname
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	421
Suriname \| 2022
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	178
Suriname \| 2021
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	153
Suriname \| 2020 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	90
EGYPT
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	9
EGYPT \| 2022
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	0
EGYPT \| 2021
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	0
EGYPT \| 2020 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 9

DEBT AND FINANCING COSTS (Tables)

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Schedule of Debt

The following table presents the carrying value of the Company’s debt as of December 31, 2023 and 2022:


	December 31,
	2023		2022

	(In millions)

4.625% notes due 2025(1)	$	51	$	51
7.7% notes due 2026	78		78
7.95% notes due 2026	132		132
4.875% due 2027(1)	108		108
4.375% notes due 2028(1)	325		325
7.75% notes due 2029(1)(2)	235		235
4.25% notes due 2030(1)	516		579
6.0% notes due 2037(1)	443		443
5.1% notes due 2040(1)	1,333		1,333
5.25% notes due 2042(1)	399		399
4.75% notes due 2043(1)	428		428
4.25% notes due 2044(1)	211		221
7.375% debentures due 2047	150		150
5.35% notes due 2049(1)	387		387
7.625% debentures due 2096	39		39
Apache notes and debentures before unamortized discount and debt issuance costs(3)	4,835		4,908


Syndicated credit facilities(4)	372		566
Apache finance lease obligations	32		34
Unamortized discount	(26)		(27)
Debt issuance costs	(25)		(28)
Total debt	5,188		5,453
Current maturities	(2)		(2)
Long-term debt	$	5,186	$	5,451

(2)Assumed by Apache in August 2017 as permitted by terms of these notes originally issued by a subsidiary and guaranteed by Apache.

(4)The carrying amount of borrowings on credit facilities approximates fair value because the interest rates are variable and reflective of market rates.

Schedule of Maturities of Long-Term Debt

Maturities for the Company’s notes and debentures excluding discount and debt issuance costs as of December 31, 2023 are as follows:


	(In millions)
2024	$	—
2025	51
2026	210
2027	108
2028	325
Thereafter	4,141
Notes and debentures, excluding discounts and debt issuance costs	$	4,835

Schedule of Components of Financing Costs, Net

The following table presents the components of the Company’s financing costs, net:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Interest expense	$	351	$	332	$	419
Amortization of debt issuance costs	4		8		8
Capitalized interest	(24)		(18)		(9)
Loss (gain) on extinguishment of debt	(9)		67		104
Interest income	(10)		(10)		(8)
Financing costs, net	$	312	$	379	$	514

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Activities Recorded in the Statement of Consolidated Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	$ 48	$ (47)	$ 25
Unrealized gains (losses), net	51	(67)	69
Derivative instrument gains (losses), net	99	(114)	94
Commodity derivative instruments
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	48	(34)	25
Unrealized gains (losses), net	51	(36)	(20)
Foreign currency derivative instruments
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	0	(13)	0
Pipeline capacity embedded derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses), net	0	0	7
Preferred Units embedded derivative
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses), net	$ 0	$ (31)	$ 82

- Definition

The net change in the difference between the fair value and the carrying value, or in the comparative fair values, of derivative instruments, including options, swaps, futures, and forward contracts, held at each balance sheet date, that was included in earnings for the period.

+ References + Details

ASSET RETIREMENT OBLIGATION - Schedule of changes to Asset Retirement Obligation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of the year	$ 1,995	$ 2,130
Liabilities incurred	14	4
Liabilities acquired	0	4
Liabilities divested	0	(73)
Liabilities settled	(43)	(39)
Accretion expense	116	117	$ 113
Revisions in estimated liabilities	356	(148)
Asset retirement obligation at end of the year	2,438	1,995	$ 2,130
Less current portion	(76)	(55)
Asset retirement obligation, long-term	$ 2,362	$ 1,940

OTHER CURRENT LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2023

Payables and Accruals [Abstract]

Schedule of Other Current Liabilities

The following table provides detail of the Company’s other current liabilities as of December 31:


	2023		2022

	(In millions)
Accrued operating expenses	$	162	$	145
Accrued exploration and development	371		333

Accrued compensation and benefits	390		514
Accrued interest	93		97
Accrued income taxes	138		90
Current asset retirement obligation	76		55
Current operating lease liability	116		167

Current decommissioning contingency for sold Gulf of Mexico properties	60		450
Other	338		292
Total Other current liabilities	$	1,744	$	2,143

CAPITAL STOCK - Common Stock Outstanding (Details) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Movement In Common Stock Outstanding [Roll Forward]
Balance, beginning of year (in shares)	311,559,149	346,930,765	377,482,630
Shares issued for stock-based compensation plans:
Treasury shares issued (in shares)	2,016	1,996	3,133
Common shares issued (in shares)	725,914	791,381	649,231
Treasury shares acquired (in shares)	(8,711,178)	(36,164,993)	(31,204,229)
Balance, end of year (in shares)	303,575,901	311,559,149	346,930,765

DEBT AND FINANCING COSTS - Schedule of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Long-term debt, gross	$ 4,835
Apache finance lease obligations	32	$ 34
Unamortized discount	(26)	(27)
Debt issuance costs	(25)	(28)
Total debt	5,188	5,453
Current maturities	(2)	(2)
LONG-TERM DEBT (Note 9)	$ 5,186	5,451
Unsecured Debt \| 4.625% notes due 2025
Debt Instrument [Line Items]
Debt interest rate	4.625%
Long-term debt, gross	$ 51	51
Unsecured Debt \| 7.7% notes due 2026
Debt Instrument [Line Items]
Debt interest rate	7.70%
Long-term debt, gross	$ 78	78
Unsecured Debt \| 7.95% notes due 2026
Debt Instrument [Line Items]
Debt interest rate	7.95%
Long-term debt, gross	$ 132	132
Unsecured Debt \| 4.875% notes due 2027
Debt Instrument [Line Items]
Debt interest rate	4.875%
Long-term debt, gross	$ 108	108
Unsecured Debt \| 4.375% notes due 2028
Debt Instrument [Line Items]
Debt interest rate	4.375%
Long-term debt, gross	$ 325	325
Unsecured Debt \| 7.75% notes due in 2029
Debt Instrument [Line Items]
Debt interest rate	7.75%
Long-term debt, gross	$ 235	235
Unsecured Debt \| 4.25% notes due 2030
Debt Instrument [Line Items]
Debt interest rate	4.25%
Long-term debt, gross	$ 516	579
Unsecured Debt \| 6.0% notes due 2037
Debt Instrument [Line Items]
Debt interest rate	6.00%
Long-term debt, gross	$ 443	443
Unsecured Debt \| 5.1% notes due 2040
Debt Instrument [Line Items]
Debt interest rate	5.10%
Long-term debt, gross	$ 1,333	1,333
Unsecured Debt \| 5.25% notes due 2042
Debt Instrument [Line Items]
Debt interest rate	5.25%
Long-term debt, gross	$ 399	399
Unsecured Debt \| 4.75% notes due 2043
Debt Instrument [Line Items]
Debt interest rate	4.75%
Long-term debt, gross	$ 428	428
Unsecured Debt \| 4.25% notes due 2044
Debt Instrument [Line Items]
Debt interest rate	4.25%
Long-term debt, gross	$ 211	221
Unsecured Debt \| 7.375% debentures due 2047
Debt Instrument [Line Items]
Debt interest rate	7.375%
Long-term debt, gross	$ 150	150
Unsecured Debt \| 5.35% notes due 2049
Debt Instrument [Line Items]
Debt interest rate	5.35%
Long-term debt, gross	$ 387	387
Unsecured Debt \| 7.625% debentures due 2096
Debt Instrument [Line Items]
Debt interest rate	7.625%
Long-term debt, gross	$ 39	39
Unsecured Debt \| Notes and debentures
Debt Instrument [Line Items]
Long-term debt, gross	4,835	4,908
Debt instrument, fair value	4,300	4,200
Line of Credit \| Syndicated credit facility \| Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility	$ 372	$ 566

DEBT AND FINANCING COSTS - Commercial Paper Program (Details) - Commercial paper	Dec. 13, 2023 USD ($)
Debt Instrument [Line Items]
Debt instrument, face amount	$ 1,800,000,000
Debt instrument guarantee terms, benchmark amount (less than)	$ 1,000,000,000
Debt instrument, term	397 days

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

+ Details

BUSINESS SEGMENT INFORMATION - Financial Segment Information (Details) - USD ($)

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Operating Expenses:

Lease operating expenses

^[1]

$ 1,436,000,000

$ 1,444,000,000

$ 1,241,000,000

Taxes other than income

207,000,000

268,000,000

204,000,000

Exploration

195,000,000

305,000,000

155,000,000

Depreciation, depletion, and amortization

1,540,000,000

1,233,000,000

1,360,000,000

Asset retirement obligation accretion

116,000,000

117,000,000

113,000,000

Impairments

61,000,000

208,000,000

Total operating expenses

4,631,000,000

5,510,000,000

5,125,000,000

Operating Income (Loss)

3,648,000,000

5,565,000,000

2,860,000,000

Other Income (Expense):

Gain on divestitures, net

8,000,000

1,180,000,000

67,000,000

Losses on previously sold Gulf of Mexico properties

(212,000,000)

(157,000,000)

(446,000,000)

Derivative instrument gains (losses), net

99,000,000

(114,000,000)

94,000,000

Other

18,000,000

148,000,000

228,000,000

General and administrative

(351,000,000)

(483,000,000)

(376,000,000)

Transaction, reorganization, and separation

(15,000,000)

(26,000,000)

(22,000,000)

Financing costs, net

(312,000,000)

(379,000,000)

(514,000,000)

NET INCOME BEFORE INCOME TAXES

2,883,000,000

5,734,000,000

1,891,000,000

Total assets

15,244,000,000

13,147,000,000

13,303,000,000

Net Property and Equipment

10,038,000,000

9,012,000,000

8,335,000,000

Additions to Net Property and Equipment

2,313,000,000

2,607,000,000

1,155,000,000

Operating Segments | Egypt

Operating Expenses:

Lease operating expenses

474,000,000

526,000,000

469,000,000

Taxes other than income

Exploration

119,000,000

84,000,000

63,000,000

Depreciation, depletion, and amortization

524,000,000

400,000,000

524,000,000

Asset retirement obligation accretion

Impairments

26,000,000

Total operating expenses

1,150,000,000

1,032,000,000

1,094,000,000

Operating Income (Loss)

1,879,000,000

2,489,000,000

991,000,000

Other Income (Expense):

Total assets

3,503,000,000

3,148,000,000

2,796,000,000

Net Property and Equipment

2,209,000,000

1,976,000,000

1,720,000,000

Additions to Net Property and Equipment

834,000,000

695,000,000

319,000,000

Operating Segments | North Sea

Operating Expenses:

Lease operating expenses

369,000,000

404,000,000

383,000,000

Taxes other than income

Exploration

19,000,000

35,000,000

34,000,000

Depreciation, depletion, and amortization

271,000,000

238,000,000

270,000,000

Asset retirement obligation accretion

76,000,000

82,000,000

79,000,000

Impairments

50,000,000

22,000,000

Total operating expenses

837,000,000

802,000,000

827,000,000

Operating Income (Loss)

501,000,000

756,000,000

309,000,000

Other Income (Expense):

Total assets

1,970,000,000

1,911,000,000

2,199,000,000

Net Property and Equipment

1,628,000,000

1,386,000,000

1,646,000,000

Additions to Net Property and Equipment

131,000,000

210,000,000

159,000,000

Operating Segments | U.S.

Operating Expenses:

Lease operating expenses

593,000,000

515,000,000

391,000,000

Taxes other than income

207,000,000

265,000,000

190,000,000

Exploration

14,000,000

24,000,000

28,000,000

Depreciation, depletion, and amortization

745,000,000

593,000,000

554,000,000

Asset retirement obligation accretion

40,000,000

34,000,000

30,000,000

Impairments

11,000,000

Total operating expenses

2,601,000,000

3,522,000,000

3,077,000,000

Operating Income (Loss)

1,311,000,000

2,472,000,000

1,679,000,000

Other Income (Expense):

Total assets

9,221,000,000

7,574,000,000

6,269,000,000

Net Property and Equipment

5,689,000,000

5,226,000,000

4,507,000,000

Additions to Net Property and Equipment

1,255,000,000

1,439,000,000

523,000,000

Reportable Legal Entities | Altus Midstream

Segment Reporting Information [Line Items]

Total revenues

21,000,000

138,000,000

Operating Expenses:

Lease operating expenses

Taxes other than income

3,000,000

14,000,000

Exploration

Depreciation, depletion, and amortization

2,000,000

12,000,000

Asset retirement obligation accretion

1,000,000

4,000,000

Impairments

160,000,000

Total operating expenses

11,000,000

227,000,000

Operating Income (Loss)

10,000,000

(89,000,000)

Other Income (Expense):

Total assets

1,698,000,000

Net Property and Equipment

187,000,000

Additions to Net Property and Equipment

3,000,000

Intersegment Eliminations & Other

Segment Reporting Information [Line Items]

Total revenues

(19,000,000)

(130,000,000)

Operating Expenses:

Lease operating expenses

(1,000,000)

(2,000,000)

Taxes other than income

Exploration

43,000,000

162,000,000

30,000,000

Depreciation, depletion, and amortization

Asset retirement obligation accretion

Impairments

Total operating expenses

43,000,000

143,000,000

(100,000,000)

Operating Income (Loss)

(43,000,000)

(162,000,000)

(30,000,000)

Other Income (Expense):

Total assets

550,000,000

514,000,000

341,000,000

Net Property and Equipment

512,000,000

424,000,000

275,000,000

Additions to Net Property and Equipment

93,000,000

263,000,000

151,000,000

Oil and gas, excluding purchased

Segment Reporting Information [Line Items]

Total revenues

^[1]

7,385,000,000

9,220,000,000

6,498,000,000

Operating Expenses:

Gathering, processing, and transmission & purchased oil and gas costs

^[1]

334,000,000

367,000,000

264,000,000

Oil and gas, excluding purchased | Operating Segments | Egypt

Segment Reporting Information [Line Items]

Total revenues

3,029,000,000

3,521,000,000

2,085,000,000

Operating Expenses:

Gathering, processing, and transmission & purchased oil and gas costs

33,000,000

22,000,000

12,000,000

Oil and gas, excluding purchased | Operating Segments | North Sea

Segment Reporting Information [Line Items]

Total revenues

1,338,000,000

1,558,000,000

1,136,000,000

Operating Expenses:

Gathering, processing, and transmission & purchased oil and gas costs

52,000,000

43,000,000

39,000,000

Oil and gas, excluding purchased | Operating Segments | U.S.

Segment Reporting Information [Line Items]

Total revenues

3,018,000,000

4,144,000,000

3,280,000,000

Operating Expenses:

Gathering, processing, and transmission & purchased oil and gas costs

249,000,000

315,000,000

309,000,000

Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream

Segment Reporting Information [Line Items]

Total revenues

Operating Expenses:

Gathering, processing, and transmission & purchased oil and gas costs

5,000,000

32,000,000

Oil and gas, excluding purchased | Intersegment Eliminations & Other

Segment Reporting Information [Line Items]

Total revenues

(3,000,000)

Operating Expenses:

Gathering, processing, and transmission & purchased oil and gas costs

(18,000,000)

(128,000,000)

Purchased oil and gas costs

Segment Reporting Information [Line Items]

Total revenues

^[1]

894,000,000

1,855,000,000

1,487,000,000

Operating Expenses:

Gathering, processing, and transmission & purchased oil and gas costs

^[1]

742,000,000

1,776,000,000

1,580,000,000

Purchased oil and gas costs | Operating Segments | Egypt

Segment Reporting Information [Line Items]

Total revenues

Operating Expenses:

Gathering, processing, and transmission & purchased oil and gas costs

Purchased oil and gas costs | Operating Segments | North Sea

Segment Reporting Information [Line Items]

Total revenues

Operating Expenses:

Gathering, processing, and transmission & purchased oil and gas costs

Purchased oil and gas costs | Operating Segments | U.S.

Segment Reporting Information [Line Items]

Total revenues

894,000,000

1,850,000,000

1,476,000,000

Operating Expenses:

Gathering, processing, and transmission & purchased oil and gas costs

742,000,000

1,776,000,000

1,575,000,000

Purchased oil and gas costs | Reportable Legal Entities | Altus Midstream

Segment Reporting Information [Line Items]

Total revenues

5,000,000

11,000,000

Operating Expenses:

Gathering, processing, and transmission & purchased oil and gas costs

5,000,000

Purchased oil and gas costs | Intersegment Eliminations & Other

Segment Reporting Information [Line Items]

Total revenues

Operating Expenses:

Gathering, processing, and transmission & purchased oil and gas costs

Oil and gas

Segment Reporting Information [Line Items]

Total revenues

8,279,000,000

11,075,000,000

7,985,000,000

Oil and gas | Operating Segments | Egypt

Segment Reporting Information [Line Items]

Total revenues

3,029,000,000

3,521,000,000

2,085,000,000

Oil and gas | Operating Segments | North Sea

Segment Reporting Information [Line Items]

Total revenues

1,338,000,000

1,558,000,000

1,136,000,000

Oil and gas | Operating Segments | U.S.

Segment Reporting Information [Line Items]

Total revenues

3,912,000,000

5,994,000,000

4,756,000,000

Oil and gas | Reportable Legal Entities | Altus Midstream

Segment Reporting Information [Line Items]

Total revenues

16,000,000

127,000,000

Oil and gas | Intersegment Eliminations & Other

Segment Reporting Information [Line Items]

Total revenues

(16,000,000)

(127,000,000)

Oil revenues

Other Income (Expense):

Revenue from non-customers

729,000,000

989,000,000

420,000,000

Oil revenues | Oil and gas, excluding purchased

Segment Reporting Information [Line Items]

Total revenues

5,997,000,000

6,835,000,000

4,585,000,000

Oil revenues | Oil and gas, excluding purchased | Operating Segments | Egypt

Segment Reporting Information [Line Items]

Total revenues

2,683,000,000

3,145,000,000

1,806,000,000

Oil revenues | Oil and gas, excluding purchased | Operating Segments | North Sea

Segment Reporting Information [Line Items]

Total revenues

1,073,000,000

1,232,000,000

929,000,000

Oil revenues | Oil and gas, excluding purchased | Operating Segments | U.S.

Segment Reporting Information [Line Items]

Total revenues

2,241,000,000

2,458,000,000

1,850,000,000

Oil revenues | Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream

Segment Reporting Information [Line Items]

Total revenues

Oil revenues | Oil and gas, excluding purchased | Intersegment Eliminations & Other

Segment Reporting Information [Line Items]

Total revenues

Natural gas revenues

Other Income (Expense):

Revenue from non-customers

95,000,000

117,000,000

47,000,000

Natural gas revenues | Oil and gas, excluding purchased

Segment Reporting Information [Line Items]

Total revenues

880,000,000

1,569,000,000

1,207,000,000

Natural gas revenues | Oil and gas, excluding purchased | Operating Segments | Egypt

Segment Reporting Information [Line Items]

Total revenues

346,000,000

370,000,000

270,000,000

Natural gas revenues | Oil and gas, excluding purchased | Operating Segments | North Sea

Segment Reporting Information [Line Items]

Total revenues

237,000,000

281,000,000

183,000,000

Natural gas revenues | Oil and gas, excluding purchased | Operating Segments | U.S.

Segment Reporting Information [Line Items]

Total revenues

297,000,000

918,000,000

754,000,000

Natural gas revenues | Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream

Segment Reporting Information [Line Items]

Total revenues

Natural gas revenues | Oil and gas, excluding purchased | Intersegment Eliminations & Other

Segment Reporting Information [Line Items]

Total revenues

Natural gas liquids revenues

Other Income (Expense):

Revenue from non-customers

2,000,000

Natural gas liquids revenues | Oil and gas, excluding purchased

Segment Reporting Information [Line Items]

Total revenues

508,000,000

816,000,000

706,000,000

Natural gas liquids revenues | Oil and gas, excluding purchased | Operating Segments | Egypt

Segment Reporting Information [Line Items]

Total revenues

6,000,000

9,000,000

Natural gas liquids revenues | Oil and gas, excluding purchased | Operating Segments | North Sea

Segment Reporting Information [Line Items]

Total revenues

28,000,000

45,000,000

24,000,000

Natural gas liquids revenues | Oil and gas, excluding purchased | Operating Segments | U.S.

Segment Reporting Information [Line Items]

Total revenues

480,000,000

768,000,000

676,000,000

Natural gas liquids revenues | Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream

Segment Reporting Information [Line Items]

Total revenues

Natural gas liquids revenues | Oil and gas, excluding purchased | Intersegment Eliminations & Other

Segment Reporting Information [Line Items]

Total revenues

$ 0

$ (3,000,000)

[1]	(1) For related party transactions associated with Kinetik, refer to Note 6—Equity Method Interest for further detail.

ACQUISITIONS AND DIVESTITURES - 2021 Activity (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Proceeds from asset divestitures		$ 29	$ 778	$ 256
Disposed of by Sale \| Non-Core Assets And Leasehold
Business Acquisition [Line Items]
Proceeds from asset divestitures		29	52
Gain (loss) on sale of oil and gas properties		$ 8	36
Permian Region
Business Acquisition [Line Items]
Payments to acquire leasehold and property			$ 37	9
Permian Region \| Disposed of by Sale
Business Acquisition [Line Items]
Carrying value of non-core assets disposed	$ 157
Proceeds from asset divestitures	176
Asset retirement obligation assumed	44
Gain (loss) on sale of oil and gas properties	$ 63
Permian Region \| Disposed of by Sale \| Non-Core Assets And Leasehold
Business Acquisition [Line Items]
Proceeds from asset divestitures				80
Gain (loss) on sale of oil and gas properties				$ 4

OTHER CURRENT ASSETS (Tables)

12 Months Ended

Dec. 31, 2023

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Schedule of Other Current Assets

The following table provides detail of the Company’s other current assets as of December 31:


	2023		2022

	(In millions)
Inventories	$	453	$	427
Drilling advances	88		89
Prepaid assets and other	46		31
Current decommissioning security for sold Gulf of Mexico assets	178		450
Total Other current assets	$	765	$	997

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2023

Extractive Industries [Abstract]

Schedule of Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities


	United States		Egypt(1)		North Sea		Other International		Total(1)

	(In millions, except per boe)
2023
Oil and gas production revenues	$	3,018	$	3,029	$	1,338	$	—	$	7,385
Operating cost:
Depreciation, depletion, and amortization(2)	709		521		270		—		1,500
Asset retirement obligation accretion	40		—		76		—		116
Lease operating expenses	593		474		369		—		1,436
Gathering, processing, and transmission	249		33		52		—		334
Exploration expenses	14		119		19		43		195

Production taxes(3)	204		—		—		—		204
Income tax	254		828		414		—		1,496
	2,063		1,975		1,200		43		5,281
Results of operations	$	955	$	1,054	$	138	$	(43)	$	2,104
2022
Oil and gas production revenues	$	4,144	$	3,521	$	1,558	$	—	$	9,223
Operating cost:
Depreciation, depletion, and amortization(2)	564		390		232		—		1,186
Asset retirement obligation accretion	34		—		82		—		116
Lease operating expenses	515		526		404		—		1,445
Gathering, processing, and transmission	315		22		43		—		380
Exploration expenses	24		84		35		162		305

Production taxes(3)	263		—		—		—		263
Income tax	510		1,100		495		—		2,105
	2,225		2,122		1,291		162		5,800
Results of operations	$	1,919	$	1,399	$	267	$	(162)	$	3,423
2021
Oil and gas production revenues	$	3,280	$	2,085	$	1,136	$	—	$	6,501
Operating cost:
Depreciation, depletion, and amortization(2)	511		477		267		—		1,255
Asset retirement obligation accretion	30		—		79		—		109
Lease operating expenses	391		469		383		—		1,243
Gathering, processing, and transmission	309		12		39		—		360
Exploration expenses	28		63		34		30		155

Production taxes(3)	188		—		—		—		188
Income tax	383		479		134		—		996
	1,840		1,500		936		30		4,306
Results of operations	$	1,440	$	585	$	200	$	(30)	$	2,195

(1)Includes a noncontrolling interest in Egypt.

(2)Reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 17—Business Segment Information.

(3)Reflects only amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 17—Business Segment Information.

Schedule of Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities

Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities


	United States		Egypt(2)		North Sea		Other International		Total(2)

	(In millions)
2023
Acquisitions:
Proved	$	1	$	4	$	—	$	—	$	5
Unproved	20		—		—		—		20
Exploration	31		226		44		131		432
Development	1,148		646		468		—		2,262
Costs incurred(1)	$	1,200	$	876	$	512	$	131	$	2,719
(1) Includes capitalized interest and asset retirement costs:
Capitalized interest	$	—	$	—	$	—	$	24	$	24
Asset retirement costs	(4)		—		375		—		371
2022
Acquisitions:
Proved	$	596	$	3	$	—	$	—	$	599
Unproved	66		—		—		—		66
Exploration	4		169		61		311		545
Development	848		568		(57)		—		1,359
Costs incurred(1)	$	1,514	$	740	$	4	$	311	$	2,569
(1) Includes capitalized interest and asset retirement costs:
Capitalized interest	$	—	$	—	$	1	$	17	$	18
Asset retirement costs	79		—		(215)		—		(136)
2021
Acquisitions:
Proved	$	—	$	(157)	$	—	$	—	$	(157)
Unproved	9		20		—		—		29
Exploration	6		86		39		170		301
Development	545		404		135		2		1,086
Costs incurred(1)	$	560	$	353	$	174	$	172	$	1,259
(1) Includes capitalized interest, asset retirement costs, and Egypt modernization impacts as follows:
Capitalized interest	$	—	$	—	$	—	$	9	$	9
Asset retirement costs	130		—		19		—		149
Egypt PSC modernization impacts – Proved and Unproved	—		(145)		—		—		(145)
(2) Includes a noncontrolling interest in Egypt.


	United States		Egypt(1)		North Sea		Other International		Total(1)

	(In millions)
2023
Proved properties	$	20,758	$	13,777	$	9,472	$	—	$	44,007
Unproved properties	267		71		3		512		853
	21,025		13,848		9,475		512		44,860
Accumulated DD&A	(15,587)		(11,678)		(7,849)		—		(35,114)
	$	5,438	$	2,170	$	1,626	$	512	$	9,746

2022
Proved properties	$	19,638	$	13,014	$	8,945	$	—	$	41,597
Unproved properties	247		77		11		424		759
	19,885		13,091		8,956		424		42,356
Accumulated DD&A	(14,902)		(11,157)		(7,573)		—		(33,632)
	$	4,983	$	1,934	$	1,383	$	424	$	8,724

(1)Includes a noncontrolling interest in Egypt.

Schedule of Proved Reserve Data


	Crude Oil and Condensate
	United States	Egypt(1)	North Sea	Total(1)

	(Thousands of barrels)
Proved developed reserves:
December 31, 2020	206,936	95,981	86,566	389,483
December 31, 2021	180,968	106,646	77,073	364,687
December 31, 2022	177,708	108,050	82,580	368,338
December 31, 2023	179,542	102,305	61,076	342,923
Proved undeveloped reserves:
December 31, 2020	25,516	11,228	7,273	44,017
December 31, 2021	18,168	11,003	5,757	34,928
December 31, 2022	22,239	8,557	2,873	33,669
December 31, 2023	30,948	5,254	—	36,202

Total proved reserves:
Balance December 31, 2020	232,452	107,209	93,839	433,500
Extensions, discoveries and other additions	17,869	13,390	2,288	33,547
Purchases of minerals in-place	126	—	—	126
Revisions of previous estimates	(4,479)	22,727	(60)	18,188
Production	(27,450)	(25,677)	(13,237)	(66,364)
Sales of minerals in-place	(19,382)	—	—	(19,382)
Balance December 31, 2021	199,136	117,649	82,830	399,615
Extensions, discoveries and other additions	9,776	7,580	2,616	19,972
Purchases of minerals in-place	16,362	—	—	16,362
Revisions of previous estimates	7,793	22,433	11,898	42,124
Production	(25,695)	(31,055)	(11,891)	(68,641)
Sales of minerals in-place	(7,425)	—	—	(7,425)
Balance December 31, 2022	199,947	116,607	85,453	402,007
Extensions, discoveries and other additions	43,613	12,979	301	56,893
Purchases of minerals in-place	20	—	—	20
Revisions of previous estimates	(3,520)	10,505	(12,002)	(5,017)
Production	(28,795)	(32,532)	(12,676)	(74,003)
Sales of minerals in-place	(775)	—	—	(775)
Balance December 31, 2023	210,490	107,559	61,076	379,125

(1)Includes proved reserves of 36 MMbbls, 39 MMbbls, 39 MMbbls, and 36 MMbbls as of December 31, 2023, 2022, 2021, and 2020, respectively, attributable to a noncontrolling interest in Egypt.


	Natural Gas Liquids
	United States	Egypt(1)	North Sea	Total(1)

	(Thousands of barrels)
Proved developed reserves:
December 31, 2020	150,599	716	2,053	153,368
December 31, 2021	164,172	446	2,059	166,677
December 31, 2022	158,745	—	2,230	160,975
December 31, 2023	153,486	—	1,460	154,946
Proved undeveloped reserves:
December 31, 2020	15,141	126	320	15,587
December 31, 2021	16,380	30	275	16,685
December 31, 2022	19,004	—	76	19,080
December 31, 2023	18,401	—	—	18,401

Total proved reserves:
Balance December 31, 2020	165,740	842	2,373	168,955
Extensions, discoveries and other additions	21,055	7	81	21,143
Purchases of minerals in-place	191	—	—	191
Revisions of previous estimates	22,724	(180)	318	22,862
Production	(24,175)	(193)	(438)	(24,806)
Sales of minerals in-place	(4,983)	—	—	(4,983)
Balance December 31, 2021	180,552	476	2,334	183,362
Extensions, discoveries and other additions	5,456	—	45	5,501
Purchases of minerals in-place	10,985	—	—	10,985
Revisions of previous estimates	9,991	(407)	333	9,917
Production	(22,895)	(69)	(406)	(23,370)
Sales of minerals in-place	(6,340)	—	—	(6,340)
Balance December 31, 2022	177,749	—	2,306	180,055
Extensions, discoveries and other additions	25,711	—	371	26,082
Purchases of minerals in-place	21	—	—	21
Revisions of previous estimates	(8,568)	—	(764)	(9,332)
Production	(22,993)	—	(453)	(23,446)
Sales of minerals in-place	(33)	—	—	(33)
Balance December 31, 2023	171,887	—	1,460	173,347

(1) Includes proved reserves of 159 Mbbls and 281 Mbbls as of December 31, 2021 and 2020, respectively, attributable to a noncontrolling interest in Egypt.


	Natural Gas
	United States	Egypt(1)	North Sea	Total(1)

	(Millions of cubic feet)
Proved developed reserves:
December 31, 2020	1,052,756	409,035	68,159	1,529,950
December 31, 2021	1,237,461	464,826	76,155	1,778,442
December 31, 2022	1,166,218	399,502	66,292	1,632,012
December 31, 2023	1,003,956	377,144	46,839	1,427,939
Proved undeveloped reserves:
December 31, 2020	76,504	12,572	8,341	97,417
December 31, 2021	184,441	9,899	7,124	201,464
December 31, 2022	210,862	1,068	2,304	214,234
December 31, 2023	99,495	2,612	—	102,107

Total proved reserves:
Balance December 31, 2020	1,129,260	421,607	76,500	1,627,367
Extensions, discoveries and other additions	227,684	50,209	3,684	281,577
Purchases of minerals in-place	839	—	—	839
Revisions of previous estimates	279,610	99,143	17,171	395,924
Production	(192,523)	(96,234)	(14,076)	(302,833)
Sales of minerals in-place	(22,968)	—	—	(22,968)
Balance December 31, 2021	1,421,902	474,725	83,279	1,979,906
Extensions, discoveries and other additions	38,157	10,191	1,643	49,991
Purchases of minerals in-place	70,584	—	—	70,584
Revisions of previous estimates	92,599	45,725	(3,431)	134,893
Production	(172,752)	(130,071)	(12,895)	(315,718)
Sales of minerals in-place	(73,410)	—	—	(73,410)
Balance December 31, 2022	1,377,080	400,570	68,596	1,846,246
Extensions, discoveries and other additions	158,118	14,188	3,335	175,641
Purchases of minerals in-place	136	—	—	136
Revisions of previous estimates	(266,664)	83,907	(6,739)	(189,496)
Production	(165,083)	(118,909)	(18,353)	(302,345)
Sales of minerals in-place	(136)	—	—	(136)
Balance December 31, 2023	1,103,451	379,756	46,839	1,530,046

(1) Includes proved reserves of 127 Bcf, 134 Bcf, 158 Bcf, and 141 Bcf as of December 31, 2023, 2022, 2021, and 2020, respectively, attributable to a noncontrolling interest in Egypt.


	Total Equivalent Reserves
	United States	Egypt(1)	North Sea	Total(1)

	(Thousands barrels of oil equivalent)
Proved developed reserves:
December 31, 2020	532,994	164,870	99,979	797,843
December 31, 2021	551,384	184,563	91,825	827,772
December 31, 2022	530,823	174,633	95,859	801,315
December 31, 2023	500,354	165,162	70,343	735,859
Proved undeveloped reserves:
December 31, 2020	53,408	13,449	8,983	75,840
December 31, 2021	65,288	12,683	7,219	85,190
December 31, 2022	76,386	8,735	3,333	88,454
December 31, 2023	65,931	5,690	—	71,621

Total proved reserves:
Balance December 31, 2020	586,402	178,319	108,962	873,683
Extensions, discoveries and other additions	76,871	21,765	2,983	101,619
Purchases of minerals in-place	457	—	—	457
Revisions of previous estimates	64,847	39,071	3,120	107,038
Production	(83,712)	(41,909)	(16,021)	(141,642)
Sales of minerals in-place	(28,193)	—	—	(28,193)
Balance December 31, 2021	616,672	197,246	99,044	912,962
Extensions, discoveries and other additions	21,592	9,278	2,935	33,805
Purchases of minerals in-place	39,110	—	—	39,110
Revisions of previous estimates	33,217	29,647	11,659	74,523
Production	(77,382)	(52,803)	(14,446)	(144,631)
Sales of minerals in-place	(26,000)	—	—	(26,000)
Balance December 31, 2022	607,209	183,368	99,192	889,769
Extensions, discoveries and other additions	95,677	15,344	1,228	112,249
Purchases of minerals in-place	64	—	—	64
Revisions of previous estimates	(56,532)	24,490	(13,889)	(45,931)
Production	(79,302)	(52,350)	(16,188)	(147,840)
Sales of minerals in-place	(831)	—	—	(831)
Balance December 31, 2023	566,285	170,852	70,343	807,480

(1) Includes total proved reserves of 57 MMboe, 61 MMboe, 66 MMboe, and 59 MMboe as of December 31, 2023, 2022, 2021, and 2020, respectively, attributable to a noncontrolling interest in Egypt.

Schedule of Unaudited Information of Future Net Cash Flows For Oil and Gas Reserves, Net of Income Tax Expense


	United States		Egypt(1)		North Sea		Total(1)

	(In millions)
2023
Cash inflows	$	21,417	$	9,921	$	5,761	$	37,099
Production costs	(8,328)		(1,690)		(2,773)		(12,791)
Development costs	(2,238)		(1,235)		(2,461)		(5,934)
Income tax expense	(949)		(2,222)		(946)		(4,117)
Net cash flows	9,902		4,774		(419)		14,257
10 percent discount rate	(3,749)		(943)		476		(4,216)
Discounted future net cash flows(2)	$	6,153	$	3,831	$	57	$	10,041
2022
Cash inflows	$	31,577	$	12,819	$	10,147	$	54,543
Production costs	(10,763)		(2,086)		(3,241)		(16,090)
Development costs	(1,733)		(1,471)		(2,297)		(5,501)
Income tax expense	(1,575)		(2,729)		(2,631)		(6,935)
Net cash flows	17,506		6,533		1,978		26,017
10 percent discount rate	(6,811)		(1,400)		(204)		(8,415)
Discounted future net cash flows(2)	$	10,695	$	5,133	$	1,774	$	17,602
2021
Cash inflows	$	22,852	$	9,337	$	6,832	$	39,021
Production costs	(8,323)		(1,712)		(2,343)		(12,378)
Development costs	(1,632)		(1,402)		(2,533)		(5,567)
Income tax expense	(134)		(1,887)		(768)		(2,789)
Net cash flows	12,763		4,336		1,188		18,287
10 percent discount rate	(5,294)		(983)		350		(5,927)
Discounted future net cash flows(2)	$	7,469	$	3,353	$	1,538	$	12,360

Schedule of Principal Sources of Change In Discounted Future Net Cash Flows

The following table sets forth the principal sources of change in the discounted future net cash flows:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Sales, net of production costs	$	(5,408)	$	(7,131)	$	(4,707)
Net change in prices and production costs	(7,089)		8,690		9,376
Discoveries and improved recovery, net of related costs	1,869		1,142		1,749
Change in future development costs	(413)		(343)		(839)
Previously estimated development costs incurred during the period	825		669		545
Revision of quantities	(262)		2,646		1,983
Purchases of minerals in-place	1		911		1
Accretion of discount	2,260		1,489		626
Change in income taxes	1,467		(2,467)		(1,583)
Sales of minerals in-place	(18)		(363)		(116)
Change in production rates and other	(793)		(1)		13
	$	(7,561)	$	5,242	$	7,048

- Definition

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

+ References + Details

- Definition

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

+ References + Details