Apache 10-K 26 Feb 21 2020 FY Annual report Financial data

Cover

Cover - USD ($)	12 Months Ended
	Dec. 31, 2020	Jan. 29, 2021	Jun. 30, 2020
Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	1-4300
Entity Registrant Name	APACHE CORPORATION
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	41-0747868
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
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
Entity Shell Company	false
Entity Public Float			$ 5,095,687,766
Entity Common Stock, Shares Outstanding		377,860,971
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement relating to the registrant’s 2021 annual meeting of stockholders are incorporated by reference in Part II and Part III of this Annual Report on Form 10-K. On January 4, 2021, the registrant (Apache) announced that its Board of Directors authorized Apache to proceed with the implementation of a holding company reorganization, in connection with which, Apache will create APA Corporation, a new holding company (APA). Upon completion of the holding company reorganization, Apache will be a wholly-owned subsidiary of APA, APA will be
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Entity Central Index Key	0000006769
Nasdaq Global Select Market
Entity Information [Line Items]
Title of 12(b) Security	Common Stock, $0.625 par value
Trading Symbol	APA
Security Exchange Name	NASDAQ

STATEMENT OF CONSOLIDATED OPERA

STATEMENT OF CONSOLIDATED OPERATIONS - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
REVENUES AND OTHER:
Derivative instrument losses, net	$ (223)	$ (35)	$ (17)
Gain on divestitures, net	32	43	23
Other	64	54	53
Total revenues and other	4,308	6,553	7,764
OPERATING EXPENSES:
Lease operating expenses	1,127	1,447	1,439
Taxes other than income	123	207	215
Exploration	274	805	503
General and administrative	290	406	431
Transaction, reorganization, and separation	54	50	28
Depreciation, depletion, and amortization	1,772	2,680	2,405
Asset retirement obligation accretion	109	107	108
Impairments	4,501	2,949	511
Financing costs, net	267	462	478
Total operating expenses	9,148	9,561	6,806
NET INCOME (LOSS) BEFORE INCOME TAXES	(4,840)	(3,008)	958
Current income tax provision	176	660	894
Deferred income tax provision (benefit)	(112)	14	(222)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	(4,904)	(3,682)	286
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$ (4,860)	$ (3,553)	$ 40
NET INCOME (LOSS) PER COMMON SHARE:
Basic (in USD per share)	$ (12.86)	$ (9.43)	$ 0.11
Diluted (in USD per share)	$ (12.86)	$ (9.43)	$ 0.11
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic (in shares)	378	377	382
Diluted (in shares)	378	377	384
Noncontrolling Interest, Egypt
OPERATING EXPENSES:
Net income (loss) attributable to noncontrolling interest	$ (121)	$ 167	$ 245
Noncontrolling Interest, Altus
OPERATING EXPENSES:
Net income (loss) attributable to noncontrolling interest	1	(334)	1
Oil and gas, excluding purchased
REVENUES AND OTHER:
Oil and gas production revenues	4,037	6,315	7,348
OPERATING EXPENSES:
Cost of goods and services sold	274	306	348
Oil and gas, purchased
REVENUES AND OTHER:
Oil and gas production revenues	398	176	357
OPERATING EXPENSES:
Cost of goods and services sold	357	142	340
Oil and gas
REVENUES AND OTHER:
Oil and gas production revenues	$ 4,435	$ 6,491	$ 7,705

STATEMENT OF CONSOLIDATED COMPR

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Net income (loss) including noncontrolling interests	$ (4,904)	$ (3,682)	$ 286
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Pension and postretirement benefit plan	(2)	13	0
Share of equity method interests other comprehensive loss	0	(1)	0
Other comprehensive income, net of tax	(2)	12	0
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	(4,906)	(3,670)	286
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	(4,862)	(3,541)	40
Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Comprehensive income (loss) attributable to noncontrolling interest	76	38	0
Noncontrolling Interest, Egypt
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Comprehensive income (loss) attributable to noncontrolling interest	(121)	167	245
Noncontrolling Interest, Altus
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Comprehensive income (loss) attributable to noncontrolling interest	$ 1	$ (334)	$ 1

STATEMENT OF CONSOLIDATED CASH

STATEMENT OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) including noncontrolling interests	$ (4,904)	$ (3,682)	$ 286
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized derivative instrument losses (gains), net	87	44	(103)
Gain on divestitures, net	(32)	(43)	(23)
Exploratory dry hole expense and unproved leasehold impairments	211	676	351
Depreciation, depletion, and amortization	1,772	2,680	2,405
Asset retirement obligation accretion	109	107	108
Impairments	4,501	2,949	511
Provision for (benefit from) deferred income taxes	(112)	14	(222)
Loss (gain) from extinguishment of debt	(160)	75	94
Other	102	50	125
Changes in operating assets and liabilities:
Receivables	149	133	150
Inventories	19	(41)	(6)
Drilling advances	(21)	(21)	(11)
Deferred charges and other	(21)	51	83
Accounts payable	(167)	(5)	77
Accrued expenses	(163)	(84)	5
Deferred credits and noncurrent liabilities	18	(36)	(53)
NET CASH PROVIDED BY OPERATING ACTIVITIES	1,388	2,867	3,777
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(1,270)	(2,594)	(3,190)
Additions to Altus gathering, processing, and transmission (GPT) facilities	(28)	(327)	(581)
Leasehold and property acquisitions	(4)	(40)	(133)
Contributions to Altus equity method interests	(327)	(501)	0
Acquisition of Altus equity method interests	0	(671)	(91)
Proceeds from asset divestitures	166	718	138
Other	(3)	(31)	(87)
NET CASH USED IN INVESTING ACTIVITIES	(1,466)	(3,446)	(3,944)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from Apache credit facility, net	150	0	0
Proceeds from Altus credit facility	228	396	0
Fixed rate debt borrowings	1,238	989	992
Payments on fixed-rate debt	(1,243)	(1,150)	(1,370)
Proceeds from Altus transaction	0	0	628
Distributions to noncontrolling interest - Egypt	(91)	(305)	(345)
Distributions to Altus Preferred Unit limited partners	(23)	0	0
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	0	611	0
Dividends paid	(123)	(376)	(382)
Treasury stock activity, net	1	2	(305)
Other	(44)	(55)	(5)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	93	112	(787)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	15	(467)	(954)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	247	714	1,668
CASH AND CASH EQUIVALENTS AT END OF PERIOD	262	247	714
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	419	394	402
Income taxes paid, net of refunds	$ 212	$ 649	$ 867

CONSOLIDATED BALANCE SHEET

CONSOLIDATED BALANCE SHEET - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
CURRENT ASSETS:
Cash and cash equivalents ($24 and $6 related to Altus VIE)	$ 262	$ 247
Receivables, net of allowance of $95 and $88	908	1,062
Other current assets (Note 5) ($5 and $5 related to Altus VIE)	676	652
Total current assets	1,846	1,961
Oil and gas, on the basis of successful efforts accounting:
Proved properties	41,217	40,540
Unproved properties and properties under development	602	666
Gathering, processing, and transmission facilities ($206 and $203 related to Altus VIE)	670	799
Other ($3 and $4 related to Altus VIE)	1,140	1,140
Property and equipment, gross	43,629	43,145
Less: Accumulated depreciation, depletion, and amortization ($13 and $1 related to Altus VIE)	(34,810)	(28,987)
Property and equipment, net	8,819	14,158
OTHER ASSETS:
Equity method interests (Note 6) ($1,555 and $1,258 related to Altus VIE)	1,555	1,258
Deferred charges and other ($5 and $4 related to Altus VIE)	526	730
Total assets	12,746	18,107
CURRENT LIABILITIES:
Accounts payable	444	695
Current debt (nil and $10 related to Altus VIE)	2	11
Other current liabilities (Note 7) ($4 and $21 related to Altus VIE)	862	1,149
Total current liabilities	1,308	1,855
LONG-TERM DEBT (Note 9) ($624 and $396 related to Altus VIE)	8,770	8,555
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	215	346
Asset retirement obligation ($64 and $60 related to Altus VIE)	1,888	1,811
Other ($144 and $107 related to Altus VIE)	602	520
Total deferred credits and other noncurrent liabilities	2,705	2,677
COMMITMENTS AND CONTINGENCIES (Note 11)
REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 13)	608	555
EQUITY (DEFICIT):
Common stock, $0.625 par, 860,000,000 shares authorized, 418,429,375 and 417,026,863 shares issued, respectively	262	261
Paid-in capital	11,735	11,769
Accumulated deficit	(10,461)	(5,601)
Treasury stock, at cost, 40,946,745 and 40,964,193 shares, respectively	(3,189)	(3,190)
Accumulated other comprehensive income	14	16
APACHE SHAREHOLDERS’ EQUITY (DEFICIT)	(1,639)	3,255
TOTAL EQUITY (DEFICIT)	(645)	4,465
TOTAL LIABILITIES AND EQUITY	$ 12,746	$ 18,107
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)	418,429,375	417,026,863
Treasury stock, shares (in shares)	40,946,745	40,964,193
Variable Interest Entity, Primary Beneficiary
CURRENT ASSETS:
Cash and cash equivalents ($24 and $6 related to Altus VIE)	$ 24	$ 6
Receivables, net of allowance of $95 and $88	95	88
Other current assets (Note 5) ($5 and $5 related to Altus VIE)	5	5
Oil and gas, on the basis of successful efforts accounting:
Gathering, processing, and transmission facilities ($206 and $203 related to Altus VIE)	206	203
Other ($3 and $4 related to Altus VIE)	3	4
Less: Accumulated depreciation, depletion, and amortization ($13 and $1 related to Altus VIE)	(13)	(1)
OTHER ASSETS:
Equity method interests (Note 6) ($1,555 and $1,258 related to Altus VIE)	1,555	1,258
Deferred charges and other ($5 and $4 related to Altus VIE)	5	4
CURRENT LIABILITIES:
Current debt (nil and $10 related to Altus VIE)	0	10
Other current liabilities (Note 7) ($4 and $21 related to Altus VIE)	4	21
LONG-TERM DEBT (Note 9) ($624 and $396 related to Altus VIE)	624	396
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Asset retirement obligation ($64 and $60 related to Altus VIE)	64	60
Other ($144 and $107 related to Altus VIE)	144	107
Noncontrolling Interest, Egypt
EQUITY (DEFICIT):
Noncontrolling interest	925	1,137
Noncontrolling Interest, Altus
EQUITY (DEFICIT):
Noncontrolling interest	$ 69	$ 73

CONSOLIDATED BALANCE SHEET (Par

CONSOLIDATED BALANCE SHEET (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Cash and cash equivalent	$ 262	$ 247
Receivables net of allowance	908	1,062
Other current assets (Note 5) ($5 and $5 related to Altus VIE)	676	652
Gathering, processing, and transmission facilities ($206 and $203 related to Altus VIE)	670	799
Other property and equipment	1,140	1,140
Accumulated depreciation	34,810	28,987
Equity method interests	1,555	1,258
Deferred charges and other	526	730
Current debt	2	11
Other current liabilities	862	1,149
Long-term debt	8,770	8,555
Asset retirement obligation	1,888	1,811
Other noncurrent liabilities	$ 602	$ 520
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)	418,429,375	417,026,863
Treasury stock, shares (in shares)	40,946,745	40,964,193
Variable Interest Entity, Primary Beneficiary
Cash and cash equivalent	$ 24	$ 6
Receivables net of allowance	95	88
Other current assets (Note 5) ($5 and $5 related to Altus VIE)	5	5
Gathering, processing, and transmission facilities ($206 and $203 related to Altus VIE)	206	203
Other property and equipment	3	4
Accumulated depreciation	13	1
Equity method interests	1,555	1,258
Deferred charges and other	5	4
Current debt	0	10
Other current liabilities	4	21
Long-term debt	624	396
Asset retirement obligation	64	60
Other noncurrent liabilities	$ 144	$ 107

STATEMENT OF CONSOLIDATED CHANG

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST - USD ($) $ in Millions	Total	Common Stock	Paid-In Capital	Accumulated Deficit	Treasury Stock	Accumulated Other Comprehensive Income (Loss)	APACHE SHAREHOLDERS’ EQUITY (DEFICIT)	Noncontrolling Interests	Noncontrolling Interest, Egypt	Noncontrolling Interest, Altus	Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners
Beginning balance at Dec. 31, 2017											$ 0
Increase (Decrease) in Temporary Equity [Roll Forward]
Distributions to Altus Preferred Unit limited partners	$ (345)							$ (345)
Ending balance at Dec. 31, 2018											0
Beginning balance at Dec. 31, 2017	8,791	$ 259	$ 12,128	$ (2,088)	$ (2,887)	$ 4	$ 7,416	1,375
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss attributable to common stock	40			40			40
Net income attributable to noncontrolling interest									$ 245	$ 1
Distributions to noncontrolling interest	(345)							(345)
Pension & Postretirement benefit plans, net of tax	0
Common dividends	(380)		(380)				(380)
Common stock activity, net	(28)	1	(29)				(28)
Treasury stock activity, net	(305)				(305)		(305)
Proceeds from Altus transaction	628		222				222	406
Compensation expense	160		160				160
Other	5		5				5
Ending balance at Dec. 31, 2018	8,812	260	12,106	(2,048)	(3,192)	4	7,130	1,682
Increase (Decrease) in Temporary Equity [Roll Forward]
Issuance of Altus Preferred Units											517
Net income attributable to Altus Preferred Unit limited partners											38
Distributions to Altus Preferred Unit limited partners	(305)							(305)
Ending balance at Dec. 31, 2019	555										555
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss attributable to common stock	(3,553)			(3,553)			(3,553)
Net income attributable to noncontrolling interest									167	(334)
Distributions to noncontrolling interest	(305)							(305)
Pension & Postretirement benefit plans, net of tax	13					13	13
Common dividends	(376)		(376)				(376)
Common stock activity, net	(21)	1	(22)				(21)
Compensation expense	61		61				61
Other	1				2	(1)	1
Ending balance at Dec. 31, 2019	4,465	261	11,769	(5,601)	(3,190)	16	3,255	1,210
Increase (Decrease) in Temporary Equity [Roll Forward]
Net income attributable to Altus Preferred Unit limited partners											76
Distributions to Altus Preferred Unit limited partners									(91)	(5)	(23)
Ending balance at Dec. 31, 2020	608										608
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss attributable to common stock	(4,860)			(4,860)			(4,860)
Net income attributable to noncontrolling interest									(121)	1
Distributions to noncontrolling interest									$ (91)	$ (5)	$ (23)
Pension & Postretirement benefit plans, net of tax	(2)					(2)	(2)
Common dividends	(38)		(38)				(38)
Common stock activity, net	(17)	1	(18)				(17)
Compensation expense	23		23				23
Other	0		(1)		1		0
Ending balance at Dec. 31, 2020	$ (645)	$ 262	$ 11,735	$ (10,461)	$ (3,189)	$ 14	$ (1,639)	$ 994

STATEMENT OF CONSOLIDATED CHA_2

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Stockholders' Equity [Abstract]
Common stock, dividends, per share (in USD per share)	$ 0.10	$ 1	$ 1

NATURE OF OPERATIONS

NATURE OF OPERATIONS	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations	Nature of Operations Apache Corporation (Apache or the Company) is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. The Company’s upstream business has exploration and production operations in three geographic areas: the United States (U.S.), Egypt, and offshore the U.K. in the North Sea (North Sea). Apache also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. Apache’s midstream business is operated by Altus Midstream Company (Nasdaq: ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas. On January 4, 2021, Apache announced that its Board of Directors authorized the Company to proceed with the implementation of a holding company reorganization, in connection with which, Apache will create APA Corporation, a new holding company (APA). Upon completion of the holding company reorganization, Apache will be a wholly-owned subsidiary of APA, APA will be the successor issuer to Apache pursuant to Rule 12g-3(a) under the Exchange, and APA will replace Apache as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA” (the Holding Company Reorganization). The Holding Company Reorganization has not yet been implemented, but it is expected to be completed during the first half of 2021.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Accounting policies used by Apache 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 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 Apache and its subsidiaries after elimination of intercompany balances and transactions. 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 Apache 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 Apache’s Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate component of equity in the Company’s consolidated balance sheet. Additionally, third-party investors own a minority interest of approximately 21 percent of Altus Midstream Company (ALTM), which is reflected as a separate noncontrolling interest component of equity in Apache’s consolidated balance sheet. ALTM qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of ALTM because it has concluded that it has a controlling financial interest in ALTM and is the primary beneficiary of the VIE. On June 12, 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units (the Preferred Units) through a private offering that admitted additional limited partners with separate rights for the Preferred Unit holders. Refer to Note 1 3 —Redeemable Noncontrolling Interest - Altus for further detail. Investments in which the Company holds less than 50 percent of the voting interest are typically accounted for under the equity method of accounting, with the balance recorded separately as “Equity method interests” in the Company’s consolidated balance sheet and as a component of “Other” under “Revenues and Other” in the Company’s statement of consolidated operations. 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 (see “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (see Note 2—Acquisitions and Divestitures ), the assessment of asset retirement obligations (see Note 8—Asset Retirement Obligation ), the estimate of income taxes (see Note 10—Income Taxes ), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (see 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 Apache’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). Recurring fair value measurements are presented in further detail in Note 4—Derivative Instruments and Hedging Activities , Note 9—Debt and Financing Costs , Note 12—Retirement and Deferred Compensation Plans , and Note 13—Redeemable Noncontrolling Interest - Altus . The Company also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. The following table presents a summary of asset impairments recorded in connection with fair value assessments: For the Year Ended December 31, 2020 2019 2018 (In millions) Oil and gas proved property $ 4,319 $ 1,484 $ 328 Gathering, processing, and transmission facilities 68 1,295 56 Equity method investment — — 113 Divested unproved properties and leasehold — 149 10 Goodwill 87 — — Inventory and other 27 21 4 Total Impairments $ 4,501 $ 2,949 $ 511 For the year ended December 31, 2020, the Company recorded asset impairments totaling $4.5 billion in connection with fair value assessments. Given the crude oil price collapse on lower demand and economic activity resulting from the coronavirus disease 2019 (COVID-19) global pandemic and related governmental actions, the Company assessed its oil and gas property and gathering, processing, and transmission (GPT) facilities for impairment based on the net book value of its assets as of March 31, 2020. The Company recorded proved property impairments totaling $3.9 billion, $354 million, and $7 million in the U.S., Egypt, and North Sea, respectively, all of which were impaired to their estimated fair values as a result of lower forecasted commodity prices, changes to planned development activity, and increasing market uncertainty. Impairments totaling $68 million were similarly recorded for GPT facilities in Egypt. These impairments are discussed in further detail below in “Property and Equipment - Oil and Gas Property” and “Property and Equipment - Gathering, Processing, and Transmission Facilities.” The Company also performed an interim impairment analysis of the goodwill related to its Egypt reporting unit. Reductions in estimated net present value of expected future cash flows from oil and gas properties resulted in implied fair values below the carrying values of the Company’s Egypt reporting unit. As a result of these assessments, the Company recognized non-cash impairments of the entire amount of recorded goodwill in the Egypt reporting unit of $87 million in the first quarter of 2020. During the remainder of 2020, the Company recorded additional proved property impairments totaling $20 million in Egypt, as well as $13 million for the early termination of drilling rig leases, $5 million for inventory revaluations, and $9 million of other asset impairments, all in the U.S. During the fourth quarter of 2019, following a material reduction to planned investment in Apache’s Alpine High development, the Company recorded impairments totaling $1.4 billion for its Alpine High proved properties and upstream infrastructure which were written down to their fair values. Altus separately assessed its long-lived infrastructure assets for impairment based on expected reductions to future throughput volumes from Alpine High. Altus subsequently recorded impairments totaling $1.3 billion on its GPT facilities. These impairments are discussed in further detail below in “Property and Equipment - Oil and Gas Property” and “Property and Equipment - Gathering, Processing, and Transmission Facilities.” Separate from the Company’s Alpine High and Altus impairments, Apache entered into agreements to sell certain of its assets in the western Anadarko Basin in Oklahoma and Texas. As a result of these agreements, a separate impairment analysis was performed for each of the assets within the disposal groups. The analyses were based on the agreed-upon proceeds less costs to sell for the transaction, a Level 1 fair value measurement. The carrying value of the net assets to be divested exceeded the fair value implied by the expected net proceeds, resulting in impairments in the second and fourth quarters of 2019 totaling $255 million, including $101 million on the Company’s proved properties, $149 million on its unproved properties, and $5 million on other working capital. For more information regarding this transaction, refer to Note 2—Acquisitions and Divestitures . For the year ended December 31, 2018, the Company recorded asset impairments totaling $511 million in connection with fair value assessments. Impairments totaling $328 million and $56 million were recorded for proved properties, and a gathering and processing facility in Oklahoma, respectively, which were written down to their fair values associated with U.S. assets to be divested. During the third quarter of 2018, Apache agreed to sell certain of its unproved properties offshore the U.K. in the North Sea. As a result, the Company performed a fair value assessment of the properties and recorded a $10 million impairment on the carrying values of the associated capitalized exploratory well costs. The fair value of the impaired assets was determined using the negotiated sales price, a Level 1 fair value measurement. Also in 2018, the Company recorded $113 million for the impairment of an equity method investment in the U.S. based on a negotiated sales price and $4 million for inventory write-downs in the U.S. for obsolescence. 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, 2020 and 2019, the Company had $262 million and $247 million, respectively, of cash and cash equivalents, of which approximately $24 million and $6 million, respectively, was held by Altus. The Company had no restricted cash as of December 31, 2020 and 2019. 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. In June 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-13, “Financial Instruments-Credit Losses.” The standard changes the impairment model for trade receivables, held-to-maturity debt securities, net investments in leases, loans, and other financial assets measured at amortized cost. This ASU requires the use of a new forward-looking “expected loss” model compared to the previous “incurred loss” model, resulting in accelerated recognition of credit losses. Apache adopted this update in the first quarter of 2020. This ASU primarily applies to the Company’s accounts receivable balances, of which the majority are received within a short-term period of one year or less. 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 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 adoption and implementation of this ASU did not have a material impact on the Company’s financial statements. The following table presents changes to the Company’s allowance for credit loss: For the Year Ended December 31, 2020 2019 2018 (In millions) Allowance for credit loss at beginning of year $ 88 $ 92 $ 84 Additional provisions for the year 7 3 9 Uncollectible accounts written off, net of recoveries — (7) (1) Allowance for credit loss at end of year $ 95 $ 88 $ 92 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. 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, 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. 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 Apache’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. The significant decline in crude oil and natural gas prices, as well as longer-term commodity price outlooks, related to reduced demand for oil and natural gas as a result of the COVID-19 pandemic and related governmental actions indicated possible impairment of the Company’s proved and unproved oil and gas properties in early 2020. In addition to estimating risk-adjusted reserves and future production volumes, estimated future commodity prices are the largest driver in variability of undiscounted pre-tax cash flows. Expected cash flows were estimated based on management’s views of published West Texas Intermediate (WTI), Brent, and Henry Hub forward pricing as of the balance sheet dates. Other significant assumptions and inputs used to calculate estimated future cash flows include estimates for future development activity, exploration plans and remaining lease terms. A 10 percent discount rate, based on a market-based weighted-average cost of capital estimate, was applied to the undiscounted cash flow estimate to value all of the Company’s asset groups that were subject to impairment charges in 2020. Similar assumptions were applied to impairments recorded in 2019 and 2018. The following table represents non-cash impairments charges of the carrying value of the Company’s proved and unproved properties: For the Year Ended December 31, 2020 2019 2018 (In millions) Proved properties: U.S. $ 3,938 $ 1,484 $ 265 Egypt 374 — 63 North Sea 7 — — Total proved properties $ 4,319 $ 1,484 $ 328 Unproved properties: U.S. $ 92 $ 760 $ 96 Egypt 8 8 — North Sea 1 — 128 Total unproved properties $ 101 $ 768 $ 224 Proved properties impaired had aggregate fair values as of the most recent date of impairment of $1.9 billion and $628 million for 2020 and 2019, respectively. Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. However, in 2019, unproved impairments of $149 million were recorded as a component of “Impairments” in connection with an agreement to sell certain non-core leasehold properties in Oklahoma and Texas. In addition, in 2018, unproved impairments of $10 million were recorded as a component of “Impairments” in connection with an agreement to sell certain unproved properties in the North Sea. 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 Facilities GPT facilities totaled $670 million and $799 million at December 31, 2020 and 2019, respectively, with accumulated depreciation for these assets totaling $323 million and $310 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 Apache-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within or in close proximity 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. Apache assessed its long-lived infrastructure assets for impairment at March 31, 2020, and recorded an impairment of $68 million on its GPT facilities in Egypt during the first quarter of 2020. The fair values of the impaired assets, which were determined to be $46 million, were estimated using the income approach, which considers internal estimates based on future throughput volumes from applicable development concessions in Egypt and estimated costs to operate. These assumptions were applied based on throughput assumptions developed in relation to the oil and gas proved property impairment assessment as discussed above to develop future cash flow projections that were then discounted to estimated fair value, using a 10 percent discount rate, based on a market-based weighted-average cost of capital estimate. Apache has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy. As discussed under “Fair Value Measurements” above, the Company decided to materially reduce its planned investment in the Alpine High play during its fourth-quarter 2019 capital planning review. Altus management subsequently assessed its long-lived infrastructure assets for impairment given the expected reduction to future throughput volumes and recorded impairments of $1.3 billion on its gathering, processing, and transmission assets. The fair values of the impaired assets were determined to be $203 million as of the time of the impairment and were estimated using the income approach. The income approach considered internal estimates of future throughput volumes, processing rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using discount rates believed to be consistent with those applied by market participants. Apache has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy. During 2018, the Company recorded impairments of the entire net book value of certain GPT assets in the U.S. in the amount of $56 million associated with a proposed divestiture package. The costs of GPT assets sold or otherwise disposed of and associated accumulated depreciation are removed from Apache’s consolidated financial statements, and the resulting gain or loss is reflected in “Gain on divestitures” under “Revenues and Other” in the Company’s statement of consolidated operations. A $2 million loss was recorded on the sale of power generators during 2020, and no gain or loss on the sales of GPT facilities was recognized during 2019 or 2018. 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 totaled $1.1 billion at each of December 31, 2020 and 2019, with accumulated depreciation for these assets totaling $864 million and $817 million at December 31, 2020 and 2019, 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. Goodwill Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed, and it is recorded in “Deferred charges and other” in the Company’s consolidated balance sheet. The Company assesses the carrying amount of goodwill by testing for impairment annually and when impairment indicators arise. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. Apache assesses each country as a reporting unit, with Egypt being the only reporting unit to have associated goodwill. The fair value of the reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then goodwill is written down to its implied fair value through a charge to expense. When there is a disposal of a reporting unit or a portion of a reporting unit that constitutes a business, goodwill associated with that business is included in the carrying amount to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount is based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained. The following presents the changes to goodwill for the years ended 2020, 2019, and 2018: Egypt Total (In millions) Goodwill at December 31, 2017 $ 87 $ 87 Impairments — — Goodwill at December 31, 2018 87 87 Impairments — — Goodwill at December 31, 2019 87 87 Impairments (87) (87) Goodwill at December 31, 2020 $ — $ — Reductions in estimated net present value of expected future cash flows from oil and gas properties resulted in implied fair values below the carrying values of the Company’s Egypt reporting unit. As a result of these assessments, the Company recognized non-cash impairments of the entire amount of recorded goodwill in the Egypt reporting unit of $87 million. This goodwill impairment has been recorded in “Impairments” in the Company’s statement of consolidated operations. 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 . Revenue Recognition The years ended 2019 and 2018 include the reclassification of $176 million and $357 million, respectively, from “Other” to “Purchased oil and gas sales,” both within “Revenues and Other” and the respective associated $142 million and $340 million purchased oil and gas costs from “Other” within “Revenues and Other” to “Purchased oil and gas costs” within “Operating Expenses” on the Company’s consolidated statement of operations to conform to the current-year presentation. 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 Apache-related production volumes, the Company also sells commodity volumes purchased from third-parties to fulfill sales obligations and commitments as the Company’s production fluctuates with potential operational issues and changes to development plans. Under these short-term 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. The Company’s Egypt operations are conducted pursuant to production sharing contracts under which the contractor partners (Contractors) pay all operating and capital costs for exploring and developing defined concessions. A percentage of the production, generally up to 40 percent, is available to Contractors to recover these operating and capital costs over contractually defined periods. The balance of the production is split among the Contractors and the Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. Additionally, the Contractors’ income taxes, which remain the liability of the Contractors under domestic law, are paid by EGPC on behalf of the Contractors out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of Apache as Contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Revenues related to Egypt’s tax volumes are considered revenue from a non-customer. Refer to Note 1 7 —Business Segment Information for a disaggregation of revenue

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES	12 Months Ended
	Dec. 31, 2020
Business Combinations [Abstract]
ACQUISITIONS AND DIVESTITURES	ACQUISITIONS AND DIVESTITURES 2020 Activity During 2020, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $4 million. Also during 2020, the Company completed the sale of certain non-core assets and leasehold, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $87 million, and recognized a gain of $13 million. 2019 Activity U.S. Divestitures In the third quarter of 2019, Apache completed the sale of non-core assets in the western Anadarko Basin of Oklahoma and Texas for aggregate cash proceeds of approximately $322 million and the assumption of asset retirement obligations of $49 million. These assets met the criteria to be classified as held for sale in the second quarter of 2019. Accordingly, the Company performed a fair value assessment of the assets and recorded impairments of $240 million to the carrying value of proved and unproved oil and gas properties, other fixed assets, and working capital. The transaction closed in the third quarter of 2019, and the Company recognized a $7 million loss in connection with the sale. In the second quarter of 2019, Apache completed the sale of certain non-core assets in Oklahoma that had a net carrying value of $206 million for aggregate cash proceeds of approximately $223 million. The Company recognized a $17 million gain in connection with the sale. During 2019, the Company also completed the sale of certain other non-core producing assets, GPT assets, and leasehold acreage, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $73 million. The Company recognized a net gain of approximately $33 million upon closing of these transactions. Suriname Joint Venture Agreement In December 2019, Apache entered into a joint venture agreement with Total S.A. to explore and develop Block 58 offshore Suriname. Under the terms of the agreement, Apache and Total S.A. each hold a 50 percent working interest in Block 58. Pursuant to the agreement, Apache operated the drilling of the first four wells, the Maka Central-1, Sapakara West-1, Kwaskwasi-1, and Keskesi East-1, and subsequently transferred operatorship of Block 58 to Total S.A. on January 1, 2021. Apache will continue to operate the Keskesi exploration well until completion of drilling operations. In connection with the agreement, Apache received $100 million from Total S.A. upon closing in the fourth quarter of 2019 and $79 million upon satisfying certain closing conditions in the first quarter of 2020 for reimbursement of 50 percent of all costs incurred on Block 58 as of December 31, 2019. All proceeds were applied against the carrying value of the Company’s Suriname properties and associated inventory. The Company recognized a $19 million gain in the first quarter of 2020 associated with the transaction. Apache will also receive various other forms of consideration, including $5.0 billion of cash carry on Apache’s first $7.5 billion of appraisal and development capital, 25 percent cash carry on all of Apache’s appraisal and development capital beyond the first $7.5 billion, a $75 million cash payment upon achieving first oil production, and future contingent royalty payments from successful joint development projects. Leasehold, Property, and Other Acquisitions During 2019, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $40 million. As part of the Altus transaction described below, Apache contributed options (Pipeline Options) to acquire equity interests in five separate third-party pipeline projects (the Equity Method Interest Pipelines) to Altus Midstream and/or its subsidiaries. As of December 31, 2019, four of the five Pipeline Options had been exercised to acquire various ownership interests in the associated Equity Method Interest Pipelines. The fifth Pipeline Option to acquire an equity interest in a separate intra-basin NGL pipeline was not exercised and expired on March 2, 2020. For discussion of the Equity Method Interest Pipelines, refer to Note 6—Equity Method Interests . 2018 Activity Altus Transaction In November 2018, Apache completed a transaction with Altus Midstream Company to create a pure-play, Permian Basin midstream C-corporation anchored by the Company’s GPT assets at Alpine High. Pursuant to the agreement, the Company contributed certain Alpine High midstream assets and the Pipeline Options to Altus and/or its subsidiaries. Altus Midstream Company contributed approximately $628 million of cash, net of transaction expenses. The transaction was accounted for by Altus as a reverse recapitalization. Under this method of accounting, Altus Midstream Company was treated as the “acquired” company, and Apache’s contributed assets of approximately $1.1 billion remained at historical cost, with no goodwill or other intangible assets recorded. Apache owns an approximate 79 percent ownership interest in Altus. Apache fully consolidates the assets and liabilities of Altus in its consolidated financial statements, with a corresponding noncontrolling interest reflected separately. Apache recorded a noncontrolling interest of $406 million upon closing, which is reflected as a separate component of equity in the Company’s consolidated balance sheet. This represents approximately 21 percent third party ownership of the net assets in Altus at the time of the transaction. The cash contributions in excess of the noncontrolling interest were recognized as additional paid-in capital. Other Activity During 2018, the Company completed the sale of certain non-core assets and leasehold, primarily in the North Sea and Permian Basin, in multiple transactions for total cash proceeds of $138 million. The Company recognized gains of approximately $23 million during 2018 upon the closing of these transactions. During 2018, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for cash proceeds of $133 million.

CAPITALIZED EXPLORATORY WELL CO

CAPITALIZED EXPLORATORY WELL COSTS	12 Months Ended
	Dec. 31, 2020
Extractive Industries [Abstract]
CAPITALIZED EXPLORATORY WELL COSTS	CAPITALIZED EXPLORATORY WELL COSTS The following summarizes the changes in capitalized exploratory well costs for the years ended December 31, 2020, 2019, and 2018. 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, 2020 2019 2018 (In millions) Capitalized well costs at beginning of year $ 141 $ 159 $ 350 Additions pending determination of proved reserves 226 286 602 Divestitures and other (38) (100) (82) Reclassifications to proved properties (56) (179) (647) Charged to exploration expense (76) (25) (64) Capitalized well costs at end of year $ 197 $ 141 $ 159 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: 2020 2019 2018 (In millions) Exploratory well costs capitalized for a period of one year or less $ 184 $ 108 $ 126 Exploratory well costs capitalized for a period greater than one year 13 33 33 Capitalized well costs at end of year $ 197 $ 141 $ 159 Number of projects with exploratory well costs capitalized for a period greater than one year 5 2 2 Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling at December 31, 2020, relate to onshore projects in Egypt. Drilling activity and testing has continued for these projects throughout 2020, and these projects are currently being evaluated for potential development. Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling at December 31, 2019, relate to separate onshore projects in the United States and Egypt. The costs related to the U.S. projects were charged to exploration expense in the current year based on management’s assessment and development efforts through year end. Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling at December 31, 2018, included $28 million related to exploratory drilling in Suriname. In December 2019, Apache entered into the joint venture agreement with Total S.A., pursuant to which Apache sold 50 percent of its ownership interest in Block 58 to Total S.A. Proceeds received from Total S.A. upon closing were applied against the carrying value of its Suriname properties. The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2020, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed: Total 2019 2018 2017 and Prior (In millions) Egypt $ 13 $ 4 $ 9 $ — $ 13 $ 4 $ 9 $ —

DERIVATIVE INSTRUMENTS AND HEDG

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Objectives and Strategies Apache is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, as well as 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, Apache utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of December 31, 2020, the Company had derivative positions with six 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, Apache may not realize the benefit of some of its derivative instruments resulting from changes in commodity prices, currency exchange rates, or interest rates. Derivative Instruments Commodity Derivative Instruments As of December 31, 2020, the Company had the following open natural gas financial basis swap contracts: Basis Swap Purchased Basis Swap Sold Production Period Settlement Index MMBtu Weighted Average Price Differential MMBtu Weighted Average Price Differential April—December 2021 NYMEX Henry Hub/IF Waha 37,580 $(0.43) — — April—December 2021 NYMEX Henry Hub/IF HSC — — 37,580 $(0.07) January—December 2022 NYMEX Henry Hub/IF Waha 43,800 $(0.45) — — January—December 2022 NYMEX Henry Hub/IF HSC — — 43,800 $(0.08) Embedded Derivatives Altus Preferred Units Embedded Derivative During the second quarter of 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units. Certain redemption features embedded within the Preferred Units require bifurcation and measurement at fair value. For further discussion of this derivative, see “Fair Value Measurements” below and Note 13—Redeemable Noncontrolling Interest - Altus . Pipeline Capacity Embedded Derivatives During the fourth quarter of 2019 and first quarter of 2020, Apache entered into separate agreements to assign a portion of its contracted capacity under an existing transportation agreement to third parties. Embedded in these agreements are arrangements under which Apache has the potential to receive payments calculated based on pricing differentials between Houston Ship Channel and Waha during calendar years 2020 and 2021. These features require bifurcation and measurement of the change in market values for each period. Unrealized gains or losses in the fair value of these features are recorded as “Derivative instrument losses, net” under “Revenues and Other” in the statement of consolidated operations. Any proceeds received will be deferred and reflected in income over the original tenure of the transportation agreement. 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 Total Fair Value Netting (1) Carrying Amount (In millions) December 31, 2020 Assets: Commodity derivative instruments $ — $ 11 $ — $ 11 $ — $ 11 Liabilities: Pipeline capacity embedded derivatives — 53 — 53 — 53 Preferred Units embedded derivative — — 139 139 — 139 December 31, 2019 Assets: Pipeline capacity embedded derivative $ — $ 8 $ — $ 8 $ — $ 8 Foreign currency derivative instruments — 1 — 1 — 1 Liabilities: Preferred Units embedded derivative — — 103 103 — 103 (1) The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties. The fair values of the Company’s derivative instruments and pipeline capacity embedded derivatives 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. The fair value of the Preferred Units embedded derivative is calculated using an income approach, a Level 3 fair value measurement. The fair value determination is based on a range of factors, including expected future interest rates using the Black-Karasinski model, Altus’ imputed interest rate, interest rate volatility, the expected timing of periodic cash distributions, the estimated timing for the potential exercise of the exchange option, and anticipated dividend yields of the Preferred Units. As of the December 31, 2020 valuation date, the Company used the forward B-rated Energy Bond Yield curve to develop the following key unobservable inputs used to value this embedded derivative: Quantitative Information About Level 3 Fair Value Measurements Fair Value at December 31, 2020 Valuation Technique Significant Unobservable Inputs Range/Value (In millions) Preferred Units embedded derivative $ 139 Option Model Altus’ Imputed Interest Rate 7.32-11.73% Interest Rate Volatility 37.08% A one percent increase in the imputed interest rate assumption would significantly increase the value of the embedded derivative as of December 31, 2020, while a one percent decrease would lead to a similar decrease in value as of December 31, 2020. The assumed expected timing until exercise of the exchange option at December 31, 2020 was 5.45 years. 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: 2020 2019 (In millions) Current Assets: Other current assets $ 6 $ 2 Noncurrent Assets: Deferred charges and other 5 7 Total derivative assets $ 11 $ 9 Deferred Credits and Other Noncurrent Liabilities: Other $ 192 $ 103 Total derivative liabilities $ 192 $ 103 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, 2020 2019 2018 (In millions) Realized: Commodity derivative instruments $ (135) $ 27 $ (81) Amortization of put premium, realized loss — — (39) Foreign currency derivative instruments (1) — — Treasury-lock — (18) — Realized gain (loss), net (136) 9 (120) Unrealized: Commodity derivative instruments 11 (44) 103 Pipeline capacity embedded derivatives (61) 8 — Foreign currency derivative instruments (1) 1 — Preferred Units embedded derivative (36) (9) — Unrealized gain (loss), net (87) (44) 103 Derivative instrument losses, net $ (223) $ (35) $ (17) Derivative instrument gains and losses are recorded in “Derivative instrument 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 losses (gains), net” in “Adjustments to reconcile net loss to net cash provided by operating activities.”

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS	12 Months Ended
	Dec. 31, 2020
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
OTHER CURRENT ASSETS	OTHER CURRENT ASSETS The following table provides detail of the Company’s other current assets as of December 31: 2020 2019 (In millions) Inventories $ 492 $ 502 Drilling advances 113 92 Prepaid assets and other 71 58 Total Other current assets $ 676 $ 652

EQUITY METHOD INTERESTS

EQUITY METHOD INTERESTS	12 Months Ended
	Dec. 31, 2020
Equity Method Investments and Joint Ventures [Abstract]
EQUITY METHOD INTERESTS	EQUITY METHOD INTERESTS As of December 31, 2020 and 2019, Apache, through its ownership of Altus, has the following equity method interests in four Permian Basin long-haul pipeline entities, which are accounted for under the equity method of accounting. For each of the equity method interests, Altus has the ability to exercise significant influence based on certain governance provisions and its participation in activities and decisions that impact the management and economic performance of the equity method interests. Interest 2020 2019 (In millions) Gulf Coast Express Pipeline LLC 16.0 % $ 284 $ 291 EPIC Crude Holdings, LP 15.0 % 176 163 Permian Highway Pipeline LLC 26.7 % 615 311 Shin Oak Pipeline (Breviloba, LLC) 33.0 % 480 493 Total Altus equity method interests $ 1,555 $ 1,258 As of December 31, 2020 and 2019, unamortized basis differences included in the equity method interest balances were $38 million and $30 million, respectively. These amounts represent differences in Altus’ initial costs paid to acquire the equity method interests and its initial underlying equity in the respective entities, as well as capitalized interest related to Permian Highway Pipeline (PHP) construction costs. Unamortized basis differences are amortized into equity income (loss) over the useful lives of the underlying pipeline assets when they are placed into service. The following table presents the activity in Altus’ equity method interests for the years ended December 31, 2020 and 2019: Gulf Coast Express Pipeline LLC EPIC Crude Holdings, LP Permian Highway Pipeline LLC Breviloba, LLC Total (In millions) Balance at December 31, 2018 $ 91 $ — $ — $ — $ 91 Acquisitions 15 52 162 442 671 Capital contributions 184 123 147 47 501 Distributions (16) (9) (25) Capitalized interest (1) — — 2 — 2 Equity income (loss), net 17 (11) — 13 19 Accumulated other comprehensive loss — (1) — — (1) Balance at December 31, 2019 291 163 311 493 1,258 Capital contributions 2 29 296 — 327 Distributions (51) — — (46) (97) Capitalized interest (1) — — 8 — 8 Equity income (loss), net 42 (16) — 33 59 Balance at December 31, 2020 $ 284 $ 176 $ 615 $ 480 $ 1,555 (1) Altus’ proportionate share of the PHP construction costs is funded with Altus’ revolving credit facility. Accordingly, Altus capitalized $8 million and $2 million of related interest expense during 2020 and 2019, respectively, which are included in the basis of the PHP equity interest. Summarized Combined Financial Information The following presents summarized information of combined statement of operations for Altus’ equity method interests (on a 100 percent basis): For the Year Ended December 31, 2020 2019 (1) 2018 (2) (In millions) Operating revenues $ 707 $ 302 $ 3 Operating income (loss) 331 121 (6) Net income (loss) 256 120 (6) Other comprehensive loss 3 (8) — (1) Although Altus’ interests in EPIC Crude Holdings, LP, Permian Highway Pipeline LLC, and Breviloba, LLC were acquired in March, May, and July 2019, respectively, the combined financial results are presented for the year ended December 31, 2019 for comparability. (2) Although Altus’ interest in Gulf Coast Express Pipeline LLC was acquired in December 2018, the combined financial results are presented for the year ended December 31, 2018 for comparability. The following presents summarized combined balance sheet information for Altus’ equity method interests (on a 100 percent basis) as of December 31: 2020 2019 (In millions) Current assets $ 260 $ 441 Noncurrent assets 7,678 6,435 Total assets $ 7,938 $ 6,876 Current liabilities $ 206 $ 478 Noncurrent liabilities 1,191 958 Equity 6,541 5,440 Total liabilities and equity $ 7,938 $ 6,876

OTHER CURRENT LIABILITIES

OTHER CURRENT LIABILITIES	12 Months Ended
	Dec. 31, 2020
Payables and Accruals [Abstract]
OTHER CURRENT LIABILITIES	OTHER CURRENT LIABILITIES The following table provides detail of the Company’s other current liabilities as of December 31: 2020 2019 (In millions) Accrued operating expenses $ 91 $ 143 Accrued exploration and development 167 319 Accrued gathering, processing, and transmission - Altus — 17 Accrued compensation and benefits 170 212 Accrued interest 140 135 Accrued income taxes 25 51 Current asset retirement obligation 56 47 Current operating lease liability 116 169 Other 97 56 Total Other current liabilities $ 862 $ 1,149

ASSET RETIREMENT OBLIGATION

ASSET RETIREMENT OBLIGATION	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATION	ASSET RETIREMENT OBLIGATION The following table describes changes to the Company’s asset retirement obligation (ARO) liability: For the Year Ended December 31, 2020 2019 (In millions) Asset retirement obligation at beginning of year $ 1,858 $ 1,932 Liabilities incurred 10 41 Liabilities divested (26) (56) Liabilities settled (30) (56) Accretion expense 109 107 Revisions in estimated liabilities 23 (110) Asset retirement obligation at end of year 1,944 1,858 Less current portion (56) (47) Asset retirement obligation, long-term $ 1,888 $ 1,811 The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with Apache’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 2020 and 2019, the Company recorded $10 million and $41 million, respectively, in abandonment liabilities resulting from Apache’s exploration and development capital program. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period. During 2020, approximately $23 million net abandonment costs were revised upward to reflect changes in estimates of timing and costs, primarily in the North Sea. During 2019, approximately $110 million net abandonment costs were revised downward to reflect changes in estimates of timing and costs, primarily in the North Sea.

DEBT AND FINANCING COSTS

DEBT AND FINANCING COSTS	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
DEBT AND FINANCING COSTS	DEBT AND FINANCING COSTS Overview All of the Company’s debt is senior unsecured debt and has equal priority with respect to the payment of both principal and interest. All indentures for the notes and debentures described below place certain restrictions on the Company, including limits on Apache’s ability to incur debt secured by certain liens. Certain of these indentures also restrict the Company’s ability to enter into certain sale and leaseback transactions and give holders the option to require the Company 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. In August 2018, Apache closed an offering of $1.0 billion in aggregate principal amount of senior unsecured 4.375% notes due October 15, 2028. The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers, repay notes that matured in September 2018, and for general corporate purposes. Also in August 2018, Apache closed cash tender offers for certain outstanding notes. Apache accepted for purchase $731 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate of approximately $828 million reflecting principal, the discount to par, early tender premium, and accrued and unpaid interest. The Company recorded a net loss of $94 million on extinguishment of debt, including $5 million of unamortized debt issuance costs and discount, in connection with the note purchases. On June 19, 2019, Apache closed offerings of $1.0 billion in aggregate principal amount of senior unsecured notes, comprised of $600 million in aggregate principal amount of 4.250% notes due January 15, 2030 and $400 million in aggregate principal amount of 5.350% notes due July 1, 2049. The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers and for general corporate purposes. On June 21, 2019, the Company closed cash tender offers for certain outstanding notes. Apache accepted for purchase $932 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate of approximately $1.0 billion reflecting principal, the net premium to par, early tender premium, and accrued and unpaid interest. The Company recorded a net loss of $75 million on extinguishment of debt, including $7 million of unamortized debt issuance costs and discount, in connection with the note purchases. On August 17, 2020, the Company closed offerings of $1.25 billion in aggregate principal amount of senior unsecured notes, comprised of $500 million in aggregate principal amount of 4.625% notes due 2025 and $750 million in aggregate principal amount of 4.875% notes due 2027. The senior unsecured notes are redeemable at any time, in whole or in part, at Apache’s option, at the applicable redemption price. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers, repay a portion of outstanding borrowings under the Company’s senior revolving credit facility, and for general corporate purposes. On August 18, 2020, the Company closed cash tender offers for certain outstanding notes. Apache accepted for purchase $644 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate $644 million, reflecting principal, aggregate discount to par of $38 million, early tender premium of $32 million, and accrued and unpaid interest of $6 million. The Company recorded a net gain of $2 million on extinguishment of debt, including an acceleration of unamortized debt discount and issuance costs, in connection with the note purchases. During 2020, the Company purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $588 million for an aggregate purchase price of $428 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $168 million. These repurchases resulted in a $158 million net gain on extinguishment of debt. The net gain includes an acceleration of related discount and debt issuance costs. The repurchases were financed by borrowings under the Company’s revolving credit facility. 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: December 31, 2020 2019 (In millions) 3.625% notes due 2021 (1) $ — $ 293 3.25% notes due 2022 (2) 213 463 2.625% notes due 2023 (2) 123 181 4.625% notes due 2025 (2) 500 — 7.7% notes due 2026 79 79 7.95% notes due 2026 133 133 4.875% due 2027 (2) 750 — 4.375% notes due 2028 (2) 993 1,000 7.75% notes due 2029 (2)(3) 235 247 4.25% notes due 2030 (2) 580 600 6.0% notes due 2037 (2) 443 467 5.1% notes due 2040 (2) 1,333 1,499 5.25% notes due 2042 (2) 399 500 4.75% notes due 2043 (2) 1,133 1,413 4.25% notes due 2044 (2) 559 753 7.375% debentures due 2047 150 150 5.35% notes due 2049 (2) 390 400 7.625% debentures due 2096 39 39 Notes and debentures before unamortized discount and debt issuance costs (4) 8,052 8,217 Commercial paper — — Altus credit facility (5) 624 396 Apache credit facility (5) 150 — Finance lease obligations 38 48 Unamortized discount (35) (42) Debt issuance costs (57) (53) Total debt 8,772 8,566 Current maturities (2) (11) Long-term debt $ 8,770 $ 8,555 (1) On November 3, 2020, Apache redeemed the 3.625% senior notes due February 1, 2021, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. (2) 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. (3) Assumed by Apache in August 2017 as permitted by terms of these notes originally issued by a subsidiary and guaranteed by Apache. (4) The fair values of the Company’s notes and debentures were $8.5 billion and $8.4 billion as of December 31, 2020 and 2019, respectively. Apache 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). (5) 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, 2020 are as follows: (In millions) 2021 $ — 2022 213 2023 123 2024 — 2025 500 Thereafter 7,216 Notes and debentures, excluding discounts and debt issuance costs $ 8,052 Uncommitted Lines of Credit The Company 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, 2020 and 2019, there were no outstanding borrowings under these facilities. As of December 31, 2020, there were £34 million and $17 million in letters of credit outstanding under these facilities. As of December 31, 2019, there were £22 million and $3 million in letters of credit outstanding under these facilities. Unsecured Committed Bank Credit Facilities In March 2018, Apache entered into a revolving credit facility with commitments totaling $4.0 billion. In March 2019, the term of this facility was extended by one year to March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exercise of an extension option. The Company can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of December 31, 2020. The facility is for general corporate purposes and available committed borrowing capacity supports Apache’s commercial paper program. As of December 31, 2020, there were $150 million of borrowings and an aggregate of £633 million and $40 million in letters of credit outstanding under this facility. As of December 31, 2019, there were no borrowings or letters of credit outstanding under this facility. The £633 million in outstanding letters of credit were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced the Company’s credit rating from BBB to BB+ on March 26, 2020. At Apache’s option, the interest rate per annum for borrowings under the 2018 facility is either a base rate, as defined, plus a margin, or the London Inter-bank Offered Rate (LIBOR), plus a margin. The Company also pays quarterly a facility fee at a per annum rate on total commitments. The margins and the facility fee vary based upon the Company’s senior long-term debt rating. At December 31, 2020, the base rate margin was 0.5 percent, the LIBOR margin was 1.50 percent, and the facility fee was 0.25 percent. A commission is payable quarterly to lenders on the face amount of each outstanding letter of credit at a per annum rate equal to the LIBOR margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks. The financial covenants of the 2018 credit facility require the Company 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 excludes the effects of non-cash write-downs, impairments, and related charges occurring after June 30, 2015. The 2018 facility’s negative covenants restrict the ability of the Company and its subsidiaries to create liens securing debt on its 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 United States and Canada; and liens arising as a matter of law, such as tax and mechanics’ liens. Apache also may incur liens on assets if debt secured thereby does not exceed 15 percent of Apache’s consolidated net tangible assets, or approximately $1.7 billion as of December 31, 2020. Negative covenants also restrict Apache’s ability to merge with another entity unless it is the surviving entity, dispose of substantially all of its assets, and guarantee debt of non-consolidated entities in excess of the stated threshold. In November 2018, Altus Midstream LP entered into a revolving credit facility for general corporate purposes that matures in November 2023 (subject to Altus Midstream LP’s two, one-year extension options). The agreement for this facility, as amended, provides aggregate commitments from a syndicate of banks of $800 million. All aggregate commitments include a letter of credit subfacility of up to $100 million and a swingline loan subfacility of up to $100 million. Altus Midstream LP may increase commitments up to an aggregate $1.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. As of December 31, 2020 and December 31, 2019, there were $624 million and $396 million, respectively, of borrowings, and no letters of credit outstanding under this facility. The agreement for Altus Midstream LP’s credit facility, as amended, restricts distributions in respect of capital to Apache and other unit holders in certain circumstances. Unless the Leverage Ratio is less than or equal to 4.00:1.00, the agreement limits such distributions to $30 million per calendar year until either (i) the consolidated net income of Altus Midstream LP and its restricted subsidiaries, as adjusted pursuant to the agreement, for three consecutive calendar months equals or exceeds $350 million on an annualized basis or (ii) Altus Midstream LP has a specified senior long-term debt rating; in addition, before the occurrence of one of those two events, the Leverage Ratio must be less than or equal to 5.00:1.00. In no event can any distribution be made that would, after giving effect to it on a pro forma basis, result in a Leverage Ratio greater than (i) 5.00:1.00 or (ii) for a specified period after a qualifying acquisition, 5.50:1.00. The Leverage Ratio is the ratio of (1) the consolidated indebtedness of Altus Midstream LP and its restricted subsidiaries to (2) EBITDA (as defined in the agreement) of Altus Midstream LP and its restricted subsidiaries for the 12-month period ending immediately before the determination date. The Leverage Ratio as of December 31, 2020 was less than 4.00:1.00. The terms of Altus Midstream LP’s Series A Cumulative Redeemable Preferred Units also contain certain restrictions on distributions in respect of capital, including the common units held by Apache and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation. Refer to Note 13—Redeemable Noncontrolling Interest - Altus for further information. In addition, the amount of any cash distributions to Altus Midstream LP by any entity in which it has an interest accounted for by the equity method is subject to such entity’s compliance with the terms of any debt or other agreements by which it may be bound, which in turn may impact the amount of funds available for distribution by Altus Midstream LP to its partners. The Altus Midstream LP credit facility is unsecured and is not guaranteed by Apache or any of Apache’s other subsidiaries. There are no clauses in either the agreement for Apache’s 2018 credit facility or for Altus Midstream LP’s 2018 credit facility that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. These agreements do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, each agreement allows the lenders to accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches, and if a borrower or any of its subsidiaries defaults on other indebtedness in excess of the stated threshold, is insolvent, or has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold. Lenders may also accelerate payment maturity and terminate lending and issuance commitments under the applicable agreement if Apache or Altus Midstream LP, as applicable, undergoes a specified change in control or any borrower has specified pension plan liabilities in excess of the stated threshold. Each of Apache and Altus Midstream LP was in compliance with the terms of its 2018 credit facility as of December 31, 2020. Commercial Paper Program Apache’s $3.5 billion commercial paper program, which is subject to market availability, facilitates Apache borrowing funds for up to 270 days. As a result of downgrades in the Company’s credit ratings during 2020, the Company does not expect that its commercial paper program will be cost competitive with its other financing alternatives and does not anticipate using it under such circumstances. As of December 31, 2020 and 2019, the Company had no commercial paper outstanding. Financing Costs, Net The following table presents the components of Apache’s financing costs, net: For the Year Ended December 31, 2020 2019 2018 (In millions) Interest expense $ 438 $ 430 $ 441 Amortization of debt issuance costs 8 7 9 Capitalized interest (12) (37) (44) Loss (gain) on extinguishment of debt (160) 75 94 Interest income (7) (13) (22) Financing costs, net $ 267 $ 462 $ 478 As of December 31, 2020, the Company had $57 million of debt issuance costs, which will be charged to interest expense over the life of the related debt issuances. Discount amortization of $7 million, $2 million, and $3 million was recorded as interest expense in 2020, 2019, and 2018, respectively.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Income (loss) before income taxes is composed of the following: For the Year Ended December 31, 2020 2019 2018 (In millions) U.S. $ (4,581) $ (4,397) $ (723) Foreign (259) 1,389 1,681 Total $ (4,840) $ (3,008) $ 958 The total income tax provision consists of the following: For the Year Ended December 31, 2020 2019 2018 (In millions) Current income taxes: Federal $ (2) $ 1 $ (1) State — — — Foreign 178 659 895 176 660 894 Deferred income taxes: Federal — 67 (65) State — — 2 Foreign (112) (53) (159) (112) 14 (222) Total $ 64 $ 674 $ 672 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 income (loss) before income taxes and total tax expense is shown below: For the Year Ended December 31, 2020 2019 2018 (In millions) Income tax expense (benefit) at U.S. statutory rate $ (1,016) $ (631) $ 201 State income tax, less federal effect (1) — 1 2 Taxes related to foreign operations 97 328 436 Tax credits (13) (6) (13) Tax on deemed repatriation of foreign earnings — — 103 Foreign tax credits — — (336) Change in U.S. tax rate — — 161 Net change in tax contingencies 1 1 (2) Goodwill impairment 35 — — Sale of North Sea assets — — (30) Valuation allowances (1) 965 972 118 All other, net (5) 9 32 $ 64 $ 674 $ 672 (1) The change in state valuation allowance is included as a component of state income tax. The net deferred income tax 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 liability consists of the following as of December 31: 2020 2019 (In millions) Deferred tax assets: U.S. and state net operating losses $ 2,306 $ 2,108 Capital losses 633 626 Tax credits and other tax incentives 33 32 Foreign tax credits 2,241 2,241 Accrued expenses and liabilities 93 97 Asset retirement obligation 654 618 Property & equipment 261 — Investment in Altus Midstream LP 76 107 Net interest expense limitation 252 162 Lease liability 79 108 Other 1 88 Total deferred tax assets 6,629 6,187 Valuation allowance (5,991) (4,959) Net deferred tax assets 638 1,228 Deferred tax liabilities: Deferred income — 1 Equity investments 4 — Property and equipment 750 1,432 Right-of-use asset 74 106 Other 13 6 Total deferred tax liabilities 841 1,545 Net deferred income tax liability $ 203 $ 317 Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows: 2020 2019 (In millions) Assets: Deferred charges and other $ 12 $ 29 Liabilities: Income taxes 215 346 Net deferred income tax liability $ 203 $ 317 On December 22, 2017, the SEC staff issued Staff Accounting Bulletin No. 118 (SAB 118) which provides guidance for the application of ASC Topic 740, Income Taxes, for the income tax effects of the Tax Cuts and Jobs Act (the TCJA). SAB 118 provides a measurement period which should not extend beyond 1 year of the enactment date of the TCJA. In 2018, the Company recorded an additional $103 million deferred tax expense attributable to the deemed repatriation of foreign earnings. This deferred tax expense combined with the provisional amount recorded in 2017 were fully offset by available foreign tax credits. The Company completed its analysis of the income tax effects of the TCJA in the fourth quarter of 2018. The Company has recorded an increase in valuation allowance against certain deferred tax assets, primarily driven by asset impairments. The Company has assessed the future potential to realize these deferred tax assets and has concluded that it is more likely than not that these deferred tax assets will not be realized based on current economic conditions and expectations for the future. In 2020, 2019, and 2018, the Company’s valuation allowance increased by $1.0 billion, $1.0 billion, and $131 million, respectively, as detailed in the table below: 2020 2019 2018 (In millions) Balance at beginning of year $ 4,959 $ 3,947 $ 3,816 State (1) 67 41 15 U.S. 960 971 124 Foreign 5 — (8) Balance at end of year $ 5,991 $ 4,959 $ 3,947 (1) Reported as a component of state income taxes. On December 31, 2020, the Company had net operating losses as follows: Amount Expiration (In millions) U.S. $ 8,859 2020 - Indefinite State 6,566 Various The Company has a U.S. net operating loss carryforward of $8.9 billion, which includes $186 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 TCJA. The Company also has a net interest expense carryover of $1.1 billion under Section 163(j) of the Code subject to indefinite carryover, a U.S. capital loss carryforward of $1.8 billion, which has a five year carryover period expiring in 2023 and a Canadian capital loss carryforward of $836 million which has an indefinite carryover. The Company has recorded a full valuation allowance against the U.S. net operating losses, the state net operating losses, the net interest expense carryover, the U.S. capital loss, and the Canadian capital loss carryforward because it is more likely than not that these attributes will not be realized. On December 31, 2020, the Company had foreign tax credits as follows: Amount Expiration (In millions) Foreign tax credits $ 2,241 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 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: 2020 2019 2018 (In millions) Balance at beginning of year $ 82 $ 24 $ 26 Additions based on tax positions related to prior year — 49 — Additions based on tax positions related to the current year 11 9 — Reductions for tax positions of prior years — — (2) Balance at end of year $ 93 $ 82 $ 24 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, 2020, 2019, and 2018, the Company recorded tax expense of $1 million for interest and penalties. At December 31, 2020, 2019, and 2018, the Company had an accrued liability for interest and penalties of $3 million, $2 million, and $1 million, respectively. In 2020, 2019, and 2018, the Company recorded an $11 million net increase, $58 million net increase, and a $2 million net reduction, respectively, in its reserve for uncertain tax positions. The Company is currently under IRS audit for the 2014 through 2017 tax years. Apache 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. Apache’s earliest open tax years in its key jurisdictions are as follows: Jurisdiction U.S. 2014 Egypt 2005 U.K. 2019 In 2020, the Company early adopted ASU 2019-12, “Simplifying the Accounting for Income Taxes.” The Company’s early adoption of ASU 2019-12 using the prospective transition approach did not result in a material impact on the consolidated financial statements.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	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. As of December 31, 2020, the Company has an accrued liability of approximately $70 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. For material matters that 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 2020, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including the Company. These cases were all removed to federal courts in Louisiana. Some of the cases have been remanded to state court with the remand orders being appealed. 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. While adverse judgments against the Company might be possible, the Company intends to vigorously oppose these claims. Apollo Exploration Lawsuit In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation , Cause No. CV50538 in the 385 th 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 areas of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The 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 plaintiffs’ appeal is pending. Australian Operations Divestiture Dispute Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the Company and its subsidiaries divested their remaining 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 believes that Quadrant’s claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity. 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 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 purported class seeks approximately $60 million USD and punitive damages. The Company believes that Plaintiffs’ claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity. California and Delaware Litigation On July 17, 2017, in three separate actions, San Mateo County, California, Marin County, California, 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 and in a separate action on January 22, 2018, the City of Richmond, filed similar lawsuits against many of the same defendants. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants. After removal of all such lawsuits to federal court, the district court remanded them back to state court. The remand decision, and further activity in the cases, has been stayed pending further appellate review. 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 believes that it is not subject to jurisdiction of the California courts and that claims made against it in the Delaware litigation are baseless. The Company intends to challenge jurisdiction in California and to vigorously defend the Delaware lawsuit. Castex Lawsuit In a case styled Apache Corporation v. Castex Offshore, Inc., et. al. , Cause No. 2015-48580, in the 113th Judicial District Court of Harris County, Texas, Castex filed claims for alleged damages of approximately $200 million, relating to overspend on the Belle Isle Gas Facility upgrade, and the drilling of five sidetracks on the Potomac #3 well. After a jury trial, a verdict of approximately $60 million, plus fees, costs and interest was entered against the Company. The Company’s appeal is pending. Oklahoma Class Actions The Company is a party to two purported class actions in Oklahoma styled Bigie Lee Rhea v. Apache Corporation , Case No. 6:14-cv-00433-JH, and Albert Steven Allen v. Apache Corporation , Case No. CJ-2019-00219. The Rhea case has been certified and includes a class of royalty owners seeking damages in excess of $250 million for alleged breach of the implied covenant to market relating to post-production deductions and alleged NGL uplift value. The Allen case has not been certified and seeks to represent a group of owners who have allegedly received late royalty and other payments under Oklahoma statutes. The amount of this claim is not yet reasonably determinable. While adverse judgments against the Company are possible, the Company intends to vigorously defend these lawsuits and claims. Stockholder 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 (1) alleges that the Company intentionally used unrealistic assumptions regarding the amount and composition of available oil and gas in Alpine High; (2) alleges that 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) alleges that these statements and omissions artificially inflated the value of the Company’s operations in the Permian Basin; and (4) alleges that, as a result, the Company’s public statements were materially false and misleading. Other lawsuits have followed with similar allegations. The Company believes that all plaintiffs’ claims lack merit and intends 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, 2020, the Company had an undiscounted reserve for environmental remediation of approximately $2 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. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and responding to the information request. The EPA has not commenced enforcement proceedings, and at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs. Additionally, 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 relating to several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and responding to the information request. The EPA has not commenced enforcement proceedings, and at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs. The Company is not aware of any environmental claims existing as of December 31, 2020 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 Asset Retirement Obligations In 2013, the Company sold its Gulf of Mexico Shelf operations and properties (Transferred Assets) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, the Company received cash consideration of $3.75 billion and Fieldwood assumed $1.5 billion of discounted asset abandonment liabilities as of the disposition date. In respect of such abandonment liabilities, Fieldwood posted letters of credit in favor of the Company (Letters of Credit) and established a trust account (Trust A), which is funded by a 10 percent net profits interest depending on future oil prices and of which the Company is the beneficiary. 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 the Company agreed, inter alia, to accept bonds in exchange for certain of the Letters of Credit. Currently, the Company holds two bonds (Bonds) and the remaining Letters of Credit to secure Fieldwood’s asset retirement obligations (AROs) on the Transferred Assets as and when such abandonment and decommissioning obligations are required to be performed over the remaining life of the Transferred Assets. On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. Fieldwood has submitted a plan of reorganization, and the Company has been engaged in discussions with Fieldwood and other interested parties regarding such plan. If approved by the bankruptcy court, the submitted plan would separate the Transferred Assets into a standalone company, and proceeds of production of the Transferred Assets will be used for the AROs. If the proceeds of production are insufficient for such AROs, then Apache expects that it may be required by the relevant governmental authorities to perform such AROs, in which case it will apply the Bonds, remaining Letters of Credit, and Trust A to pay for the AROs. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan of up to $400 million for the new company to perform decommissioning, with such standby loan secured by a first and prior lien on the Transferred Assets. If the foregoing is insufficient, the Company may be forced to use available cash to cover any additional costs it incurs for performing such AROs. Leases and Contractual Obligations On January 1, 2019, Apache adopted ASU 2016-02, “Leases (Topic 842),” which requires lessees to recognize separate right-of-use (ROU) assets and lease liabilities for most leases classified as operating leases under previous GAAP. As allowed under the standard, the Company applied practical expedients permitting an entity the option to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases, as well as permitting an entity the option to carry forward its historical assessments of whether existing agreements contain a lease, classification of existing lease agreements, and treatment of initial direct lease costs. 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, Apache 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, Apache 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” within “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 $149 million and $222 million in 2020 and 2019, respectively. Apache 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, which is primarily related to drilling activities in Block 58 offshore Suriname, was $80 million and $18 million in 2020 and 2019, respectively. In addition, the Company periodically enters into finance leases that are similar to those leases classified as capital leases under previous GAAP. Finance lease assets are included in “Other” within “Property 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 and $7 million in 2020 and 2019, respectively. Interest on the Company’s finance lease assets was $2 million and $3 million in 2020 and 2019, respectively. The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2020: Operating Leases Finance Leases Weighted average remaining lease term 3.7 years 12.7 years Weighted average discount rate 4.2 % 4.4 % At December 31, 2020, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows: Net Minimum Commitments (1) Operating Leases (2) Finance Leases (3) Purchase Obligations (4) (In millions) 2021 $ 120 $ 3 $ 236 2022 70 3 203 2023 33 3 203 2024 27 4 160 2025 7 4 159 Thereafter 25 29 600 Total future minimum payments 282 46 $ 1,561 Less: imputed interest (21) (8) N/A Total lease liabilities 261 38 N/A Current portion 116 2 N/A Non-current portion $ 145 $ 36 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 agreement 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 $120 million, $111 million, and $132 million in 2020, 2019, and 2018, respectively. 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 was $41 million and $78 million in 2020 and 2019, respectively. As a result of electing the transitional practical expedient to apply the provisions of the standard at its adoption date instead of the earliest comparative period presented, below are the required ASU Leases (Topic 840) disclosures for prior periods: Operating Leases (1) Finance Leases (2) (In millions) Year ended December 31, 2018 2019 $ 61 $ 1 2020-2021 64 3 2022-2023 53 4 2024 & Beyond 42 32 Total $ 220 $ 40 (1) Includes leases for buildings, facilities, and related equipment with varying expiration dates through 2042. Total rent expense, net of amounts capitalized and sublease income was $76 million in 2018. (2) This represents the Company’s capital lease obligation related to its Midland, Texas office building. The imputed interest rate necessary to reduce the net minimum lease payments to present value of the lease term is 4.4 percent, or $16 million as of December 31, 2018.

RETIREMENT AND DEFERRED COMPENS

RETIREMENT AND DEFERRED COMPENSATION PLANS	12 Months Ended
	Dec. 31, 2020
Retirement Benefits [Abstract]
RETIREMENT AND DEFERRED COMPENSATION PLANS	RETIREMENT AND DEFERRED COMPENSATION PLANS Apache Corporation 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, as defined, 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 eligible 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 Apache Corporation, immediate and full vesting occurs. Additionally, Apache North Sea Limited maintains a separate retirement plan, as required under the laws of the U.K. The aggregate annual cost to Apache 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 $43 million, $52 million, and $52 million for 2020, 2019, and 2018, respectively. Apache 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. The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2020, 2019, and 2018, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. Apache uses a measurement date of December 31 for its pension and postretirement benefit plans. 2020 2019 2018 Pension Postretirement Pension Postretirement Pension Postretirement (In millions) Change in Projected Benefit Obligation Projected benefit obligation at beginning of year $ 199 $ 20 $ 187 $ 27 $ 216 $ 27 Service cost 3 1 3 2 4 2 Interest cost 4 — 5 1 5 1 Foreign currency exchange rates 8 — 7 — (11) — Actuarial losses (gains) 30 1 15 (9) (11) (2) Plan settlements — — (14) — (11) — Benefits paid (11) (4) (4) (2) (5) (3) Retiree contributions — 2 — 1 — 2 Projected benefit obligation at end of year 233 20 199 20 187 27 Change in Plan Assets Fair value of plan assets at beginning of year 228 — 208 — 238 — Actual return on plan assets 31 — 25 — (6) — Foreign currency exchange rates 9 — 8 — (13) — Employer contributions 5 2 5 1 5 2 Plan settlements — — (14) — (11) — Benefits paid (11) (4) (4) (2) (5) (4) Retiree contributions — 2 — 1 — 2 Fair value of plan assets at end of year 262 — 228 — 208 — Funded status at end of year $ 29 $ (20) $ 29 $ (20) $ 21 $ (27) Amounts recognized in Consolidated Balance Sheet Current liability $ — $ (2) $ — $ (2) $ — $ (2) Non-current asset (liability) 29 (18) 29 (18) 21 (25) $ 29 $ (20) $ 29 $ (20) $ 21 $ (27) Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss) Accumulated gain (loss) $ (11) $ 16 $ (7) $ 19 $ (13) $ 10 Weighted Average Assumptions used as of December 31 Discount rate 1.40 % 2.06 % 2.10 % 3.00 % 2.90 % 4.13 % Salary increases 4.50 % N/A 4.30 % N/A 4.70 % N/A Expected return on assets 2.20 % N/A 2.20 % N/A 2.80 % N/A Healthcare cost trend Initial N/A 6.00 % N/A 6.25 % N/A 6.50 % Ultimate in 2025 N/A 5.00 % N/A 5.00 % N/A 5.00 % As of December 31, 2020, 2019, and 2018, the accumulated benefit obligation for the U.K. Pension Plan was $207 million, $181 million, and $167 million, respectively. Apache’s defined benefit pension plan assets are held by a non-related trustee who has been instructed to invest the assets in a blend of equity securities and low-risk debt securities. The Company intends that this blend of investments will provide a reasonable rate of return such that the benefits promised to members are provided. 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 previous allocations for plan asset holdings and the target allocation for the Company’s plan assets are summarized below: Target Percentage of 2020 2020 2019 Asset Category Equity securities: Overseas quoted equities 19 % 19 % 23 % Total equity securities 19 % 19 % 23 % Debt securities: U.K. government bonds 65 % 64 % 62 % U.K. corporate bonds 16 % 16 % 15 % Total debt securities 81 % 80 % 77 % Cash — 1 % — Total 100 % 100 % 100 % The plan’s assets do not include any direct ownership of equity or debt securities of Apache. The fair value of plan assets at December 31, 2020 and 2019 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, 2020 and 2019: December 31, 2020 2019 (In millions) Equity securities: Overseas quoted equities $ 49 $ 52 Total equity securities 49 52 Debt securities: U.K. government bonds 168 140 U.K. corporate bonds 43 35 Total debt securities 211 175 Cash 2 1 Fair value of plan assets $ 262 $ 228 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. 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, 2020, 2019, and 2018: 2020 2019 2018 Pension Postretirement Pension Postretirement Pension Postretirement (In millions) Components of Net Periodic Benefit Cost Service cost $ 3 $ 1 $ 3 $ 2 $ 4 $ 2 Interest cost 4 — 5 1 5 1 Expected return on assets (5) — (5) — (7) — Amortization of gain — (1) — (1) — — Settlement loss — — — — 1 — Net periodic benefit cost $ 2 $ — $ 3 $ 2 $ 3 $ 3 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31 Discount rate 2.10 % 3.00 % 2.90 % 4.13 % 2.60 % 3.44 % Salary increases 4.30 % N/A 4.70 % N/A 4.70 % N/A Expected return on assets 2.20 % N/A 2.80 % N/A 2.90 % N/A Healthcare cost trend Initial N/A 6.25 % N/A 6.50 % N/A 6.75 % Ultimate in 2025 N/A 5.00 % N/A 5.00 % N/A 5.00 % Apache expects to contribute approximately $5 million to its pension plan and $2 million to its postretirement benefit plan in 2021. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: Pension Postretirement (In millions) 2021 $ 5 $ 2 2022 6 2 2023 7 2 2024 6 2 2025 6 2 Years 2026-2030 36 6

REDEMABLE NONCONTROLLING INTERE

REDEMABLE NONCONTROLLING INTEREST - ALTUS	12 Months Ended
	Dec. 31, 2020
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 of 1933, as amended (the Closing). Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. Pursuant to the partnership agreement of Altus Midstream LP: • The Preferred Units bear quarterly distributions at a rate of 7 percent per annum, increasing to 10 percent per annum after the fifth anniversary of Closing and upon the occurrence of specified events. Altus Midstream LP may pay distributions in-kind for the first six quarters after the Preferred Units are issued. • The Preferred Units are redeemable at Altus Midstream LP’s option at any time in cash at a redemption price (the Redemption Price) equal to the greater of an 11.5 percent internal rate of return (increasing after the fifth anniversary of Closing to 13.75 percent) and a 1.3x multiple of invested capital. The Preferred Units will be redeemable at the holder’s option upon a change of control or liquidation of Altus Midstream LP and certain other events, including certain asset dispositions. • The Preferred Units will be exchangeable for shares of ALTM’s Class A common stock at the holder’s election after the seventh anniversary of Closing or upon the occurrence of specified events. Each Preferred Unit will be exchangeable for a number of shares of ALTM’s Class A common stock equal to the Redemption Price divided by the volume-weighted average trading price of ALTM’s Class A common stock on the Nasdaq Capital Market for the 20 trading days immediately preceding the second trading day prior to the applicable exchange date, less a 6 percent discount. • Each outstanding Preferred Unit has a liquidation preference equal to the Redemption Price payable before any amounts are paid in respect of Altus Midstream LP’s common units and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation. • Preferred Units holders have rights to approve certain partnership business, financial, and governance-related matters. • Altus Midstream LP is restricted from declaring or making cash distributions on its common units until all required distributions on the Preferred Units have been paid. In addition, before the fifth anniversary of Closing, aggregate cash distributions on, and redemptions of, Altus Midstream LP’s common units are limited to $650 million of cash from ordinary course operations if permitted under its credit facility. Cash distributions on, and redemptions of, Altus Midstream LP’s common units also are subject to satisfaction of leverage ratio requirements specified in its partnership agreement. Classification The Preferred Units are accounted for on the Company’s consolidated balance sheets as a redeemable noncontrolling interest classified as temporary equity based on the terms of the Preferred Units, including the redemption rights with respect thereto. Initial Measurement Altus recorded the net transaction price of $611 million, calculated as the negotiated transaction price of $625 million, less issue discounts of $4 million and transaction costs totaling $10 million. Certain redemption features embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. Altus bifurcated and recognized at fair value an embedded derivative related to the Preferred Units at inception of $94 million for a redemption option of the Preferred Unit holders. The derivative is reflected in “Other” within “Deferred Credits and Other Noncurrent Liabilities” on the Company’s consolidated balance sheet at its current fair value of $139 million as of December 31, 2020. The fair value of the embedded derivative, a Level 3 fair value measurement, was based on numerous factors including expected future interest rates using the Black-Karasinski model, Altus’ imputed interest rate, the timing of periodic cash distributions, and dividend yields of the Preferred Units. See Note 4—Derivative Instruments and Hedging Activities for more detail. The net transaction price was allocated to the preferred redeemable noncontrolling interest and the embedded features according to the associated initial fair value measurements as follows: June 12, 2019 (In millions) Redeemable noncontrolling interest - Altus Preferred Unit limited partners $ 517 Preferred Units embedded derivative 94 $ 611 Subsequent Measurement Altus applies 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 may be recorded, if applicable. The amount of such adjustment is determined based upon the accreted value method to reflect the passage of time until the Preferred Units are exchangeable at the option of the holder. Pursuant to this method, the net transaction price is accreted using the effective interest method to the Redemption Price calculated at the seventh anniversary of the Closing. The total adjustment is limited to an amount such that the carrying amount of the Preferred Unit redeemable noncontrolling interest at each period end is equal to the greater of (a) the sum of (i) the carrying amount of the Preferred Units, plus (ii) the fair value of the embedded derivative liability and (b) the accreted value of the net transaction price. Activity related to the Preferred Units for the years ended December 31, 2020 and 2019 is as follows: Units Outstanding Financial Position (1) (In millions, except unit data) Redeemable noncontrolling interest — Preferred Units: at December 31, 2018 — $ — Issuance of Preferred Units, net 625,000 517 Distribution of in-kind additional Preferred Units 13,163 — Allocation of Altus Midstream net income N/A 38 Redeemable noncontrolling interest - Altus Preferred Unit limited partners: at December 31, 2019 638,163 555 Distribution of in-kind additional Preferred Units 22,531 — Cash distributions to Altus Preferred Unit limited partners — (23) Allocation of Altus Midstream LP net income N/A 76 Redeemable noncontrolling interest - Altus Preferred Unit limited partners: at December 31, 2020 660,694 608 Preferred Units embedded derivative 139 $ 747 (1) The Preferred Units are redeemable at Altus Midstream’s option at a redemption price (the Redemption Price), which as of December 31, 2020 was the greater of (i) an 11.5 percent internal rate of return and (ii) a 1.3 times multiple of invested capital. As of December 31, 2020, the Redemption Price would have been based on 1.3 times multiple of invested capital, which was $813 million and greater than using an 11.5 percent internal rate of return, which was $717 million. N/A - not applicable. Common Stock Outstanding The following table provides changes to the Company’s common shares outstanding for the years ended December 31, 2020, 2019, and 2018: For the Year Ended December 31, 2020 2019 2018 Balance, beginning of year 376,062,670 374,696,222 380,954,864 Shares issued for stock-based compensation plans: Treasury shares issued 17,448 31,701 2,454 Common shares issued 1,402,512 1,334,747 1,566,237 Treasury shares acquired — — (7,827,333) Balance, end of year 377,482,630 376,062,670 374,696,222 Net Income (Loss) per Common Share The following table provides a reconciliation of the components of basic and diluted net income (loss) per common share for the years ended December 31, 2020, 2019, and 2018: 2020 2019 2018 Loss Shares Per Share Loss Shares Per Share Income Shares Per Share (In millions, except per share amounts) Basic: Income (loss) attributable to common stock $ (4,860) 378 $ (12.86) $ (3,553) 377 $ (9.43) $ 40 382 $ 0.11 Effect of Dilutive Securities: Stock options and other $ — — $ — $ — — $ — $ — 2 $ — Diluted: Income (loss) attributable to common stock $ (4,860) 378 $ (12.86) $ (3,553) 377 $ (9.43) $ 40 384 $ 0.11 The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 4.5 million, 5.0 million, and 5.6 million for the years ended December 31, 2020, 2019, and 2018, respectively. 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 years ended December 31, 2020 and 2019. Stock Repurchase Program In 2013 and 2014, Apache’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. Shares may be purchased either in the open market or through privately held negotiated transactions. The Company initiated the buyback program on June 10, 2013, and, through December 31, 2020, had repurchased a total of 40 million shares at an average price of $79.18 per share. During the fourth quarter of 2018, the Company’s Board of Directors authorized the purchase of up to 40 million additional shares of the Company’s common stock. The Company is not obligated to acquire any specific number of shares and did not purchase any shares during the year ended December 31, 2020. Common Stock Dividend In the first quarter of 2020, the Board of Directors approved a reduction in the Company’s quarterly dividends from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020. For the year ended December 31, 2020, the Company declared common stock dividends of $0.10 per share. For each of the years ended December 31, 2019 and 2018, the Company declared common stock dividends of $1.00 per share. Stock Compensation Plans The Company maintains several stock-based compensation plans, which include stock options, restricted stock, and conditional restricted stock unit plans. 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, 2020, 14.1 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 Year Ended December 31, 2020 2019 2018 (In millions) Stock-settled and cash-settled compensation expensed $ 40 $ 110 $ 157 Stock-settled and cash-settled compensation capitalized 7 28 37 Total stock-settled and cash-settled compensation costs $ 47 $ 138 $ 194 Stock Options As of December 31, 2020, the Company had outstanding options to purchase shares of its common stock under the 2016 Plan, the 2011 Omnibus Equity Compensation Plan (the 2011 Plan), and the 2007 Omnibus Equity Compensation Plan (the 2007 Plan), (collectively, 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 Apache’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, 2020, 2019, and 2018: 2020 2019 2018 Shares Weighted Average Shares Weighted Average Shares Weighted Average (In thousands, except exercise price amounts) Outstanding, beginning of year 4,298 $ 75.24 4,872 $ 75.95 4,593 $ 83.36 Granted — — — — 812 45.93 Exercised — — — — (29) 41.79 Forfeited (37) 44.98 (80) 34.58 (121) 74.58 Expired (724) 92.14 (494) 88.82 (383) 104.21 Outstanding, end of year (1) 3,537 72.10 4,298 75.24 4,872 75.95 Expected to vest (2) 150 45.77 495 49.11 1,274 48.74 Exercisable, end of year (3) 3,387 73.26 3,803 78.64 3,598 85.59 (1) As of December 31, 2020, options outstanding had a weighted average remaining contractual life of 3.6 years and no intrinsic value. (2) As of December 31, 2020, options expected to vest had a weighted average remaining contractual life of 7.0 years and no intrinsic value. (3) As of December 31, 2020, options exercisable had a weighted average remaining contractual life of 3.4 years and no intrinsic value. The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model, a Level 2 fair value measurement. The following table summarizes specific assumptions used in the Company’s valuation: 2020 2019 2018 Expected volatility N/A N/A 33.74% Expected dividend yields N/A N/A 2.16% Expected term (in years) N/A N/A 6 Risk-free rate N/A N/A 2.42% Weighted-average grant-date fair value N/A N/A $ 13.15 N/A - not applicable. Assumptions related to the expected volatilities are based on the Company’s historical volatility of its common stock and other factors. The expected dividend yield is based on historical yields on the date of grant. The expected term of stock options granted represents the period of time that the stock options are expected to be outstanding and is derived from historical exercise behavior, current trends, and values derived from lattice-based models. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant. There were no options issued and no options exercised during the years ended December 31, 2020 and 2019. The intrinsic values of options exercised during the year ended December 31, 2018 was approximately $0.1 million. As of December 31, 2020, total compensation cost related to non-vested options not yet recognized was nil because they fully vest on January 5, 2021. 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 stock or 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. The cash-settled awards compensation expense 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, 2020, 2019, and 2018, compensation costs charged to expense for the restricted stock units and restricted stock phantom units was $39 million, $104 million, and $101 million, respectively. As of December 31, 2020, 2019, and 2018, capitalized compensation costs for the restricted stock units and restricted stock phantom units were $6 million, $24 million, and $29 million, respectively. The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2020, 2019, and 2018: 2020 2019 2018 Units Weighted Units Weighted Units Weighted (In thousands, except per share amounts) Non-vested, beginning of year 2,448 $ 46.65 3,153 $ 55.54 4,920 $ 56.67 Granted 1,352 24.60 1,479 36.81 608 45.59 Vested (3) (1,933) 48.65 (1,899) 53.99 (2,023) 55.10 Forfeited (315) 30.09 (285) 45.06 (352) 56.69 Non-vested, end of year (1)(2) 1,552 28.43 2,448 46.65 3,153 55.54 (1) As of December 31, 2020, there was $14 million of total unrecognized compensation cost related to 1,551,807 unvested stock-settled restricted stock units. (2) As of December 31, 2020, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.7 years. (3) The grant date fair values of the stock-settled awards vested during 2020, 2019, and 2018 were approximately $94 million, $103 million, and $111 million, respectively. The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2020, 2019, and 2018: For the Year Ended December 31, 2020 2019 2018 (In thousands) Non-vested, beginning of year 5,384 1,818 59 Adjustment for ALTM reverse stock split (1) (1,246) — — Granted (2) 3,462 4,831 1,973 Vested (1,618) (616) (38) Forfeited (1,559) (649) (176) Non-vested, end of year (3) 4,423 5,384 1,818 (1) On June 30, 2020, Altus executed a 1-for-20 reverse stock split of its outstanding common stock. Outstanding cash-settled awards are based on the per-share market price of ALTM stock. (2) Restricted stock phantom units granted during 2020 and 2019 included 3,378,486 and 3,401,477 awards, respectively, based on the per-share market price of Apache common stock and 83,239 and 1,429,135 awards, respectively, based on the per-share market price of ALTM common stock. The restricted stock phantom units granted during 2020 based on ALTM’s per-share market price reflect the 1-for-20 reverse stock split described above. (3) The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2020 was approximately $28 million. In January 2021, the Company awarded 1,354,349 restricted stock units and 4,360,656 restricted stock phantom units based on Apache’s weighted-average per-share market price of $16.18 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 $22 million and $71 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 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. Also during January 2021, the Company awarded 56,836 restricted stock phantom units based on ALTM’s weighted-average per-share market price of $48.84. The restricted stock phantom units represent a hypothetical interest in ALTM’s common stock and, once vested, are settled in cash. Total compensation cost for these restricted stock phantom units, absent any forfeitures, is estimated to be $3 million and was calculated based on the fair market value of ALTM’s common stock as of the grant date. 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 ALTM’s common stock. Performance Program To provide long-term incentives for the Company’s employees to deliver competitive shareholder returns, the Company makes annual grants of conditional restricted stock units to eligible employees. Apache has a performance program for certain eligible employees with payout for 50 percent of the shares based upon measurement of total shareholder return (TSR) of Apache common stock as compared to a designated peer group during a three-year performance period. Payout for the remaining 50 percent 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, 2020, are as described below: • In January 2017, the Company’s Board of Directors approved the 2017 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial stock-settled conditional restricted stock unit awards totaling 620,885 units. A total of 111,126 restricted stock units were outstanding as of December 31, 2020. The results for the performance period yielded a payout of 54 percent of target. • In January 2018, the Company’s Board of Directors approved the 2018 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 931,049 units. A total of 704,483 phantom units were outstanding as of December 31, 2020. The results for the performance period yielded a payout of 23 percent of target. • In January 2019, the Company’s Board of Directors approved the 2019 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,679,832 units. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,301,893 phantom units were outstanding as of December 31, 2020, from which a minimum of zero to a maximum of 2,603,786 phantom units could be awarded. • 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. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,410,404 phantom units were outstanding as of December 31, 2020, from which a minimum of zero to a maximum of 2,820,808 phantom units could be awarded. The fair value cost of the stock-settled awards was estimated on the date of grant and is recorded as compensation expense ratably over the applicable vesting term. The fair value of the cash-settled awards is remeasured at the end of each reporting period over the applicable vesting term. Compensation cost charged to expense under the performance programs was a credit of $8 million during 2020 and expenses of $24 million and $38 million during 2019 and 2018, respectively. Capitalized compensation costs under the performance programs was a credit of $1 million during 2020 and expenses of $3 million and $7 million during 2019 and 2018, respectively. The following table summarizes stock-settled conditional restricted stock unit activity for the year ended December 31, 2020: Units Weighted Average Grant- Date Fair Value (1) (In thousands) Non-vested, beginning of year 781 $ 52.69 Granted 18 62.31 Vested (445) 41.10 Forfeited (16) 56.66 Expired (227) 70.70 Non-vested, end of year (2)(3) 111 63.15 (1) The fair value of each conditional restricted stock unit award is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a three-year continuous risk-free interest rate; (ii) a constant volatility assumption based on the historical realized stock price volatility of the Company and the designated peer group; and (iii) the historical stock prices and expected dividends of the common stock of the Company and its designated peer group. (2) As of December 31, 2020, there was no unrecognized compensation cost related to 111,126 unvested stock-settled conditional restricted stock units. (3) As of December 31, 2020, the weighted-average remaining life of the unvested stock-settled conditional restricted stock units is approximately 0.0 years. The following table summarizes cash-settled conditional restricted stock unit activity for the year ended December 31, 2020: Units (In thousands) Non-vested, beginning of year 2,320 Granted 1,687 Vested (2) Forfeited (542) Expired (46) Non-vested, end of year (1) 3,417 (1) As of December 31, 2020, the outstanding liability for the unvested cash-settled conditional restricted stock units that had not been recognized was approximately $14 million.

CAPITAL STOCK

CAPITAL STOCK	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
CAPITAL STOCK	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 of 1933, as amended (the Closing). Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. Pursuant to the partnership agreement of Altus Midstream LP: • The Preferred Units bear quarterly distributions at a rate of 7 percent per annum, increasing to 10 percent per annum after the fifth anniversary of Closing and upon the occurrence of specified events. Altus Midstream LP may pay distributions in-kind for the first six quarters after the Preferred Units are issued. • The Preferred Units are redeemable at Altus Midstream LP’s option at any time in cash at a redemption price (the Redemption Price) equal to the greater of an 11.5 percent internal rate of return (increasing after the fifth anniversary of Closing to 13.75 percent) and a 1.3x multiple of invested capital. The Preferred Units will be redeemable at the holder’s option upon a change of control or liquidation of Altus Midstream LP and certain other events, including certain asset dispositions. • The Preferred Units will be exchangeable for shares of ALTM’s Class A common stock at the holder’s election after the seventh anniversary of Closing or upon the occurrence of specified events. Each Preferred Unit will be exchangeable for a number of shares of ALTM’s Class A common stock equal to the Redemption Price divided by the volume-weighted average trading price of ALTM’s Class A common stock on the Nasdaq Capital Market for the 20 trading days immediately preceding the second trading day prior to the applicable exchange date, less a 6 percent discount. • Each outstanding Preferred Unit has a liquidation preference equal to the Redemption Price payable before any amounts are paid in respect of Altus Midstream LP’s common units and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation. • Preferred Units holders have rights to approve certain partnership business, financial, and governance-related matters. • Altus Midstream LP is restricted from declaring or making cash distributions on its common units until all required distributions on the Preferred Units have been paid. In addition, before the fifth anniversary of Closing, aggregate cash distributions on, and redemptions of, Altus Midstream LP’s common units are limited to $650 million of cash from ordinary course operations if permitted under its credit facility. Cash distributions on, and redemptions of, Altus Midstream LP’s common units also are subject to satisfaction of leverage ratio requirements specified in its partnership agreement. Classification The Preferred Units are accounted for on the Company’s consolidated balance sheets as a redeemable noncontrolling interest classified as temporary equity based on the terms of the Preferred Units, including the redemption rights with respect thereto. Initial Measurement Altus recorded the net transaction price of $611 million, calculated as the negotiated transaction price of $625 million, less issue discounts of $4 million and transaction costs totaling $10 million. Certain redemption features embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. Altus bifurcated and recognized at fair value an embedded derivative related to the Preferred Units at inception of $94 million for a redemption option of the Preferred Unit holders. The derivative is reflected in “Other” within “Deferred Credits and Other Noncurrent Liabilities” on the Company’s consolidated balance sheet at its current fair value of $139 million as of December 31, 2020. The fair value of the embedded derivative, a Level 3 fair value measurement, was based on numerous factors including expected future interest rates using the Black-Karasinski model, Altus’ imputed interest rate, the timing of periodic cash distributions, and dividend yields of the Preferred Units. See Note 4—Derivative Instruments and Hedging Activities for more detail. The net transaction price was allocated to the preferred redeemable noncontrolling interest and the embedded features according to the associated initial fair value measurements as follows: June 12, 2019 (In millions) Redeemable noncontrolling interest - Altus Preferred Unit limited partners $ 517 Preferred Units embedded derivative 94 $ 611 Subsequent Measurement Altus applies 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 may be recorded, if applicable. The amount of such adjustment is determined based upon the accreted value method to reflect the passage of time until the Preferred Units are exchangeable at the option of the holder. Pursuant to this method, the net transaction price is accreted using the effective interest method to the Redemption Price calculated at the seventh anniversary of the Closing. The total adjustment is limited to an amount such that the carrying amount of the Preferred Unit redeemable noncontrolling interest at each period end is equal to the greater of (a) the sum of (i) the carrying amount of the Preferred Units, plus (ii) the fair value of the embedded derivative liability and (b) the accreted value of the net transaction price. Activity related to the Preferred Units for the years ended December 31, 2020 and 2019 is as follows: Units Outstanding Financial Position (1) (In millions, except unit data) Redeemable noncontrolling interest — Preferred Units: at December 31, 2018 — $ — Issuance of Preferred Units, net 625,000 517 Distribution of in-kind additional Preferred Units 13,163 — Allocation of Altus Midstream net income N/A 38 Redeemable noncontrolling interest - Altus Preferred Unit limited partners: at December 31, 2019 638,163 555 Distribution of in-kind additional Preferred Units 22,531 — Cash distributions to Altus Preferred Unit limited partners — (23) Allocation of Altus Midstream LP net income N/A 76 Redeemable noncontrolling interest - Altus Preferred Unit limited partners: at December 31, 2020 660,694 608 Preferred Units embedded derivative 139 $ 747 (1) The Preferred Units are redeemable at Altus Midstream’s option at a redemption price (the Redemption Price), which as of December 31, 2020 was the greater of (i) an 11.5 percent internal rate of return and (ii) a 1.3 times multiple of invested capital. As of December 31, 2020, the Redemption Price would have been based on 1.3 times multiple of invested capital, which was $813 million and greater than using an 11.5 percent internal rate of return, which was $717 million. N/A - not applicable. Common Stock Outstanding The following table provides changes to the Company’s common shares outstanding for the years ended December 31, 2020, 2019, and 2018: For the Year Ended December 31, 2020 2019 2018 Balance, beginning of year 376,062,670 374,696,222 380,954,864 Shares issued for stock-based compensation plans: Treasury shares issued 17,448 31,701 2,454 Common shares issued 1,402,512 1,334,747 1,566,237 Treasury shares acquired — — (7,827,333) Balance, end of year 377,482,630 376,062,670 374,696,222 Net Income (Loss) per Common Share The following table provides a reconciliation of the components of basic and diluted net income (loss) per common share for the years ended December 31, 2020, 2019, and 2018: 2020 2019 2018 Loss Shares Per Share Loss Shares Per Share Income Shares Per Share (In millions, except per share amounts) Basic: Income (loss) attributable to common stock $ (4,860) 378 $ (12.86) $ (3,553) 377 $ (9.43) $ 40 382 $ 0.11 Effect of Dilutive Securities: Stock options and other $ — — $ — $ — — $ — $ — 2 $ — Diluted: Income (loss) attributable to common stock $ (4,860) 378 $ (12.86) $ (3,553) 377 $ (9.43) $ 40 384 $ 0.11 The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 4.5 million, 5.0 million, and 5.6 million for the years ended December 31, 2020, 2019, and 2018, respectively. 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 years ended December 31, 2020 and 2019. Stock Repurchase Program In 2013 and 2014, Apache’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. Shares may be purchased either in the open market or through privately held negotiated transactions. The Company initiated the buyback program on June 10, 2013, and, through December 31, 2020, had repurchased a total of 40 million shares at an average price of $79.18 per share. During the fourth quarter of 2018, the Company’s Board of Directors authorized the purchase of up to 40 million additional shares of the Company’s common stock. The Company is not obligated to acquire any specific number of shares and did not purchase any shares during the year ended December 31, 2020. Common Stock Dividend In the first quarter of 2020, the Board of Directors approved a reduction in the Company’s quarterly dividends from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020. For the year ended December 31, 2020, the Company declared common stock dividends of $0.10 per share. For each of the years ended December 31, 2019 and 2018, the Company declared common stock dividends of $1.00 per share. Stock Compensation Plans The Company maintains several stock-based compensation plans, which include stock options, restricted stock, and conditional restricted stock unit plans. 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, 2020, 14.1 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 Year Ended December 31, 2020 2019 2018 (In millions) Stock-settled and cash-settled compensation expensed $ 40 $ 110 $ 157 Stock-settled and cash-settled compensation capitalized 7 28 37 Total stock-settled and cash-settled compensation costs $ 47 $ 138 $ 194 Stock Options As of December 31, 2020, the Company had outstanding options to purchase shares of its common stock under the 2016 Plan, the 2011 Omnibus Equity Compensation Plan (the 2011 Plan), and the 2007 Omnibus Equity Compensation Plan (the 2007 Plan), (collectively, 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 Apache’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, 2020, 2019, and 2018: 2020 2019 2018 Shares Weighted Average Shares Weighted Average Shares Weighted Average (In thousands, except exercise price amounts) Outstanding, beginning of year 4,298 $ 75.24 4,872 $ 75.95 4,593 $ 83.36 Granted — — — — 812 45.93 Exercised — — — — (29) 41.79 Forfeited (37) 44.98 (80) 34.58 (121) 74.58 Expired (724) 92.14 (494) 88.82 (383) 104.21 Outstanding, end of year (1) 3,537 72.10 4,298 75.24 4,872 75.95 Expected to vest (2) 150 45.77 495 49.11 1,274 48.74 Exercisable, end of year (3) 3,387 73.26 3,803 78.64 3,598 85.59 (1) As of December 31, 2020, options outstanding had a weighted average remaining contractual life of 3.6 years and no intrinsic value. (2) As of December 31, 2020, options expected to vest had a weighted average remaining contractual life of 7.0 years and no intrinsic value. (3) As of December 31, 2020, options exercisable had a weighted average remaining contractual life of 3.4 years and no intrinsic value. The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model, a Level 2 fair value measurement. The following table summarizes specific assumptions used in the Company’s valuation: 2020 2019 2018 Expected volatility N/A N/A 33.74% Expected dividend yields N/A N/A 2.16% Expected term (in years) N/A N/A 6 Risk-free rate N/A N/A 2.42% Weighted-average grant-date fair value N/A N/A $ 13.15 N/A - not applicable. Assumptions related to the expected volatilities are based on the Company’s historical volatility of its common stock and other factors. The expected dividend yield is based on historical yields on the date of grant. The expected term of stock options granted represents the period of time that the stock options are expected to be outstanding and is derived from historical exercise behavior, current trends, and values derived from lattice-based models. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant. There were no options issued and no options exercised during the years ended December 31, 2020 and 2019. The intrinsic values of options exercised during the year ended December 31, 2018 was approximately $0.1 million. As of December 31, 2020, total compensation cost related to non-vested options not yet recognized was nil because they fully vest on January 5, 2021. 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 stock or 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. The cash-settled awards compensation expense 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, 2020, 2019, and 2018, compensation costs charged to expense for the restricted stock units and restricted stock phantom units was $39 million, $104 million, and $101 million, respectively. As of December 31, 2020, 2019, and 2018, capitalized compensation costs for the restricted stock units and restricted stock phantom units were $6 million, $24 million, and $29 million, respectively. The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2020, 2019, and 2018: 2020 2019 2018 Units Weighted Units Weighted Units Weighted (In thousands, except per share amounts) Non-vested, beginning of year 2,448 $ 46.65 3,153 $ 55.54 4,920 $ 56.67 Granted 1,352 24.60 1,479 36.81 608 45.59 Vested (3) (1,933) 48.65 (1,899) 53.99 (2,023) 55.10 Forfeited (315) 30.09 (285) 45.06 (352) 56.69 Non-vested, end of year (1)(2) 1,552 28.43 2,448 46.65 3,153 55.54 (1) As of December 31, 2020, there was $14 million of total unrecognized compensation cost related to 1,551,807 unvested stock-settled restricted stock units. (2) As of December 31, 2020, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.7 years. (3) The grant date fair values of the stock-settled awards vested during 2020, 2019, and 2018 were approximately $94 million, $103 million, and $111 million, respectively. The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2020, 2019, and 2018: For the Year Ended December 31, 2020 2019 2018 (In thousands) Non-vested, beginning of year 5,384 1,818 59 Adjustment for ALTM reverse stock split (1) (1,246) — — Granted (2) 3,462 4,831 1,973 Vested (1,618) (616) (38) Forfeited (1,559) (649) (176) Non-vested, end of year (3) 4,423 5,384 1,818 (1) On June 30, 2020, Altus executed a 1-for-20 reverse stock split of its outstanding common stock. Outstanding cash-settled awards are based on the per-share market price of ALTM stock. (2) Restricted stock phantom units granted during 2020 and 2019 included 3,378,486 and 3,401,477 awards, respectively, based on the per-share market price of Apache common stock and 83,239 and 1,429,135 awards, respectively, based on the per-share market price of ALTM common stock. The restricted stock phantom units granted during 2020 based on ALTM’s per-share market price reflect the 1-for-20 reverse stock split described above. (3) The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2020 was approximately $28 million. In January 2021, the Company awarded 1,354,349 restricted stock units and 4,360,656 restricted stock phantom units based on Apache’s weighted-average per-share market price of $16.18 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 $22 million and $71 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 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. Also during January 2021, the Company awarded 56,836 restricted stock phantom units based on ALTM’s weighted-average per-share market price of $48.84. The restricted stock phantom units represent a hypothetical interest in ALTM’s common stock and, once vested, are settled in cash. Total compensation cost for these restricted stock phantom units, absent any forfeitures, is estimated to be $3 million and was calculated based on the fair market value of ALTM’s common stock as of the grant date. 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 ALTM’s common stock. Performance Program To provide long-term incentives for the Company’s employees to deliver competitive shareholder returns, the Company makes annual grants of conditional restricted stock units to eligible employees. Apache has a performance program for certain eligible employees with payout for 50 percent of the shares based upon measurement of total shareholder return (TSR) of Apache common stock as compared to a designated peer group during a three-year performance period. Payout for the remaining 50 percent 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, 2020, are as described below: • In January 2017, the Company’s Board of Directors approved the 2017 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial stock-settled conditional restricted stock unit awards totaling 620,885 units. A total of 111,126 restricted stock units were outstanding as of December 31, 2020. The results for the performance period yielded a payout of 54 percent of target. • In January 2018, the Company’s Board of Directors approved the 2018 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 931,049 units. A total of 704,483 phantom units were outstanding as of December 31, 2020. The results for the performance period yielded a payout of 23 percent of target. • In January 2019, the Company’s Board of Directors approved the 2019 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,679,832 units. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,301,893 phantom units were outstanding as of December 31, 2020, from which a minimum of zero to a maximum of 2,603,786 phantom units could be awarded. • 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. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,410,404 phantom units were outstanding as of December 31, 2020, from which a minimum of zero to a maximum of 2,820,808 phantom units could be awarded. The fair value cost of the stock-settled awards was estimated on the date of grant and is recorded as compensation expense ratably over the applicable vesting term. The fair value of the cash-settled awards is remeasured at the end of each reporting period over the applicable vesting term. Compensation cost charged to expense under the performance programs was a credit of $8 million during 2020 and expenses of $24 million and $38 million during 2019 and 2018, respectively. Capitalized compensation costs under the performance programs was a credit of $1 million during 2020 and expenses of $3 million and $7 million during 2019 and 2018, respectively. The following table summarizes stock-settled conditional restricted stock unit activity for the year ended December 31, 2020: Units Weighted Average Grant- Date Fair Value (1) (In thousands) Non-vested, beginning of year 781 $ 52.69 Granted 18 62.31 Vested (445) 41.10 Forfeited (16) 56.66 Expired (227) 70.70 Non-vested, end of year (2)(3) 111 63.15 (1) The fair value of each conditional restricted stock unit award is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a three-year continuous risk-free interest rate; (ii) a constant volatility assumption based on the historical realized stock price volatility of the Company and the designated peer group; and (iii) the historical stock prices and expected dividends of the common stock of the Company and its designated peer group. (2) As of December 31, 2020, there was no unrecognized compensation cost related to 111,126 unvested stock-settled conditional restricted stock units. (3) As of December 31, 2020, the weighted-average remaining life of the unvested stock-settled conditional restricted stock units is approximately 0.0 years. The following table summarizes cash-settled conditional restricted stock unit activity for the year ended December 31, 2020: Units (In thousands) Non-vested, beginning of year 2,320 Granted 1,687 Vested (2) Forfeited (542) Expired (46) Non-vested, end of year (1) 3,417 (1) As of December 31, 2020, the outstanding liability for the unvested cash-settled conditional restricted stock units that had not been recognized was approximately $14 million.

ACCUMULATED OTHER COMPREHENSIVE

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Components of accumulated other comprehensive income (loss) include the following: As of December 31, 2020 2019 2018 (In millions) Share of equity method interests other comprehensive loss $ (1) $ (1) $ — Pension and postretirement benefit plan ( Note 12 ) 15 17 4 Accumulated other comprehensive income $ 14 $ 16 $ 4

MAJOR CUSTOMERS

MAJOR CUSTOMERS	12 Months Ended
	Dec. 31, 2020
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 2020, sales to EGPC and Vitol accounted for approximately 17 percent and 14 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues. During 2019, sales to BP and Sinopec, and their respective affiliates, each accounted for approximately 10 percent and 11 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues. During 2018, sales to BP, Sinopec, and EGPC, and their respective affiliates, each accounted for approximately 17 percent, 15 percent, and 10 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production 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.

BUSINESS SEGMENT INFORMATION

BUSINESS SEGMENT INFORMATION	12 Months Ended
	Dec. 31, 2020
Segment Reporting [Abstract]
BUSINESS SEGMENT INFORMATION	BUSINESS SEGMENT INFORMATION As of December 31, 2020, Apache is engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and the U.S. Apache also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. Apache’s Upstream business explores for, develops, and produces natural gas, crude oil and natural gas liquids. During 2018, Apache established a new reporting segment for its U.S. midstream business separate from its upstream oil and gas development activities. The midstream business is operated by Altus, which owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas. Financial information for each segment is presented below: Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2020 Oil revenues $ 1,102 $ 795 $ 1,209 $ — $ — $ 3,106 Natural gas revenues 280 67 251 — — 598 Natural gas liquids revenues 8 21 304 — — 333 Oil, natural gas, and natural gas liquids production revenues 1,390 883 1,764 — — 4,037 Purchased oil and gas sales — — 394 4 — 398 Midstream service affiliate revenues — — — 145 (145) — 1,390 883 2,158 149 (145) 4,435 Operating Expenses: Lease operating expenses 424 305 400 — (2) 1,127 Gathering, processing, and transmission 38 50 291 38 (143) 274 Purchased oil and gas costs — — 354 3 — 357 Taxes other than income — — 108 15 — 123 Exploration 63 28 168 — 15 274 Depreciation, depletion, and amortization 601 380 779 12 — 1,772 Asset retirement obligation accretion — 73 32 4 — 109 Impairments 529 7 3,963 2 — 4,501 1,655 843 6,095 74 (130) 8,537 Operating Income (Loss) $ (265) $ 40 $ (3,937) $ 75 $ (15) (4,102) Other Income (Expense): Gain on divestitures, net 32 Derivative instrument losses, net (223) Other 64 General and administrative (290) Transaction, reorganization, and separation (54) Financing costs, net (267) Loss Before Income Taxes $ (4,840) Total Assets (3) $ 3,003 $ 2,220 $ 5,540 $ 1,786 $ 197 $ 12,746 Net Property and Equipment $ 1,955 $ 1,773 $ 4,760 $ 196 $ 135 $ 8,819 Additions to Net Property and Equipment $ 454 $ 215 $ 345 $ 12 $ 136 $ 1,162 Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2019 Oil revenues $ 1,969 $ 1,163 $ 2,098 $ — $ — $ 5,230 Natural gas revenues 295 90 293 — — 678 Natural gas liquids revenues 12 23 372 — — 407 Oil, natural gas, and natural gas liquids production revenues 2,276 1,276 2,763 — — 6,315 Purchased oil and gas sales — — 176 — — 176 Midstream service affiliate revenues — — — 136 (136) — 2,276 1,276 2,939 136 (136) 6,491 Operating Expenses: Lease operating expenses 484 320 645 — (2) 1,447 Gathering, processing, and transmission 40 45 299 56 (134) 306 Purchased oil and gas costs — — 142 — — 142 Taxes other than income — — 194 13 — 207 Exploration 100 2 688 — 15 805 Depreciation, depletion, and amortization 708 366 1,566 40 — 2,680 Asset retirement obligation accretion — 76 29 2 — 107 Impairments — — 1,648 1,301 — 2,949 1,332 809 5,211 1,412 (121) 8,643 Operating Income (Loss) $ 944 $ 467 $ (2,272) $ (1,276) $ (15) (2,152) Other Income (Expense): Gain on divestitures, net 43 Derivative instrument losses, net (35) Other 54 General and administrative (406) Transaction, reorganization, and separation (50) Financing costs, net (462) Loss Before Income Taxes $ (3,008) Total Assets (3) $ 3,700 $ 2,473 $ 10,388 $ 1,479 $ 67 $ 18,107 Net Property and Equipment $ 2,573 $ 1,956 $ 9,385 $ 206 $ 38 $ 14,158 Additions to Net Property and Equipment $ 454 $ 183 $ 1,696 $ 308 $ 93 $ 2,734 Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2018 Oil revenues $ 2,396 $ 1,179 $ 2,271 $ — $ — $ 5,846 Natural gas revenues 339 122 458 — — 919 Natural gas liquids revenues 13 20 550 — — 583 Oil, natural gas, and natural gas liquids production revenues 2,748 1,321 3,279 — — 7,348 Purchased oil and gas sales — — 357 — — 357 Midstream service affiliate revenues — — — 77 (77) — 2,748 1,321 3,636 77 (77) 7,705 Operating Expenses: Lease operating expenses 428 341 670 — — 1,439 Gathering, processing, and transmission 47 42 282 54 (77) 348 Purchased oil and gas costs — — 340 — — 340 Taxes other than income — — 207 8 — 215 Exploration 88 192 219 — 4 503 Depreciation, depletion, and amortization 745 375 1,266 19 — 2,405 Asset retirement obligation accretion — 75 32 1 — 108 Impairments 63 10 438 — — 511 1,371 1,035 3,454 82 (73) 5,869 Operating Income (Loss) $ 1,377 $ 286 $ 182 $ (5) $ (4) 1,836 Other Income (Expense): Gain on divestitures, net 23 Derivative instrument losses, net (17) Other 53 General and administrative (431) Transaction, reorganization, and separation (28) Financing costs, net (478) Income Before Income Taxes $ 958 Total Assets (3) $ 4,260 $ 2,456 $ 12,962 $ 1,857 $ 47 $ 21,582 Net Property and Equipment $ 2,856 $ 2,148 $ 12,145 $ 1,227 $ 45 $ 18,421 Additions to Net Property and Equipment $ 594 $ 223 $ 2,544 $ 545 $ 8 $ 3,914 (1) Includes revenue from non-customers for the years ended December 31, 2020, 2019, and 2018 of: For the Year Ended December 31, 2020 2019 2018 (In millions) Oil $ 95 $ 410 $ 592 Natural gas 14 40 58 Natural gas liquids — 1 2 (2) Includes a noncontrolling interest in Egypt and Altus Midstream. (3) Intercompany balances are excluded from total assets.

SUPPLEMENTAL OIL AND GAS DISCLO

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)	12 Months Ended
	Dec. 31, 2020
Extractive Industries [Abstract]
Supplemental Oil and Gas Disclosures (Unaudited)	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. Apache has no long-term agreements to purchase oil or gas production from foreign governments or authorities. United Egypt (1) North Sea Other Total (1) (In millions, except per boe) 2020 Oil and gas production revenues $ 1,764 $ 1,390 $ 883 $ — $ 4,037 Operating cost: Depreciation, depletion, and amortization (2) 726 540 377 — 1,643 Asset retirement obligation accretion 32 — 73 — 105 Lease operating expenses 400 424 305 — 1,129 Gathering, processing, and transmission 291 38 50 — 379 Exploration expenses 168 63 28 15 274 Impairments related to oil and gas properties 3,938 374 7 — 4,319 Production taxes (3) 106 — — — 106 Income tax (818) (22) 17 — (823) 4,843 1,417 857 15 7,132 Results of operations $ (3,079) $ (27) $ 26 $ (15) $ (3,095) 2019 Oil and gas production revenues $ 2,763 $ 2,276 $ 1,276 $ — $ 6,315 Operating cost: Depreciation, depletion, and amortization (2) 1,508 641 363 — 2,512 Asset retirement obligation accretion 29 — 76 — 105 Lease operating expenses 645 484 320 — 1,449 Gathering, processing, and transmission 299 40 45 — 384 Exploration expenses 688 100 2 15 805 Impairments related to oil and gas properties 1,633 — — — 1,633 Production taxes (3) 191 — — — 191 Income tax (468) 455 188 — 175 4,525 1,720 994 15 7,254 Results of operations $ (1,762) $ 556 $ 282 $ (15) $ (939) 2018 Oil and gas production revenues $ 3,279 $ 2,748 $ 1,321 $ — $ 7,348 Operating cost: Depreciation, depletion, and amortization (2) 1,206 688 371 — 2,265 Asset retirement obligation accretion 32 — 75 — 107 Lease operating expenses 670 428 341 — 1,439 Gathering, processing, and transmission 282 47 42 — 371 Exploration expenses 219 88 192 4 503 Impairments related to oil and gas properties 265 63 10 — 338 Production taxes (3) 203 — — — 203 Income tax 87 645 116 — 848 2,964 1,959 1,147 4 6,074 Results of operations $ 315 $ 789 $ 174 $ (4) $ 1,274 (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 Egypt (2) North Sea Other Total (2) (In millions) 2020 Acquisitions: Proved $ — $ 7 $ — $ — $ 7 Unproved 4 — — — 4 Exploration 8 102 68 150 328 Development 332 378 162 — 872 Costs incurred (1) $ 344 $ 487 $ 230 $ 150 $ 1,211 (1) Includes capitalized interest and asset retirement costs as follows: Capitalized interest $ — $ — $ — $ 3 $ 3 Asset retirement costs 9 — 29 — 38 2019 Acquisitions: Proved $ 3 $ 5 $ — $ — $ 8 Unproved 47 10 — — 57 Exploration 162 139 62 105 468 Development 1,500 374 119 3 1,996 Costs incurred (1) $ 1,712 $ 528 $ 181 $ 108 $ 2,529 (1) Includes capitalized interest and asset retirement costs as follows: Capitalized interest $ 23 $ — $ 5 $ 4 $ 32 Asset retirement costs 14 — (111) — (97) 2018 Acquisitions: Proved $ — $ 6 $ — $ — $ 6 Unproved 111 16 — — 127 Exploration 640 175 113 12 940 Development 1,791 457 133 — 2,381 Costs incurred (1) $ 2,542 $ 654 $ 246 $ 12 $ 3,454 (1) Includes capitalized interest and asset retirement costs as follows: Capitalized interest $ 23 $ — $ 11 $ 2 $ 36 Asset retirement costs 93 — (62) — 31 (2) Includes a noncontrolling interest in Egypt. 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 Egypt (1) North Other Total (1) (In millions) 2020 Proved properties $ 20,343 $ 12,069 $ 8,805 $ — $ 41,217 Unproved properties 348 77 42 135 602 20,691 12,146 8,847 135 41,819 Accumulated DD&A (16,252) (10,290) (7,081) — (33,623) $ 4,439 $ 1,856 $ 1,766 $ 135 $ 8,196 2019 Proved properties $ 20,291 $ 11,614 $ 8,635 $ — $ 40,540 Unproved properties 509 109 10 38 666 20,800 11,723 8,645 38 41,206 Accumulated DD&A (11,783) (9,377) (6,700) — (27,860) $ 9,017 $ 2,346 $ 1,945 $ 38 $ 13,346 (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, Apache 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. Apache 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 Egypt (1) North Total (1) (Thousands of barrels) Proved developed reserves: December 31, 2017 304,279 124,568 92,598 521,445 December 31, 2018 300,484 110,014 104,491 514,989 December 31, 2019 278,145 103,573 101,712 483,430 December 31, 2020 206,936 95,981 86,566 389,483 Proved undeveloped reserves: December 31, 2017 31,904 16,198 14,013 62,115 December 31, 2018 45,182 9,484 11,278 65,944 December 31, 2019 46,716 10,831 10,049 67,596 December 31, 2020 25,516 11,228 7,273 44,017 Total proved reserves: Balance December 31, 2017 336,183 140,766 106,611 583,560 Extensions, discoveries and other additions 61,976 22,473 15,682 100,131 Purchases of minerals in-place 140 — — 140 Revisions of previous estimates (14,334) (9,556) 10,613 (13,277) Production (38,252) (34,185) (17,137) (89,574) Sales of minerals in-place (47) — — (47) Balance December 31, 2018 345,666 119,498 115,769 580,933 Extensions, discoveries and other additions 52,297 21,039 9,017 82,353 Revisions of previous estimates (16,446) 4,752 5,132 (6,562) Production (38,344) (30,885) (18,157) (87,386) Sales of minerals in-place (18,312) — — (18,312) Balance December 31, 2019 324,861 114,404 111,761 551,026 Extensions, discoveries and other additions 17,858 17,855 5,275 40,988 Revisions of previous estimates (69,247) 2,541 (4,756) (71,462) Production (32,299) (27,591) (18,441) (78,331) Sales of minerals in-place (8,721) — — (8,721) Balance December 31, 2020 232,452 107,209 93,839 433,500 (1) Includes proved reserves of 36 MMbbls, 38 MMbbls, 40 MMbbls, and 47 MMbbls as of December 31, 2020, 2019, 2018, and 2017, respectively, attributable to a noncontrolling interest in Egypt. Natural Gas Liquids United Egypt (1) North Total (1) (Thousands of barrels) Proved developed reserves: December 31, 2017 171,005 685 2,025 173,715 December 31, 2018 197,574 502 1,938 200,014 December 31, 2019 158,794 667 2,317 161,778 December 31, 2020 150,599 716 2,053 153,368 Proved undeveloped reserves: December 31, 2017 29,559 39 353 29,951 December 31, 2018 33,796 60 631 34,487 December 31, 2019 23,569 90 660 24,319 December 31, 2020 15,141 126 320 15,587 Total proved reserves: Balance December 31, 2017 200,564 724 2,378 203,666 Extensions, discoveries and other additions 60,990 144 1,444 62,578 Purchases of minerals in-place 40 — — 40 Revisions of previous estimates (9,250) 31 (819) (10,038) Production (20,969) (337) (434) (21,740) Sales of minerals in-place (5) — — (5) Balance December 31, 2018 231,370 562 2,569 234,501 Extensions, discoveries and other additions 41,343 27 697 42,067 Revisions of previous estimates (32,569) 508 345 (31,716) Production (24,959) (340) (634) (25,933) Sales of minerals in-place (32,822) — — (32,822) Balance December 31, 2019 182,363 757 2,977 186,097 Extensions, discoveries and other additions 11,435 97 312 11,844 Revisions of previous estimates (469) 264 (207) (412) Production (27,133) (276) (709) (28,118) Sales of minerals in-place (456) — — (456) Balance December 31, 2020 165,740 842 2,373 168,955 (1) Includes proved reserves of 281 Mbbls, 252 Mbbls, 187 Mbbls, and 241 Mbbls as of December 31, 2020, 2019, 2018, and 2017, respectively, attributable to a noncontrolling interest in Egypt. Natural Gas United Egypt (1) North Total (1) (Millions of cubic feet) Proved developed reserves: December 31, 2017 1,347,009 540,667 83,342 1,971,018 December 31, 2018 1,626,403 476,132 95,347 2,197,882 December 31, 2019 945,938 433,382 106,329 1,485,649 December 31, 2020 1,052,756 409,035 68,159 1,529,950 Proved undeveloped reserves: December 31, 2017 297,226 47,255 11,063 355,544 December 31, 2018 267,090 33,006 15,804 315,900 December 31, 2019 115,040 24,704 16,604 156,348 December 31, 2020 76,504 12,572 8,341 97,417 Total proved reserves: Balance December 31, 2017 1,644,235 587,922 94,405 2,326,562 Extensions, discoveries and other additions 704,135 79,394 55,274 838,803 Purchases of minerals in-place 906 — — 906 Revisions of previous estimates (239,204) (38,892) (21,933) (300,029) Production (216,538) (119,286) (16,595) (352,419) Sales of minerals in-place (41) — — (41) Balance December 31, 2018 1,893,493 509,138 111,151 2,513,782 Extensions, discoveries and other additions 249,205 34,758 27,711 311,674 Revisions of previous estimates (509,753) 18,570 4,015 (487,168) Production (233,447) (104,380) (19,944) (357,771) Sales of minerals in-place (338,520) — — (338,520) Balance December 31, 2019 1,060,978 458,086 122,933 1,641,997 Extensions, discoveries and other additions 60,965 83,718 8,140 152,823 Revisions of previous estimates 215,166 (19,849) (33,541) 161,776 Production (205,594) (100,348) (21,032) (326,974) Sales of minerals in-place (2,255) — — (2,255) Balance December 31, 2020 1,129,260 421,607 76,500 1,627,367 (1) Includes proved reserves of 141 Bcf, 153 Bcf, 170 Bcf, and 196 Bcf as of December 31, 2020, 2019, 2018, and 2017, respectively, attributable to a noncontrolling interest in Egypt. Total Equivalent Reserves United Egypt (1) North Total (1) (Thousands barrels of oil equivalent) Proved developed reserves: December 31, 2017 699,786 215,364 108,513 1,023,663 December 31, 2018 769,125 189,871 122,320 1,081,316 December 31, 2019 594,595 176,470 121,751 892,816 December 31, 2020 532,994 164,870 99,979 797,843 Proved undeveloped reserves: December 31, 2017 111,001 24,112 16,210 151,323 December 31, 2018 123,493 15,045 14,543 153,081 December 31, 2019 89,458 15,038 13,476 117,972 December 31, 2020 53,408 13,449 8,983 75,840 Total proved reserves: Balance December 31, 2017 810,787 239,476 124,723 1,174,986 Extensions, discoveries and other additions 240,322 35,849 26,338 302,509 Purchases of minerals in-place 331 — — 331 Revisions of previous estimates (63,451) (16,007) 6,139 (73,319) Production (95,312) (54,402) (20,337) (170,051) Sales of minerals in-place (59) — — (59) Balance December 31, 2018 892,618 204,916 136,863 1,234,397 Extensions, discoveries and other additions 135,174 26,859 14,333 176,366 Revisions of previous estimates (133,974) 8,355 6,146 (119,473) Production (102,211) (48,622) (22,115) (172,948) Sales of minerals in-place (107,554) — — (107,554) Balance December 31, 2019 684,053 191,508 135,227 1,010,788 Extensions, discoveries and other additions 39,454 31,905 6,944 78,303 Revisions of previous estimates (33,854) (502) (10,554) (44,910) Production (93,698) (44,592) (22,655) (160,945) Sales of minerals in-place (9,553) — — (9,553) Balance December 31, 2020 586,402 178,319 108,962 873,683 (1) Includes include total proved reserves of 59 MMboe, 64 MMboe, 68 MMboe, and 80 MMboe as of December 31, 2020, 2019, 2018, and 2017, respectively, attributable to a noncontrolling interest in Egypt. During 2020, Apache added approximately 78 MMboe from extensions, discoveries, and other additions. The Company recorded 39 MMboe of exploration and development adds in the U.S., primarily in the Southern Midland Basin (26 MMboe) associated with the Wolfcamp and Spraberry drilling programs and the remainder in the Delaware Basin and Austin Chalk. The international operations contributed 39 MMboe of exploration and development adds during 2020, with Egypt contributing 32 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area and Umbarka Area concessions. The North Sea contributed 7 MMboe from drilling success, primarily in the Beryl Field. The Company had combined downward revisions of previously estimated reserves of 45 MMboe. Downward revisions related to changes in product prices accounted for 70 MMboe, engineering and performance upward revisions accounted for 27 MMboe, and downward interest revisions accounted for 2 MMboe. The Company also sold 10 MMboe of proved reserves associated with U.S. divestitures, primarily related to Eastern Shelf and Magnet Withers/Pickett Ridge. During 2019, Apache added approximately 176 MMboe from extensions, discoveries, and other additions. The Company recorded 135 MMboe of exploration and development adds in the U.S., primarily associated with Woodford, Bone Springs, Spraberry, Barnett, and Wolfcamp drilling programs in the Permian Basin (129 MMboe) and various offset drilling activity in the Midcontinent region (6 MMboe). The Company’s international assets contributed 41 MMboe of exploration and development adds during 2019. Egypt contributed 27 MMboe from onshore exploration and appraisal activity in the Khalda Extension 2, Khalda, Khalda Extension 3, East Bahariya Extension 3, and West Kanayis concessions. The North Sea contributed 14 MMboe from drilling success in the Beryl and Forties fields. The Company had combined downward revisions of previously estimated reserves of 119 MMboe. Downward revisions related to changes in product prices accounted for 139 MMboe and engineering and performance upward revisions accounted for 20 MMboe. The Company also sold 107 MMboe of proved reserves associated with U.S. divestitures, primarily related to the sale of the Company’s Woodford-SCOOP and STACK plays and western Anadarko Basin assets. During 2018, Apache added approximately 303 MMboe from extensions, discoveries, and other additions. The Company recorded 240 MMboe of exploration and development adds in the U.S., primarily associated with Woodford, Bone Springs, Yeso, Barnett, and Wolfcamp drilling programs in the Permian Basin (217 MMboe) and Woodford and Austin Chalk drilling activity in the Midcontinent region (20 MMboe). The Company’s international assets contributed 62 MMboe of exploration and development adds during 2018. Egypt contributed 36 MMboe from onshore exploration and appraisal activity in the Khalda Extension 2, Khalda, Khalda Extension 3, Matruh, and West Kalabsha concessions. The North Sea contributed 26 MMboe from drilling success in the Beryl and Forties fields. The Company had combined downward revisions of previously estimated reserves of 73 MMboe. Downward revisions related to changes in product prices accounted for 24 MMboe, interest revisions accounted for 5 MMboe, and engineering and performance downward revisions accounted for 44 MMboe. Approximately 10 percent of the Company’s year-end 2020 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, 2020, 2019, and 2018 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 current laws, 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 Egypt (1) North Total (1) (In millions) 2020 Cash inflows $ 12,537 $ 5,560 $ 4,122 $ 22,219 Production costs (6,244) (1,704) (2,388) (10,336) Development costs (1,555) (633) (2,448) (4,636) Income tax expense — (1,096) 316 (780) Net cash flows 4,738 2,127 (398) 6,467 10 percent discount rate (1,829) (437) 1,111 (1,155) Discounted future net cash flows (2) $ 2,909 $ 1,690 $ 713 $ 5,312 2019 Cash inflows $ 21,694 $ 8,306 $ 7,454 $ 37,454 Production costs (10,642) (1,847) (2,730) (15,219) Development costs (1,740) (707) (2,651) (5,098) Income tax expense (27) (1,930) (784) (2,741) Net cash flows 9,285 3,822 1,289 14,396 10 percent discount rate (4,003) (808) 297 (4,514) Discounted future net cash flows (2) $ 5,282 $ 3,014 $ 1,586 $ 9,882 2018 Cash inflows $ 29,906 $ 9,866 $ 9,206 $ 48,978 Production costs (13,699) (1,799) (2,588) (18,086) Development costs (2,150) (792) (2,714) (5,656) Income tax expense (19) (2,455) (1,352) (3,826) Net cash flows 14,038 4,820 2,552 21,410 10 percent discount rate (6,516) (1,066) (107) (7,689) Discounted future net cash flows (2) $ 7,522 $ 3,754 $ 2,445 $ 13,721 (1) Includes discounted future net cash flows of approximately $563 million , $1.0 billion, and $1.3 billion as of December 31, 2020, 2019, and 2018, 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 $7.1 billion , $12.4 billion, and $16.9 billion as of December 31, 2020, 2019, and 2018, respectively. The following table sets forth the principal sources of change in the discounted future net cash flows: For the Year Ended December 31, 2020 2019 2018 (In millions) Sales, net of production costs $ (2,422) $ (4,291) $ (5,335) Net change in prices and production costs (5,753) (3,034) 3,902 Discoveries and improved recovery, net of related costs 751 2,042 3,889 Change in future development costs 20 (75) 47 Previously estimated development costs incurred during the period 576 983 910 Revision of quantities (418) (741) (648) Purchases of minerals in-place — — 6 Accretion of discount 1,236 1,693 1,216 Change in income taxes 1,533 720 (1,125) Sales of minerals in-place (104) (817) (1) Change in production rates and other 11 (319) 777 $ (4,570) $ (3,839) $ 3,638

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. 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 Apache 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 Apache’s Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate component of equity in the Company’s consolidated balance sheet. Additionally, third-party investors own a minority interest of approximately 21 percent of Altus Midstream Company (ALTM), which is reflected as a separate noncontrolling interest component of equity in Apache’s consolidated balance sheet. ALTM qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of ALTM because it has concluded that it has a controlling financial interest in ALTM and is the primary beneficiary of the VIE. On June 12, 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units (the Preferred Units) through a private offering that admitted additional limited partners with separate rights for the Preferred Unit holders. Refer to Note 1 3 —Redeemable Noncontrolling Interest - Altus for further detail.
Use of Estimates	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 (see “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (see Note 2—Acquisitions and Divestitures ), the assessment of asset retirement obligations (see Note 8—Asset Retirement Obligation ), the estimate of income taxes (see Note 10—Income Taxes ), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (see Note 18—Supplemental Oil and Gas Disclosures (Unaudited) ).
Fair Value Measurements	Fair Value Measurements Certain assets and liabilities are reported at fair value on a recurring basis in Apache’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). Recurring fair value measurements are presented in further detail in Note 4—Derivative Instruments and Hedging Activities , Note 9—Debt and Financing Costs , Note 12—Retirement and Deferred Compensation Plans , and Note 13—Redeemable Noncontrolling Interest - Altus . The Company also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. The following table presents a summary of asset impairments recorded in connection with fair value assessments: For the Year Ended December 31, 2020 2019 2018 (In millions) Oil and gas proved property $ 4,319 $ 1,484 $ 328 Gathering, processing, and transmission facilities 68 1,295 56 Equity method investment — — 113 Divested unproved properties and leasehold — 149 10 Goodwill 87 — — Inventory and other 27 21 4 Total Impairments $ 4,501 $ 2,949 $ 511 For the year ended December 31, 2020, the Company recorded asset impairments totaling $4.5 billion in connection with fair value assessments. Given the crude oil price collapse on lower demand and economic activity resulting from the coronavirus disease 2019 (COVID-19) global pandemic and related governmental actions, the Company assessed its oil and gas property and gathering, processing, and transmission (GPT) facilities for impairment based on the net book value of its assets as of March 31, 2020. The Company recorded proved property impairments totaling $3.9 billion, $354 million, and $7 million in the U.S., Egypt, and North Sea, respectively, all of which were impaired to their estimated fair values as a result of lower forecasted commodity prices, changes to planned development activity, and increasing market uncertainty. Impairments totaling $68 million were similarly recorded for GPT facilities in Egypt. These impairments are discussed in further detail below in “Property and Equipment - Oil and Gas Property” and “Property and Equipment - Gathering, Processing, and Transmission Facilities.” The Company also performed an interim impairment analysis of the goodwill related to its Egypt reporting unit. Reductions in estimated net present value of expected future cash flows from oil and gas properties resulted in implied fair values below the carrying values of the Company’s Egypt reporting unit. As a result of these assessments, the Company recognized non-cash impairments of the entire amount of recorded goodwill in the Egypt reporting unit of $87 million in the first quarter of 2020. During the remainder of 2020, the Company recorded additional proved property impairments totaling $20 million in Egypt, as well as $13 million for the early termination of drilling rig leases, $5 million for inventory revaluations, and $9 million of other asset impairments, all in the U.S. During the fourth quarter of 2019, following a material reduction to planned investment in Apache’s Alpine High development, the Company recorded impairments totaling $1.4 billion for its Alpine High proved properties and upstream infrastructure which were written down to their fair values. Altus separately assessed its long-lived infrastructure assets for impairment based on expected reductions to future throughput volumes from Alpine High. Altus subsequently recorded impairments totaling $1.3 billion on its GPT facilities. These impairments are discussed in further detail below in “Property and Equipment - Oil and Gas Property” and “Property and Equipment - Gathering, Processing, and Transmission Facilities.” Separate from the Company’s Alpine High and Altus impairments, Apache entered into agreements to sell certain of its assets in the western Anadarko Basin in Oklahoma and Texas. As a result of these agreements, a separate impairment analysis was performed for each of the assets within the disposal groups. The analyses were based on the agreed-upon proceeds less costs to sell for the transaction, a Level 1 fair value measurement. The carrying value of the net assets to be divested exceeded the fair value implied by the expected net proceeds, resulting in impairments in the second and fourth quarters of 2019 totaling $255 million, including $101 million on the Company’s proved properties, $149 million on its unproved properties, and $5 million on other working capital. For more information regarding this transaction, refer to Note 2—Acquisitions and Divestitures . For the year ended December 31, 2018, the Company recorded asset impairments totaling $511 million in connection with fair value assessments. Impairments totaling $328 million and $56 million were recorded for proved properties, and a gathering and processing facility in Oklahoma, respectively, which were written down to their fair values associated with U.S. assets to be divested. During the third quarter of 2018, Apache agreed to sell certain of its unproved properties offshore the U.K. in the North Sea. As a result, the Company performed a fair value assessment of the properties and recorded a $10 million impairment on the carrying values of the associated capitalized exploratory well costs. The fair value of the impaired assets was determined using the negotiated sales price, a Level 1 fair value measurement. Also in 2018, the Company recorded $113 million for the impairment of an equity method investment in the U.S. based on a negotiated sales price and $4 million for inventory write-downs in the U.S. for obsolescence.
Cash and Cash Equivalents	Cash and Cash EquivalentsThe 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.
Accounts Receivable and Allowance for Credit Losses	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. In June 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-13, “Financial Instruments-Credit Losses.” The standard changes the impairment model for trade receivables, held-to-maturity debt securities, net investments in leases, loans, and other financial assets measured at amortized cost. This ASU requires the use of a new forward-looking “expected loss” model compared to the previous “incurred loss” model, resulting in accelerated recognition of credit losses. Apache adopted this update in the first quarter of 2020. This ASU primarily applies to the Company’s accounts receivable balances, of which the majority are received within a short-term period of one year or less. 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 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 adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.
Inventories	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.
Property and Equipment	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, property and equipment cost is based on the fair values at the acquisition date.
Oil and Gas Property	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. 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 Apache’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. The significant decline in crude oil and natural gas prices, as well as longer-term commodity price outlooks, related to reduced demand for oil and natural gas as a result of the COVID-19 pandemic and related governmental actions indicated possible impairment of the Company’s proved and unproved oil and gas properties in early 2020. In addition to estimating risk-adjusted reserves and future production volumes, estimated future commodity prices are the largest driver in variability of undiscounted pre-tax cash flows. Expected cash flows were estimated based on management’s views of published West Texas Intermediate (WTI), Brent, and Henry Hub forward pricing as of the balance sheet dates. Other significant assumptions and inputs used to calculate estimated future cash flows include estimates for future development activity, exploration plans and remaining lease terms. A 10 percent discount rate, based on a market-based weighted-average cost of capital estimate, was applied to the undiscounted cash flow estimate to value all of the Company’s asset groups that were subject to impairment charges in 2020. Similar assumptions were applied to impairments recorded in 2019 and 2018. The following table represents non-cash impairments charges of the carrying value of the Company’s proved and unproved properties: For the Year Ended December 31, 2020 2019 2018 (In millions) Proved properties: U.S. $ 3,938 $ 1,484 $ 265 Egypt 374 — 63 North Sea 7 — — Total proved properties $ 4,319 $ 1,484 $ 328 Unproved properties: U.S. $ 92 $ 760 $ 96 Egypt 8 8 — North Sea 1 — 128 Total unproved properties $ 101 $ 768 $ 224 Proved properties impaired had aggregate fair values as of the most recent date of impairment of $1.9 billion and $628 million for 2020 and 2019, respectively. Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. However, in 2019, unproved impairments of $149 million were recorded as a component of “Impairments” in connection with an agreement to sell certain non-core leasehold properties in Oklahoma and Texas. In addition, in 2018, unproved impairments of $10 million were recorded as a component of “Impairments” in connection with an agreement to sell certain unproved properties in the North Sea.
Gathering, Processing, and Transmission Facilities	Gathering, Processing, and Transmission Facilities GPT facilities totaled $670 million and $799 million at December 31, 2020 and 2019, respectively, with accumulated depreciation for these assets totaling $323 million and $310 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 Apache-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within or in close proximity 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. Apache assessed its long-lived infrastructure assets for impairment at March 31, 2020, and recorded an impairment of $68 million on its GPT facilities in Egypt during the first quarter of 2020. The fair values of the impaired assets, which were determined to be $46 million, were estimated using the income approach, which considers internal estimates based on future throughput volumes from applicable development concessions in Egypt and estimated costs to operate. These assumptions were applied based on throughput assumptions developed in relation to the oil and gas proved property impairment assessment as discussed above to develop future cash flow projections that were then discounted to estimated fair value, using a 10 percent discount rate, based on a market-based weighted-average cost of capital estimate. Apache has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy. As discussed under “Fair Value Measurements” above, the Company decided to materially reduce its planned investment in the Alpine High play during its fourth-quarter 2019 capital planning review. Altus management subsequently assessed its long-lived infrastructure assets for impairment given the expected reduction to future throughput volumes and recorded impairments of $1.3 billion on its gathering, processing, and transmission assets. The fair values of the impaired assets were determined to be $203 million as of the time of the impairment and were estimated using the income approach. The income approach considered internal estimates of future throughput volumes, processing rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using discount rates believed to be consistent with those applied by market participants. Apache has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy. During 2018, the Company recorded impairments of the entire net book value of certain GPT assets in the U.S. in the amount of $56 million associated with a proposed divestiture package. The costs of GPT assets sold or otherwise disposed of and associated accumulated depreciation are removed from Apache’s consolidated financial statements, and the resulting gain or loss is reflected in “Gain on divestitures” under “Revenues and Other” in the Company’s statement of consolidated operations. A $2 million loss was recorded on the sale of power generators during 2020, and no gain or loss on the sales of GPT facilities was recognized during 2019 or 2018.
Asset Retirement Costs and Obligations	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	Capitalized Interest
Goodwill	Goodwill Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed, and it is recorded in “Deferred charges and other” in the Company’s consolidated balance sheet. The Company assesses the carrying amount of goodwill by testing for impairment annually and when impairment indicators arise. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. Apache assesses each country as a reporting unit, with Egypt being the only reporting unit to have associated goodwill. The fair value of the reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then goodwill is written down to its implied fair value through a charge to expense.
Commitments and Contingencies	Commitments and ContingenciesAccruals 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.
Revenue Recognition	Revenue Recognition The years ended 2019 and 2018 include the reclassification of $176 million and $357 million, respectively, from “Other” to “Purchased oil and gas sales,” both within “Revenues and Other” and the respective associated $142 million and $340 million purchased oil and gas costs from “Other” within “Revenues and Other” to “Purchased oil and gas costs” within “Operating Expenses” on the Company’s consolidated statement of operations to conform to the current-year presentation. 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 Apache-related production volumes, the Company also sells commodity volumes purchased from third-parties to fulfill sales obligations and commitments as the Company’s production fluctuates with potential operational issues and changes to development plans. Under these short-term 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. The Company’s Egypt operations are conducted pursuant to production sharing contracts under which the contractor partners (Contractors) pay all operating and capital costs for exploring and developing defined concessions. A percentage of the production, generally up to 40 percent, is available to Contractors to recover these operating and capital costs over contractually defined periods. The balance of the production is split among the Contractors and the Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. Additionally, the Contractors’ income taxes, which remain the liability of the Contractors under domestic law, are paid by EGPC on behalf of the Contractors out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of Apache as Contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Revenues related to Egypt’s tax volumes are considered revenue from a non-customer. Refer to Note 1 7 —Business Segment Information for a disaggregation of revenue by product and reporting segment. Altus Midstream The Company’s Altus Midstream segment is operated by ALTM, through its subsidiary, Altus Midstream LP (collectively, Altus). Altus generates revenue from contracts with customers from its gathering, compression, processing, and transmission services provided on Apache’s natural gas and natural gas liquid production volumes. Under these long-term commercial service contracts, providing the related service represents a single, distinct performance obligation on behalf of Altus that is satisfied over time. In accordance with the terms of these agreements, Altus receives a fixed fee for each contract year, subject to yearly fee escalation recalculations. Revenue is measured using the output method and recognized in the amount to which Altus has the right to invoice, as performance completed to date corresponds directly with the value to its customers. For the periods presented, Altus Midstream segment revenues were primarily attributable to sales between Altus and Apache, which are fully eliminated upon consolidation. Payment Terms and Contract Balances 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. Receivables from contracts with customers, net of allowance for credit losses, totaled $670 million and $945 million as of December 31, 2020 and 2019, respectively. 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.
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities Apache 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.
Income Taxes	Income Taxes Apache 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.
Earnings Per Share	Earnings Per ShareThe 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. The Company uses the “if-converted method” to determine the potential dilutive effect of an assumed exchange of the outstanding Preferred Units of Altus Midstream for shares of Altus’ common stock.
Stock-Based Compensation	Stock-Based CompensationApache 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.
Treasury Stock	Treasury Stock The Company follows the weighted-average-cost method of accounting for treasury stock transactions.
New Pronouncements Issued But Not Yet Adopted	New Pronouncements Issued But Not Yet Adopted In October 2020, the FASB issued ASU 2020-10, “Codification Improvements,” which clarifies or improves disclosure requirements for various topics to align with Securities and Exchange Commission (SEC) regulations. This update is effective for the Company beginning in the first quarter of 2021 and will be applied retrospectively. The adoption and implementation of this ASU will not have a material impact on the Company’s financial statements. In August 2020, the FASB issued ASU 2020-06, “Debt-Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40)” to improve financial reporting associated with the accounting for convertible instruments and contracts in an entity’s own equity. This update is effective for the Company beginning in the first quarter of 2022, with early adoption permitted, using either the modified or fully retrospective method with a cumulative effect adjustment to the opening balance of retained earnings. The Company is evaluating the effect of adoption of the ASU and does not believe it will have a material impact on its financial statements.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Schedule of Asset Impairments Recorded in Connection with Fair Value Assessment	The following table presents a summary of asset impairments recorded in connection with fair value assessments: For the Year Ended December 31, 2020 2019 2018 (In millions) Oil and gas proved property $ 4,319 $ 1,484 $ 328 Gathering, processing, and transmission facilities 68 1,295 56 Equity method investment — — 113 Divested unproved properties and leasehold — 149 10 Goodwill 87 — — Inventory and other 27 21 4 Total Impairments $ 4,501 $ 2,949 $ 511
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, 2020 2019 2018 (In millions) Allowance for credit loss at beginning of year $ 88 $ 92 $ 84 Additional provisions for the year 7 3 9 Uncollectible accounts written off, net of recoveries — (7) (1) Allowance for credit loss at end of year $ 95 $ 88 $ 92
Schedule of Non-cash Impairments of Proved and Unproved Properties	The following table represents non-cash impairments charges of the carrying value of the Company’s proved and unproved properties: For the Year Ended December 31, 2020 2019 2018 (In millions) Proved properties: U.S. $ 3,938 $ 1,484 $ 265 Egypt 374 — 63 North Sea 7 — — Total proved properties $ 4,319 $ 1,484 $ 328 Unproved properties: U.S. $ 92 $ 760 $ 96 Egypt 8 8 — North Sea 1 — 128 Total unproved properties $ 101 $ 768 $ 224
Schedule of Goodwill	The following presents the changes to goodwill for the years ended 2020, 2019, and 2018: Egypt Total (In millions) Goodwill at December 31, 2017 $ 87 $ 87 Impairments — — Goodwill at December 31, 2018 87 87 Impairments — — Goodwill at December 31, 2019 87 87 Impairments (87) (87) Goodwill at December 31, 2020 $ — $ —

CAPITALIZED EXPLORATORY WELL _2

CAPITALIZED EXPLORATORY WELL COSTS (Tables)	12 Months Ended
	Dec. 31, 2020
Extractive Industries [Abstract]
Capitalized Exploratory Well Costs, Roll Forward	The following summarizes the changes in capitalized exploratory well costs for the years ended December 31, 2020, 2019, and 2018. 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, 2020 2019 2018 (In millions) Capitalized well costs at beginning of year $ 141 $ 159 $ 350 Additions pending determination of proved reserves 226 286 602 Divestitures and other (38) (100) (82) Reclassifications to proved properties (56) (179) (647) Charged to exploration expense (76) (25) (64) Capitalized well costs at end of year $ 197 $ 141 $ 159
Schedule of Aging of Capitalized Exploratory Well Costs	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: 2020 2019 2018 (In millions) Exploratory well costs capitalized for a period of one year or less $ 184 $ 108 $ 126 Exploratory well costs capitalized for a period greater than one year 13 33 33 Capitalized well costs at end of year $ 197 $ 141 $ 159 Number of projects with exploratory well costs capitalized for a period greater than one year 5 2 2
Schedule of Projects with Exploratory Well Costs Capitalized for More than One Year	The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2020, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed: Total 2019 2018 2017 and Prior (In millions) Egypt $ 13 $ 4 $ 9 $ — $ 13 $ 4 $ 9 $ —

DERIVATIVE INSTRUMENTS AND HE_2

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	As of December 31, 2020, the Company had the following open natural gas financial basis swap contracts: Basis Swap Purchased Basis Swap Sold Production Period Settlement Index MMBtu Weighted Average Price Differential MMBtu Weighted Average Price Differential April—December 2021 NYMEX Henry Hub/IF Waha 37,580 $(0.43) — — April—December 2021 NYMEX Henry Hub/IF HSC — — 37,580 $(0.07) January—December 2022 NYMEX Henry Hub/IF Waha 43,800 $(0.45) — — January—December 2022 NYMEX Henry Hub/IF HSC — — 43,800 $(0.08)
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 Total Fair Value Netting (1) Carrying Amount (In millions) December 31, 2020 Assets: Commodity derivative instruments $ — $ 11 $ — $ 11 $ — $ 11 Liabilities: Pipeline capacity embedded derivatives — 53 — 53 — 53 Preferred Units embedded derivative — — 139 139 — 139 December 31, 2019 Assets: Pipeline capacity embedded derivative $ — $ 8 $ — $ 8 $ — $ 8 Foreign currency derivative instruments — 1 — 1 — 1 Liabilities: Preferred Units embedded derivative — — 103 103 — 103 (1) The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.
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 Total Fair Value Netting (1) Carrying Amount (In millions) December 31, 2020 Assets: Commodity derivative instruments $ — $ 11 $ — $ 11 $ — $ 11 Liabilities: Pipeline capacity embedded derivatives — 53 — 53 — 53 Preferred Units embedded derivative — — 139 139 — 139 December 31, 2019 Assets: Pipeline capacity embedded derivative $ — $ 8 $ — $ 8 $ — $ 8 Foreign currency derivative instruments — 1 — 1 — 1 Liabilities: Preferred Units embedded derivative — — 103 103 — 103 (1) The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.
Schedule of Fair Value Measurement Inputs	As of the December 31, 2020 valuation date, the Company used the forward B-rated Energy Bond Yield curve to develop the following key unobservable inputs used to value this embedded derivative: Quantitative Information About Level 3 Fair Value Measurements Fair Value at December 31, 2020 Valuation Technique Significant Unobservable Inputs Range/Value (In millions) Preferred Units embedded derivative $ 139 Option Model Altus’ Imputed Interest Rate 7.32-11.73% Interest Rate Volatility 37.08%
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: 2020 2019 (In millions) Current Assets: Other current assets $ 6 $ 2 Noncurrent Assets: Deferred charges and other 5 7 Total derivative assets $ 11 $ 9 Deferred Credits and Other Noncurrent Liabilities: Other $ 192 $ 103 Total derivative liabilities $ 192 $ 103 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, 2020 2019 2018 (In millions) Realized: Commodity derivative instruments $ (135) $ 27 $ (81) Amortization of put premium, realized loss — — (39) Foreign currency derivative instruments (1) — — Treasury-lock — (18) — Realized gain (loss), net (136) 9 (120) Unrealized: Commodity derivative instruments 11 (44) 103 Pipeline capacity embedded derivatives (61) 8 — Foreign currency derivative instruments (1) 1 — Preferred Units embedded derivative (36) (9) — Unrealized gain (loss), net (87) (44) 103 Derivative instrument losses, net $ (223) $ (35) $ (17)

OTHER CURRENT ASSETS (Tables)

OTHER CURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2020
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: 2020 2019 (In millions) Inventories $ 492 $ 502 Drilling advances 113 92 Prepaid assets and other 71 58 Total Other current assets $ 676 $ 652

EQUITY METHOD INTERESTS (Tables

EQUITY METHOD INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2020
Equity Method Investments and Joint Ventures [Abstract]
Summary of Equity Method Investment Information	Interest 2020 2019 (In millions) Gulf Coast Express Pipeline LLC 16.0 % $ 284 $ 291 EPIC Crude Holdings, LP 15.0 % 176 163 Permian Highway Pipeline LLC 26.7 % 615 311 Shin Oak Pipeline (Breviloba, LLC) 33.0 % 480 493 Total Altus equity method interests $ 1,555 $ 1,258 The following table presents the activity in Altus’ equity method interests for the years ended December 31, 2020 and 2019: Gulf Coast Express Pipeline LLC EPIC Crude Holdings, LP Permian Highway Pipeline LLC Breviloba, LLC Total (In millions) Balance at December 31, 2018 $ 91 $ — $ — $ — $ 91 Acquisitions 15 52 162 442 671 Capital contributions 184 123 147 47 501 Distributions (16) (9) (25) Capitalized interest (1) — — 2 — 2 Equity income (loss), net 17 (11) — 13 19 Accumulated other comprehensive loss — (1) — — (1) Balance at December 31, 2019 291 163 311 493 1,258 Capital contributions 2 29 296 — 327 Distributions (51) — — (46) (97) Capitalized interest (1) — — 8 — 8 Equity income (loss), net 42 (16) — 33 59 Balance at December 31, 2020 $ 284 $ 176 $ 615 $ 480 $ 1,555 (1) Altus’ proportionate share of the PHP construction costs is funded with Altus’ revolving credit facility. Accordingly, Altus capitalized $8 million and $2 million of related interest expense during 2020 and 2019, respectively, which are included in the basis of the PHP equity interest. The following presents summarized information of combined statement of operations for Altus’ equity method interests (on a 100 percent basis): For the Year Ended December 31, 2020 2019 (1) 2018 (2) (In millions) Operating revenues $ 707 $ 302 $ 3 Operating income (loss) 331 121 (6) Net income (loss) 256 120 (6) Other comprehensive loss 3 (8) — (1) Although Altus’ interests in EPIC Crude Holdings, LP, Permian Highway Pipeline LLC, and Breviloba, LLC were acquired in March, May, and July 2019, respectively, the combined financial results are presented for the year ended December 31, 2019 for comparability. (2) Although Altus’ interest in Gulf Coast Express Pipeline LLC was acquired in December 2018, the combined financial results are presented for the year ended December 31, 2018 for comparability. The following presents summarized combined balance sheet information for Altus’ equity method interests (on a 100 percent basis) as of December 31: 2020 2019 (In millions) Current assets $ 260 $ 441 Noncurrent assets 7,678 6,435 Total assets $ 7,938 $ 6,876 Current liabilities $ 206 $ 478 Noncurrent liabilities 1,191 958 Equity 6,541 5,440 Total liabilities and equity $ 7,938 $ 6,876

OTHER CURRENT LIABILITIES (Tabl

OTHER CURRENT LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2020
Payables and Accruals [Abstract]
Detail of Other Current Liabilities	The following table provides detail of the Company’s other current liabilities as of December 31: 2020 2019 (In millions) Accrued operating expenses $ 91 $ 143 Accrued exploration and development 167 319 Accrued gathering, processing, and transmission - Altus — 17 Accrued compensation and benefits 170 212 Accrued interest 140 135 Accrued income taxes 25 51 Current asset retirement obligation 56 47 Current operating lease liability 116 169 Other 97 56 Total Other current liabilities $ 862 $ 1,149

ASSET RETIREMENT OBLIGATION (Ta

ASSET RETIREMENT OBLIGATION (Tables)	12 Months Ended
	Dec. 31, 2020
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 Year Ended December 31, 2020 2019 (In millions) Asset retirement obligation at beginning of year $ 1,858 $ 1,932 Liabilities incurred 10 41 Liabilities divested (26) (56) Liabilities settled (30) (56) Accretion expense 109 107 Revisions in estimated liabilities 23 (110) Asset retirement obligation at end of year 1,944 1,858 Less current portion (56) (47) Asset retirement obligation, long-term $ 1,888 $ 1,811

DEBT AND FINANCING COSTS (Table

DEBT AND FINANCING COSTS (Tables)	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Schedule of Debt	The following table presents the carrying value of the Company’s debt: December 31, 2020 2019 (In millions) 3.625% notes due 2021 (1) $ — $ 293 3.25% notes due 2022 (2) 213 463 2.625% notes due 2023 (2) 123 181 4.625% notes due 2025 (2) 500 — 7.7% notes due 2026 79 79 7.95% notes due 2026 133 133 4.875% due 2027 (2) 750 — 4.375% notes due 2028 (2) 993 1,000 7.75% notes due 2029 (2)(3) 235 247 4.25% notes due 2030 (2) 580 600 6.0% notes due 2037 (2) 443 467 5.1% notes due 2040 (2) 1,333 1,499 5.25% notes due 2042 (2) 399 500 4.75% notes due 2043 (2) 1,133 1,413 4.25% notes due 2044 (2) 559 753 7.375% debentures due 2047 150 150 5.35% notes due 2049 (2) 390 400 7.625% debentures due 2096 39 39 Notes and debentures before unamortized discount and debt issuance costs (4) 8,052 8,217 Commercial paper — — Altus credit facility (5) 624 396 Apache credit facility (5) 150 — Finance lease obligations 38 48 Unamortized discount (35) (42) Debt issuance costs (57) (53) Total debt 8,772 8,566 Current maturities (2) (11) Long-term debt $ 8,770 $ 8,555 (1) On November 3, 2020, Apache redeemed the 3.625% senior notes due February 1, 2021, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. (2) 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. (3) Assumed by Apache in August 2017 as permitted by terms of these notes originally issued by a subsidiary and guaranteed by Apache. (4) The fair values of the Company’s notes and debentures were $8.5 billion and $8.4 billion as of December 31, 2020 and 2019, respectively. Apache 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). (5) The carrying amount of borrowings on credit facilities approximates fair value because the interest rates are variable and reflective of market rates.
Schedule of Long Term Debt by Maturity	Maturities for the Company’s notes and debentures excluding discount and debt issuance costs as of December 31, 2020 are as follows: (In millions) 2021 $ — 2022 213 2023 123 2024 — 2025 500 Thereafter 7,216 Notes and debentures, excluding discounts and debt issuance costs $ 8,052
Components of Financing Costs, Net	The following table presents the components of Apache’s financing costs, net: For the Year Ended December 31, 2020 2019 2018 (In millions) Interest expense $ 438 $ 430 $ 441 Amortization of debt issuance costs 8 7 9 Capitalized interest (12) (37) (44) Loss (gain) on extinguishment of debt (160) 75 94 Interest income (7) (13) (22) Financing costs, net $ 267 $ 462 $ 478

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income (Loss) Before Income Taxes	Income (loss) before income taxes is composed of the following: For the Year Ended December 31, 2020 2019 2018 (In millions) U.S. $ (4,581) $ (4,397) $ (723) Foreign (259) 1,389 1,681 Total $ (4,840) $ (3,008) $ 958
Total Provision for Income Taxes	The total income tax provision consists of the following: For the Year Ended December 31, 2020 2019 2018 (In millions) Current income taxes: Federal $ (2) $ 1 $ (1) State — — — Foreign 178 659 895 176 660 894 Deferred income taxes: Federal — 67 (65) State — — 2 Foreign (112) (53) (159) (112) 14 (222) Total $ 64 $ 674 $ 672
Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense	A reconciliation of the tax on the Company’s income (loss) before income taxes and total tax expense is shown below: For the Year Ended December 31, 2020 2019 2018 (In millions) Income tax expense (benefit) at U.S. statutory rate $ (1,016) $ (631) $ 201 State income tax, less federal effect (1) — 1 2 Taxes related to foreign operations 97 328 436 Tax credits (13) (6) (13) Tax on deemed repatriation of foreign earnings — — 103 Foreign tax credits — — (336) Change in U.S. tax rate — — 161 Net change in tax contingencies 1 1 (2) Goodwill impairment 35 — — Sale of North Sea assets — — (30) Valuation allowances (1) 965 972 118 All other, net (5) 9 32 $ 64 $ 674 $ 672 (1) The change in state valuation allowance is included as a component of state income tax.
Net Deferred Tax Liability	The net deferred income tax liability consists of the following as of December 31: 2020 2019 (In millions) Deferred tax assets: U.S. and state net operating losses $ 2,306 $ 2,108 Capital losses 633 626 Tax credits and other tax incentives 33 32 Foreign tax credits 2,241 2,241 Accrued expenses and liabilities 93 97 Asset retirement obligation 654 618 Property & equipment 261 — Investment in Altus Midstream LP 76 107 Net interest expense limitation 252 162 Lease liability 79 108 Other 1 88 Total deferred tax assets 6,629 6,187 Valuation allowance (5,991) (4,959) Net deferred tax assets 638 1,228 Deferred tax liabilities: Deferred income — 1 Equity investments 4 — Property and equipment 750 1,432 Right-of-use asset 74 106 Other 13 6 Total deferred tax liabilities 841 1,545 Net deferred income tax liability $ 203 $ 317 Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows: 2020 2019 (In millions) Assets: Deferred charges and other $ 12 $ 29 Liabilities: Income taxes 215 346 Net deferred income tax liability $ 203 $ 317
Summary of Valuation Allowance Against Certain Foreign Net Deferred Tax Assets and State Net Operating Losses	In 2020, 2019, and 2018, the Company’s valuation allowance increased by $1.0 billion, $1.0 billion, and $131 million, respectively, as detailed in the table below: 2020 2019 2018 (In millions) Balance at beginning of year $ 4,959 $ 3,947 $ 3,816 State (1) 67 41 15 U.S. 960 971 124 Foreign 5 — (8) Balance at end of year $ 5,991 $ 4,959 $ 3,947 (1) Reported as a component of state income taxes.
Net Operating Losses	On December 31, 2020, the Company had net operating losses as follows: Amount Expiration (In millions) U.S. $ 8,859 2020 - Indefinite State 6,566 Various
Schedule of Foreign Tax Credit Carryforward	On December 31, 2020, the Company had foreign tax credits as follows: Amount Expiration (In millions) Foreign tax credits $ 2,241 2025-2026
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: 2020 2019 2018 (In millions) Balance at beginning of year $ 82 $ 24 $ 26 Additions based on tax positions related to prior year — 49 — Additions based on tax positions related to the current year 11 9 — Reductions for tax positions of prior years — — (2) Balance at end of year $ 93 $ 82 $ 24
Key Jurisdictions of Company's Earliest Open Tax Years	Apache’s earliest open tax years in its key jurisdictions are as follows: Jurisdiction U.S. 2014 Egypt 2005 U.K. 2019

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Lease Cost	The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2020: Operating Leases Finance Leases Weighted average remaining lease term 3.7 years 12.7 years Weighted average discount rate 4.2 % 4.4 %
Operating Lease, Liability, Maturity	At December 31, 2020, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows: Net Minimum Commitments (1) Operating Leases (2) Finance Leases (3) Purchase Obligations (4) (In millions) 2021 $ 120 $ 3 $ 236 2022 70 3 203 2023 33 3 203 2024 27 4 160 2025 7 4 159 Thereafter 25 29 600 Total future minimum payments 282 46 $ 1,561 Less: imputed interest (21) (8) N/A Total lease liabilities 261 38 N/A Current portion 116 2 N/A Non-current portion $ 145 $ 36 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 agreement 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 $120 million, $111 million, and $132 million in 2020, 2019, and 2018, respectively.
Finance Lease, Liability, Maturity	At December 31, 2020, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows: Net Minimum Commitments (1) Operating Leases (2) Finance Leases (3) Purchase Obligations (4) (In millions) 2021 $ 120 $ 3 $ 236 2022 70 3 203 2023 33 3 203 2024 27 4 160 2025 7 4 159 Thereafter 25 29 600 Total future minimum payments 282 46 $ 1,561 Less: imputed interest (21) (8) N/A Total lease liabilities 261 38 N/A Current portion 116 2 N/A Non-current portion $ 145 $ 36 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 agreement 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 $120 million, $111 million, and $132 million in 2020, 2019, and 2018, respectively.
Long-term Purchase Commitment	At December 31, 2020, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows: Net Minimum Commitments (1) Operating Leases (2) Finance Leases (3) Purchase Obligations (4) (In millions) 2021 $ 120 $ 3 $ 236 2022 70 3 203 2023 33 3 203 2024 27 4 160 2025 7 4 159 Thereafter 25 29 600 Total future minimum payments 282 46 $ 1,561 Less: imputed interest (21) (8) N/A Total lease liabilities 261 38 N/A Current portion 116 2 N/A Non-current portion $ 145 $ 36 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 agreement 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 $120 million, $111 million, and $132 million in 2020, 2019, and 2018, respectively.
Schedule of Future Minimum Lease Payments for Capital Leases	As a result of electing the transitional practical expedient to apply the provisions of the standard at its adoption date instead of the earliest comparative period presented, below are the required ASU Leases (Topic 840) disclosures for prior periods: Operating Leases (1) Finance Leases (2) (In millions) Year ended December 31, 2018 2019 $ 61 $ 1 2020-2021 64 3 2022-2023 53 4 2024 & Beyond 42 32 Total $ 220 $ 40 (1) Includes leases for buildings, facilities, and related equipment with varying expiration dates through 2042. Total rent expense, net of amounts capitalized and sublease income was $76 million in 2018. (2) This represents the Company’s capital lease obligation related to its Midland, Texas office building. The imputed interest rate necessary to reduce the net minimum lease payments to present value of the lease term is 4.4 percent, or $16 million as of December 31, 2018.
Schedule of Future Minimum Leases Payments for Operating Leases	As a result of electing the transitional practical expedient to apply the provisions of the standard at its adoption date instead of the earliest comparative period presented, below are the required ASU Leases (Topic 840) disclosures for prior periods: Operating Leases (1) Finance Leases (2) (In millions) Year ended December 31, 2018 2019 $ 61 $ 1 2020-2021 64 3 2022-2023 53 4 2024 & Beyond 42 32 Total $ 220 $ 40 (1) Includes leases for buildings, facilities, and related equipment with varying expiration dates through 2042. Total rent expense, net of amounts capitalized and sublease income was $76 million in 2018. (2) This represents the Company’s capital lease obligation related to its Midland, Texas office building. The imputed interest rate necessary to reduce the net minimum lease payments to present value of the lease term is 4.4 percent, or $16 million as of December 31, 2018.

RETIREMENT AND DEFERRED COMPE_2

RETIREMENT AND DEFERRED COMPENSATION PLANS (Tables)	12 Months Ended
	Dec. 31, 2020
Retirement Benefits [Abstract]
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, 2020, 2019, and 2018, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. Apache uses a measurement date of December 31 for its pension and postretirement benefit plans. 2020 2019 2018 Pension Postretirement Pension Postretirement Pension Postretirement (In millions) Change in Projected Benefit Obligation Projected benefit obligation at beginning of year $ 199 $ 20 $ 187 $ 27 $ 216 $ 27 Service cost 3 1 3 2 4 2 Interest cost 4 — 5 1 5 1 Foreign currency exchange rates 8 — 7 — (11) — Actuarial losses (gains) 30 1 15 (9) (11) (2) Plan settlements — — (14) — (11) — Benefits paid (11) (4) (4) (2) (5) (3) Retiree contributions — 2 — 1 — 2 Projected benefit obligation at end of year 233 20 199 20 187 27 Change in Plan Assets Fair value of plan assets at beginning of year 228 — 208 — 238 — Actual return on plan assets 31 — 25 — (6) — Foreign currency exchange rates 9 — 8 — (13) — Employer contributions 5 2 5 1 5 2 Plan settlements — — (14) — (11) — Benefits paid (11) (4) (4) (2) (5) (4) Retiree contributions — 2 — 1 — 2 Fair value of plan assets at end of year 262 — 228 — 208 — Funded status at end of year $ 29 $ (20) $ 29 $ (20) $ 21 $ (27) Amounts recognized in Consolidated Balance Sheet Current liability $ — $ (2) $ — $ (2) $ — $ (2) Non-current asset (liability) 29 (18) 29 (18) 21 (25) $ 29 $ (20) $ 29 $ (20) $ 21 $ (27) Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss) Accumulated gain (loss) $ (11) $ 16 $ (7) $ 19 $ (13) $ 10 Weighted Average Assumptions used as of December 31 Discount rate 1.40 % 2.06 % 2.10 % 3.00 % 2.90 % 4.13 % Salary increases 4.50 % N/A 4.30 % N/A 4.70 % N/A Expected return on assets 2.20 % N/A 2.20 % N/A 2.80 % N/A Healthcare cost trend Initial N/A 6.00 % N/A 6.25 % N/A 6.50 % Ultimate in 2025 N/A 5.00 % N/A 5.00 % N/A 5.00 %
Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset	A breakout of previous allocations for plan asset holdings and the target allocation for the Company’s plan assets are summarized below: Target Percentage of 2020 2020 2019 Asset Category Equity securities: Overseas quoted equities 19 % 19 % 23 % Total equity securities 19 % 19 % 23 % Debt securities: U.K. government bonds 65 % 64 % 62 % U.K. corporate bonds 16 % 16 % 15 % Total debt securities 81 % 80 % 77 % Cash — 1 % — Total 100 % 100 % 100 %
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, 2020 and 2019: December 31, 2020 2019 (In millions) Equity securities: Overseas quoted equities $ 49 $ 52 Total equity securities 49 52 Debt securities: U.K. government bonds 168 140 U.K. corporate bonds 43 35 Total debt securities 211 175 Cash 2 1 Fair value of plan assets $ 262 $ 228
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, 2020, 2019, and 2018: 2020 2019 2018 Pension Postretirement Pension Postretirement Pension Postretirement (In millions) Components of Net Periodic Benefit Cost Service cost $ 3 $ 1 $ 3 $ 2 $ 4 $ 2 Interest cost 4 — 5 1 5 1 Expected return on assets (5) — (5) — (7) — Amortization of gain — (1) — (1) — — Settlement loss — — — — 1 — Net periodic benefit cost $ 2 $ — $ 3 $ 2 $ 3 $ 3 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31 Discount rate 2.10 % 3.00 % 2.90 % 4.13 % 2.60 % 3.44 % Salary increases 4.30 % N/A 4.70 % N/A 4.70 % N/A Expected return on assets 2.20 % N/A 2.80 % N/A 2.90 % N/A Healthcare cost trend Initial N/A 6.25 % N/A 6.50 % N/A 6.75 % Ultimate in 2025 N/A 5.00 % N/A 5.00 % N/A 5.00 %
Expected Future Benefit Payment	The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: Pension Postretirement (In millions) 2021 $ 5 $ 2 2022 6 2 2023 7 2 2024 6 2 2025 6 2 Years 2026-2030 36 6

REDEMABLE NONCONTROLLING INTE_2

REDEMABLE NONCONTROLLING INTEREST - ALTUS (Tables)	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
Schedule of Preferred Units	The net transaction price was allocated to the preferred redeemable noncontrolling interest and the embedded features according to the associated initial fair value measurements as follows: June 12, 2019 (In millions) Redeemable noncontrolling interest - Altus Preferred Unit limited partners $ 517 Preferred Units embedded derivative 94 $ 611 Activity related to the Preferred Units for the years ended December 31, 2020 and 2019 is as follows: Units Outstanding Financial Position (1) (In millions, except unit data) Redeemable noncontrolling interest — Preferred Units: at December 31, 2018 — $ — Issuance of Preferred Units, net 625,000 517 Distribution of in-kind additional Preferred Units 13,163 — Allocation of Altus Midstream net income N/A 38 Redeemable noncontrolling interest - Altus Preferred Unit limited partners: at December 31, 2019 638,163 555 Distribution of in-kind additional Preferred Units 22,531 — Cash distributions to Altus Preferred Unit limited partners — (23) Allocation of Altus Midstream LP net income N/A 76 Redeemable noncontrolling interest - Altus Preferred Unit limited partners: at December 31, 2020 660,694 608 Preferred Units embedded derivative 139 $ 747 (1) The Preferred Units are redeemable at Altus Midstream’s option at a redemption price (the Redemption Price), which as of December 31, 2020 was the greater of (i) an 11.5 percent internal rate of return and (ii) a 1.3 times multiple of invested capital. As of December 31, 2020, the Redemption Price would have been based on 1.3 times multiple of invested capital, which was $813 million and greater than using an 11.5 percent internal rate of return, which was $717 million. N/A - not applicable.

CAPITAL STOCK (Tables)

CAPITAL STOCK (Tables)	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
Common Stock Outstanding	The following table provides changes to the Company’s common shares outstanding for the years ended December 31, 2020, 2019, and 2018: For the Year Ended December 31, 2020 2019 2018 Balance, beginning of year 376,062,670 374,696,222 380,954,864 Shares issued for stock-based compensation plans: Treasury shares issued 17,448 31,701 2,454 Common shares issued 1,402,512 1,334,747 1,566,237 Treasury shares acquired — — (7,827,333) Balance, end of year 377,482,630 376,062,670 374,696,222
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 (loss) per common share for the years ended December 31, 2020, 2019, and 2018: 2020 2019 2018 Loss Shares Per Share Loss Shares Per Share Income Shares Per Share (In millions, except per share amounts) Basic: Income (loss) attributable to common stock $ (4,860) 378 $ (12.86) $ (3,553) 377 $ (9.43) $ 40 382 $ 0.11 Effect of Dilutive Securities: Stock options and other $ — — $ — $ — — $ — $ — 2 $ — Diluted: Income (loss) attributable to common stock $ (4,860) 378 $ (12.86) $ (3,553) 377 $ (9.43) $ 40 384 $ 0.11
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 Year Ended December 31, 2020 2019 2018 (In millions) Stock-settled and cash-settled compensation expensed $ 40 $ 110 $ 157 Stock-settled and cash-settled compensation capitalized 7 28 37 Total stock-settled and cash-settled compensation costs $ 47 $ 138 $ 194
Summary of Stock Options Activities	The following table summarizes stock option activity for the years ended December 31, 2020, 2019, and 2018: 2020 2019 2018 Shares Weighted Average Shares Weighted Average Shares Weighted Average (In thousands, except exercise price amounts) Outstanding, beginning of year 4,298 $ 75.24 4,872 $ 75.95 4,593 $ 83.36 Granted — — — — 812 45.93 Exercised — — — — (29) 41.79 Forfeited (37) 44.98 (80) 34.58 (121) 74.58 Expired (724) 92.14 (494) 88.82 (383) 104.21 Outstanding, end of year (1) 3,537 72.10 4,298 75.24 4,872 75.95 Expected to vest (2) 150 45.77 495 49.11 1,274 48.74 Exercisable, end of year (3) 3,387 73.26 3,803 78.64 3,598 85.59 (1) As of December 31, 2020, options outstanding had a weighted average remaining contractual life of 3.6 years and no intrinsic value. (2) As of December 31, 2020, options expected to vest had a weighted average remaining contractual life of 7.0 years and no intrinsic value. (3) As of December 31, 2020, options exercisable had a weighted average remaining contractual life of 3.4 years and no intrinsic value.
Schedule of Assumptions Used	The following table summarizes specific assumptions used in the Company’s valuation: 2020 2019 2018 Expected volatility N/A N/A 33.74% Expected dividend yields N/A N/A 2.16% Expected term (in years) N/A N/A 6 Risk-free rate N/A N/A 2.42% Weighted-average grant-date fair value N/A N/A $ 13.15 N/A - not applicable.
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, 2020, 2019, and 2018: 2020 2019 2018 Units Weighted Units Weighted Units Weighted (In thousands, except per share amounts) Non-vested, beginning of year 2,448 $ 46.65 3,153 $ 55.54 4,920 $ 56.67 Granted 1,352 24.60 1,479 36.81 608 45.59 Vested (3) (1,933) 48.65 (1,899) 53.99 (2,023) 55.10 Forfeited (315) 30.09 (285) 45.06 (352) 56.69 Non-vested, end of year (1)(2) 1,552 28.43 2,448 46.65 3,153 55.54 (1) As of December 31, 2020, there was $14 million of total unrecognized compensation cost related to 1,551,807 unvested stock-settled restricted stock units. (2) As of December 31, 2020, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.7 years. (3) The grant date fair values of the stock-settled awards vested during 2020, 2019, and 2018 were approximately $94 million, $103 million, and $111 million, respectively. The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2020, 2019, and 2018: For the Year Ended December 31, 2020 2019 2018 (In thousands) Non-vested, beginning of year 5,384 1,818 59 Adjustment for ALTM reverse stock split (1) (1,246) — — Granted (2) 3,462 4,831 1,973 Vested (1,618) (616) (38) Forfeited (1,559) (649) (176) Non-vested, end of year (3) 4,423 5,384 1,818 (1) On June 30, 2020, Altus executed a 1-for-20 reverse stock split of its outstanding common stock. Outstanding cash-settled awards are based on the per-share market price of ALTM stock. (2) Restricted stock phantom units granted during 2020 and 2019 included 3,378,486 and 3,401,477 awards, respectively, based on the per-share market price of Apache common stock and 83,239 and 1,429,135 awards, respectively, based on the per-share market price of ALTM common stock. The restricted stock phantom units granted during 2020 based on ALTM’s per-share market price reflect the 1-for-20 reverse stock split described above. (3) The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2020 was approximately $28 million. The following table summarizes stock-settled conditional restricted stock unit activity for the year ended December 31, 2020: Units Weighted Average Grant- Date Fair Value (1) (In thousands) Non-vested, beginning of year 781 $ 52.69 Granted 18 62.31 Vested (445) 41.10 Forfeited (16) 56.66 Expired (227) 70.70 Non-vested, end of year (2)(3) 111 63.15 (1) The fair value of each conditional restricted stock unit award is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a three-year continuous risk-free interest rate; (ii) a constant volatility assumption based on the historical realized stock price volatility of the Company and the designated peer group; and (iii) the historical stock prices and expected dividends of the common stock of the Company and its designated peer group. (2) As of December 31, 2020, there was no unrecognized compensation cost related to 111,126 unvested stock-settled conditional restricted stock units. (3) As of December 31, 2020, the weighted-average remaining life of the unvested stock-settled conditional restricted stock units is approximately 0.0 years. The following table summarizes cash-settled conditional restricted stock unit activity for the year ended December 31, 2020: Units (In thousands) Non-vested, beginning of year 2,320 Granted 1,687 Vested (2) Forfeited (542) Expired (46) Non-vested, end of year (1) 3,417 (1) As of December 31, 2020, the outstanding liability for the unvested cash-settled conditional restricted stock units that had not been recognized was approximately $14 million.

ACCUMULATED OTHER COMPREHENSI_2

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
Components of Accumulated Other Comprehensive Income (Loss)	Components of accumulated other comprehensive income (loss) include the following: As of December 31, 2020 2019 2018 (In millions) Share of equity method interests other comprehensive loss $ (1) $ (1) $ — Pension and postretirement benefit plan ( Note 12 ) 15 17 4 Accumulated other comprehensive income $ 14 $ 16 $ 4

BUSINESS SEGMENT INFORMATION (T

BUSINESS SEGMENT INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2020
Segment Reporting [Abstract]
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) 2020 Oil revenues $ 1,102 $ 795 $ 1,209 $ — $ — $ 3,106 Natural gas revenues 280 67 251 — — 598 Natural gas liquids revenues 8 21 304 — — 333 Oil, natural gas, and natural gas liquids production revenues 1,390 883 1,764 — — 4,037 Purchased oil and gas sales — — 394 4 — 398 Midstream service affiliate revenues — — — 145 (145) — 1,390 883 2,158 149 (145) 4,435 Operating Expenses: Lease operating expenses 424 305 400 — (2) 1,127 Gathering, processing, and transmission 38 50 291 38 (143) 274 Purchased oil and gas costs — — 354 3 — 357 Taxes other than income — — 108 15 — 123 Exploration 63 28 168 — 15 274 Depreciation, depletion, and amortization 601 380 779 12 — 1,772 Asset retirement obligation accretion — 73 32 4 — 109 Impairments 529 7 3,963 2 — 4,501 1,655 843 6,095 74 (130) 8,537 Operating Income (Loss) $ (265) $ 40 $ (3,937) $ 75 $ (15) (4,102) Other Income (Expense): Gain on divestitures, net 32 Derivative instrument losses, net (223) Other 64 General and administrative (290) Transaction, reorganization, and separation (54) Financing costs, net (267) Loss Before Income Taxes $ (4,840) Total Assets (3) $ 3,003 $ 2,220 $ 5,540 $ 1,786 $ 197 $ 12,746 Net Property and Equipment $ 1,955 $ 1,773 $ 4,760 $ 196 $ 135 $ 8,819 Additions to Net Property and Equipment $ 454 $ 215 $ 345 $ 12 $ 136 $ 1,162 Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2019 Oil revenues $ 1,969 $ 1,163 $ 2,098 $ — $ — $ 5,230 Natural gas revenues 295 90 293 — — 678 Natural gas liquids revenues 12 23 372 — — 407 Oil, natural gas, and natural gas liquids production revenues 2,276 1,276 2,763 — — 6,315 Purchased oil and gas sales — — 176 — — 176 Midstream service affiliate revenues — — — 136 (136) — 2,276 1,276 2,939 136 (136) 6,491 Operating Expenses: Lease operating expenses 484 320 645 — (2) 1,447 Gathering, processing, and transmission 40 45 299 56 (134) 306 Purchased oil and gas costs — — 142 — — 142 Taxes other than income — — 194 13 — 207 Exploration 100 2 688 — 15 805 Depreciation, depletion, and amortization 708 366 1,566 40 — 2,680 Asset retirement obligation accretion — 76 29 2 — 107 Impairments — — 1,648 1,301 — 2,949 1,332 809 5,211 1,412 (121) 8,643 Operating Income (Loss) $ 944 $ 467 $ (2,272) $ (1,276) $ (15) (2,152) Other Income (Expense): Gain on divestitures, net 43 Derivative instrument losses, net (35) Other 54 General and administrative (406) Transaction, reorganization, and separation (50) Financing costs, net (462) Loss Before Income Taxes $ (3,008) Total Assets (3) $ 3,700 $ 2,473 $ 10,388 $ 1,479 $ 67 $ 18,107 Net Property and Equipment $ 2,573 $ 1,956 $ 9,385 $ 206 $ 38 $ 14,158 Additions to Net Property and Equipment $ 454 $ 183 $ 1,696 $ 308 $ 93 $ 2,734 Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2018 Oil revenues $ 2,396 $ 1,179 $ 2,271 $ — $ — $ 5,846 Natural gas revenues 339 122 458 — — 919 Natural gas liquids revenues 13 20 550 — — 583 Oil, natural gas, and natural gas liquids production revenues 2,748 1,321 3,279 — — 7,348 Purchased oil and gas sales — — 357 — — 357 Midstream service affiliate revenues — — — 77 (77) — 2,748 1,321 3,636 77 (77) 7,705 Operating Expenses: Lease operating expenses 428 341 670 — — 1,439 Gathering, processing, and transmission 47 42 282 54 (77) 348 Purchased oil and gas costs — — 340 — — 340 Taxes other than income — — 207 8 — 215 Exploration 88 192 219 — 4 503 Depreciation, depletion, and amortization 745 375 1,266 19 — 2,405 Asset retirement obligation accretion — 75 32 1 — 108 Impairments 63 10 438 — — 511 1,371 1,035 3,454 82 (73) 5,869 Operating Income (Loss) $ 1,377 $ 286 $ 182 $ (5) $ (4) 1,836 Other Income (Expense): Gain on divestitures, net 23 Derivative instrument losses, net (17) Other 53 General and administrative (431) Transaction, reorganization, and separation (28) Financing costs, net (478) Income Before Income Taxes $ 958 Total Assets (3) $ 4,260 $ 2,456 $ 12,962 $ 1,857 $ 47 $ 21,582 Net Property and Equipment $ 2,856 $ 2,148 $ 12,145 $ 1,227 $ 45 $ 18,421 Additions to Net Property and Equipment $ 594 $ 223 $ 2,544 $ 545 $ 8 $ 3,914 (1) Includes revenue from non-customers for the years ended December 31, 2020, 2019, and 2018 of: For the Year Ended December 31, 2020 2019 2018 (In millions) Oil $ 95 $ 410 $ 592 Natural gas 14 40 58 Natural gas liquids — 1 2 (2) Includes a noncontrolling interest in Egypt and Altus Midstream. (3) Intercompany balances are excluded from total assets.

SUPPLEMENTAL OIL AND GAS DISC_2

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2020
Extractive Industries [Abstract]
Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities	The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities. Apache has no long-term agreements to purchase oil or gas production from foreign governments or authorities. United Egypt (1) North Sea Other Total (1) (In millions, except per boe) 2020 Oil and gas production revenues $ 1,764 $ 1,390 $ 883 $ — $ 4,037 Operating cost: Depreciation, depletion, and amortization (2) 726 540 377 — 1,643 Asset retirement obligation accretion 32 — 73 — 105 Lease operating expenses 400 424 305 — 1,129 Gathering, processing, and transmission 291 38 50 — 379 Exploration expenses 168 63 28 15 274 Impairments related to oil and gas properties 3,938 374 7 — 4,319 Production taxes (3) 106 — — — 106 Income tax (818) (22) 17 — (823) 4,843 1,417 857 15 7,132 Results of operations $ (3,079) $ (27) $ 26 $ (15) $ (3,095) 2019 Oil and gas production revenues $ 2,763 $ 2,276 $ 1,276 $ — $ 6,315 Operating cost: Depreciation, depletion, and amortization (2) 1,508 641 363 — 2,512 Asset retirement obligation accretion 29 — 76 — 105 Lease operating expenses 645 484 320 — 1,449 Gathering, processing, and transmission 299 40 45 — 384 Exploration expenses 688 100 2 15 805 Impairments related to oil and gas properties 1,633 — — — 1,633 Production taxes (3) 191 — — — 191 Income tax (468) 455 188 — 175 4,525 1,720 994 15 7,254 Results of operations $ (1,762) $ 556 $ 282 $ (15) $ (939) 2018 Oil and gas production revenues $ 3,279 $ 2,748 $ 1,321 $ — $ 7,348 Operating cost: Depreciation, depletion, and amortization (2) 1,206 688 371 — 2,265 Asset retirement obligation accretion 32 — 75 — 107 Lease operating expenses 670 428 341 — 1,439 Gathering, processing, and transmission 282 47 42 — 371 Exploration expenses 219 88 192 4 503 Impairments related to oil and gas properties 265 63 10 — 338 Production taxes (3) 203 — — — 203 Income tax 87 645 116 — 848 2,964 1,959 1,147 4 6,074 Results of operations $ 315 $ 789 $ 174 $ (4) $ 1,274 (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	Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities United Egypt (2) North Sea Other Total (2) (In millions) 2020 Acquisitions: Proved $ — $ 7 $ — $ — $ 7 Unproved 4 — — — 4 Exploration 8 102 68 150 328 Development 332 378 162 — 872 Costs incurred (1) $ 344 $ 487 $ 230 $ 150 $ 1,211 (1) Includes capitalized interest and asset retirement costs as follows: Capitalized interest $ — $ — $ — $ 3 $ 3 Asset retirement costs 9 — 29 — 38 2019 Acquisitions: Proved $ 3 $ 5 $ — $ — $ 8 Unproved 47 10 — — 57 Exploration 162 139 62 105 468 Development 1,500 374 119 3 1,996 Costs incurred (1) $ 1,712 $ 528 $ 181 $ 108 $ 2,529 (1) Includes capitalized interest and asset retirement costs as follows: Capitalized interest $ 23 $ — $ 5 $ 4 $ 32 Asset retirement costs 14 — (111) — (97) 2018 Acquisitions: Proved $ — $ 6 $ — $ — $ 6 Unproved 111 16 — — 127 Exploration 640 175 113 12 940 Development 1,791 457 133 — 2,381 Costs incurred (1) $ 2,542 $ 654 $ 246 $ 12 $ 3,454 (1) Includes capitalized interest and asset retirement costs as follows: Capitalized interest $ 23 $ — $ 11 $ 2 $ 36 Asset retirement costs 93 — (62) — 31 (2) Includes a noncontrolling interest in Egypt. 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 Egypt (1) North Other Total (1) (In millions) 2020 Proved properties $ 20,343 $ 12,069 $ 8,805 $ — $ 41,217 Unproved properties 348 77 42 135 602 20,691 12,146 8,847 135 41,819 Accumulated DD&A (16,252) (10,290) (7,081) — (33,623) $ 4,439 $ 1,856 $ 1,766 $ 135 $ 8,196 2019 Proved properties $ 20,291 $ 11,614 $ 8,635 $ — $ 40,540 Unproved properties 509 109 10 38 666 20,800 11,723 8,645 38 41,206 Accumulated DD&A (11,783) (9,377) (6,700) — (27,860) $ 9,017 $ 2,346 $ 1,945 $ 38 $ 13,346 (1) Includes a noncontrolling interest in Egypt..
Proved Reserve Data	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 Egypt (1) North Total (1) (Thousands of barrels) Proved developed reserves: December 31, 2017 304,279 124,568 92,598 521,445 December 31, 2018 300,484 110,014 104,491 514,989 December 31, 2019 278,145 103,573 101,712 483,430 December 31, 2020 206,936 95,981 86,566 389,483 Proved undeveloped reserves: December 31, 2017 31,904 16,198 14,013 62,115 December 31, 2018 45,182 9,484 11,278 65,944 December 31, 2019 46,716 10,831 10,049 67,596 December 31, 2020 25,516 11,228 7,273 44,017 Total proved reserves: Balance December 31, 2017 336,183 140,766 106,611 583,560 Extensions, discoveries and other additions 61,976 22,473 15,682 100,131 Purchases of minerals in-place 140 — — 140 Revisions of previous estimates (14,334) (9,556) 10,613 (13,277) Production (38,252) (34,185) (17,137) (89,574) Sales of minerals in-place (47) — — (47) Balance December 31, 2018 345,666 119,498 115,769 580,933 Extensions, discoveries and other additions 52,297 21,039 9,017 82,353 Revisions of previous estimates (16,446) 4,752 5,132 (6,562) Production (38,344) (30,885) (18,157) (87,386) Sales of minerals in-place (18,312) — — (18,312) Balance December 31, 2019 324,861 114,404 111,761 551,026 Extensions, discoveries and other additions 17,858 17,855 5,275 40,988 Revisions of previous estimates (69,247) 2,541 (4,756) (71,462) Production (32,299) (27,591) (18,441) (78,331) Sales of minerals in-place (8,721) — — (8,721) Balance December 31, 2020 232,452 107,209 93,839 433,500 (1) Includes proved reserves of 36 MMbbls, 38 MMbbls, 40 MMbbls, and 47 MMbbls as of December 31, 2020, 2019, 2018, and 2017, respectively, attributable to a noncontrolling interest in Egypt. Natural Gas Liquids United Egypt (1) North Total (1) (Thousands of barrels) Proved developed reserves: December 31, 2017 171,005 685 2,025 173,715 December 31, 2018 197,574 502 1,938 200,014 December 31, 2019 158,794 667 2,317 161,778 December 31, 2020 150,599 716 2,053 153,368 Proved undeveloped reserves: December 31, 2017 29,559 39 353 29,951 December 31, 2018 33,796 60 631 34,487 December 31, 2019 23,569 90 660 24,319 December 31, 2020 15,141 126 320 15,587 Total proved reserves: Balance December 31, 2017 200,564 724 2,378 203,666 Extensions, discoveries and other additions 60,990 144 1,444 62,578 Purchases of minerals in-place 40 — — 40 Revisions of previous estimates (9,250) 31 (819) (10,038) Production (20,969) (337) (434) (21,740) Sales of minerals in-place (5) — — (5) Balance December 31, 2018 231,370 562 2,569 234,501 Extensions, discoveries and other additions 41,343 27 697 42,067 Revisions of previous estimates (32,569) 508 345 (31,716) Production (24,959) (340) (634) (25,933) Sales of minerals in-place (32,822) — — (32,822) Balance December 31, 2019 182,363 757 2,977 186,097 Extensions, discoveries and other additions 11,435 97 312 11,844 Revisions of previous estimates (469) 264 (207) (412) Production (27,133) (276) (709) (28,118) Sales of minerals in-place (456) — — (456) Balance December 31, 2020 165,740 842 2,373 168,955 (1) Includes proved reserves of 281 Mbbls, 252 Mbbls, 187 Mbbls, and 241 Mbbls as of December 31, 2020, 2019, 2018, and 2017, respectively, attributable to a noncontrolling interest in Egypt. Natural Gas United Egypt (1) North Total (1) (Millions of cubic feet) Proved developed reserves: December 31, 2017 1,347,009 540,667 83,342 1,971,018 December 31, 2018 1,626,403 476,132 95,347 2,197,882 December 31, 2019 945,938 433,382 106,329 1,485,649 December 31, 2020 1,052,756 409,035 68,159 1,529,950 Proved undeveloped reserves: December 31, 2017 297,226 47,255 11,063 355,544 December 31, 2018 267,090 33,006 15,804 315,900 December 31, 2019 115,040 24,704 16,604 156,348 December 31, 2020 76,504 12,572 8,341 97,417 Total proved reserves: Balance December 31, 2017 1,644,235 587,922 94,405 2,326,562 Extensions, discoveries and other additions 704,135 79,394 55,274 838,803 Purchases of minerals in-place 906 — — 906 Revisions of previous estimates (239,204) (38,892) (21,933) (300,029) Production (216,538) (119,286) (16,595) (352,419) Sales of minerals in-place (41) — — (41) Balance December 31, 2018 1,893,493 509,138 111,151 2,513,782 Extensions, discoveries and other additions 249,205 34,758 27,711 311,674 Revisions of previous estimates (509,753) 18,570 4,015 (487,168) Production (233,447) (104,380) (19,944) (357,771) Sales of minerals in-place (338,520) — — (338,520) Balance December 31, 2019 1,060,978 458,086 122,933 1,641,997 Extensions, discoveries and other additions 60,965 83,718 8,140 152,823 Revisions of previous estimates 215,166 (19,849) (33,541) 161,776 Production (205,594) (100,348) (21,032) (326,974) Sales of minerals in-place (2,255) — — (2,255) Balance December 31, 2020 1,129,260 421,607 76,500 1,627,367 (1) Includes proved reserves of 141 Bcf, 153 Bcf, 170 Bcf, and 196 Bcf as of December 31, 2020, 2019, 2018, and 2017, respectively, attributable to a noncontrolling interest in Egypt. Total Equivalent Reserves United Egypt (1) North Total (1) (Thousands barrels of oil equivalent) Proved developed reserves: December 31, 2017 699,786 215,364 108,513 1,023,663 December 31, 2018 769,125 189,871 122,320 1,081,316 December 31, 2019 594,595 176,470 121,751 892,816 December 31, 2020 532,994 164,870 99,979 797,843 Proved undeveloped reserves: December 31, 2017 111,001 24,112 16,210 151,323 December 31, 2018 123,493 15,045 14,543 153,081 December 31, 2019 89,458 15,038 13,476 117,972 December 31, 2020 53,408 13,449 8,983 75,840 Total proved reserves: Balance December 31, 2017 810,787 239,476 124,723 1,174,986 Extensions, discoveries and other additions 240,322 35,849 26,338 302,509 Purchases of minerals in-place 331 — — 331 Revisions of previous estimates (63,451) (16,007) 6,139 (73,319) Production (95,312) (54,402) (20,337) (170,051) Sales of minerals in-place (59) — — (59) Balance December 31, 2018 892,618 204,916 136,863 1,234,397 Extensions, discoveries and other additions 135,174 26,859 14,333 176,366 Revisions of previous estimates (133,974) 8,355 6,146 (119,473) Production (102,211) (48,622) (22,115) (172,948) Sales of minerals in-place (107,554) — — (107,554) Balance December 31, 2019 684,053 191,508 135,227 1,010,788 Extensions, discoveries and other additions 39,454 31,905 6,944 78,303 Revisions of previous estimates (33,854) (502) (10,554) (44,910) Production (93,698) (44,592) (22,655) (160,945) Sales of minerals in-place (9,553) — — (9,553) Balance December 31, 2020 586,402 178,319 108,962 873,683 (1) Includes include total proved reserves of 59 MMboe, 64 MMboe, 68 MMboe, and 80 MMboe as of December 31, 2020, 2019, 2018, and 2017, respectively, attributable to a noncontrolling interest in Egypt.
Unaudited Information of Future Net Cash Flows For Oil and Gas Reserves, Net of Income Tax Expense	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 current laws, 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 Egypt (1) North Total (1) (In millions) 2020 Cash inflows $ 12,537 $ 5,560 $ 4,122 $ 22,219 Production costs (6,244) (1,704) (2,388) (10,336) Development costs (1,555) (633) (2,448) (4,636) Income tax expense — (1,096) 316 (780) Net cash flows 4,738 2,127 (398) 6,467 10 percent discount rate (1,829) (437) 1,111 (1,155) Discounted future net cash flows (2) $ 2,909 $ 1,690 $ 713 $ 5,312 2019 Cash inflows $ 21,694 $ 8,306 $ 7,454 $ 37,454 Production costs (10,642) (1,847) (2,730) (15,219) Development costs (1,740) (707) (2,651) (5,098) Income tax expense (27) (1,930) (784) (2,741) Net cash flows 9,285 3,822 1,289 14,396 10 percent discount rate (4,003) (808) 297 (4,514) Discounted future net cash flows (2) $ 5,282 $ 3,014 $ 1,586 $ 9,882 2018 Cash inflows $ 29,906 $ 9,866 $ 9,206 $ 48,978 Production costs (13,699) (1,799) (2,588) (18,086) Development costs (2,150) (792) (2,714) (5,656) Income tax expense (19) (2,455) (1,352) (3,826) Net cash flows 14,038 4,820 2,552 21,410 10 percent discount rate (6,516) (1,066) (107) (7,689) Discounted future net cash flows (2) $ 7,522 $ 3,754 $ 2,445 $ 13,721 (1) Includes discounted future net cash flows of approximately $563 million , $1.0 billion, and $1.3 billion as of December 31, 2020, 2019, and 2018, 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 $7.1 billion , $12.4 billion, and $16.9 billion as of December 31, 2020, 2019, and 2018, respectively.
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, 2020 2019 2018 (In millions) Sales, net of production costs $ (2,422) $ (4,291) $ (5,335) Net change in prices and production costs (5,753) (3,034) 3,902 Discoveries and improved recovery, net of related costs 751 2,042 3,889 Change in future development costs 20 (75) 47 Previously estimated development costs incurred during the period 576 983 910 Revision of quantities (418) (741) (648) Purchases of minerals in-place — — 6 Accretion of discount 1,236 1,693 1,216 Change in income taxes 1,533 720 (1,125) Sales of minerals in-place (104) (817) (1) Change in production rates and other 11 (319) 777 $ (4,570) $ (3,839) $ 3,638

NATURE OF OPERATIONS (Details)

NATURE OF OPERATIONS (Details)	12 Months Ended
	Dec. 31, 2020Area
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of geographical areas	3

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) - USD ($)	3 Months Ended			12 Months Ended
	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Nov. 30, 2018
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments		$ 1,400,000,000		$ 4,501,000,000	$ 2,949,000,000	$ 511,000,000
Goodwill impairment				87,000,000	0	0
Impairment for early termination of drilling rig leases	$ 13,000,000
Inventory write-downs	5,000,000					4,000,000
Other asset impairments	9,000,000
Capitalized exploratory well costs, impairment						10,000,000
Equity method investment				0	0	113,000,000
Cash and cash equivalent		247,000,000		262,000,000	247,000,000
Restricted cash		0		0	0
Oil and gas property impaired, fair value		628,000,000		1,900,000,000	628,000,000
Divested unproved properties and leasehold				0	149,000,000	10,000,000
Gathering, processing, and transmission facilities ($206 and $203 related to Altus VIE)		799,000,000		670,000,000	799,000,000
Other property and equipment		1,140,000,000		$ 1,140,000,000	1,140,000,000
Percentage of production available to recover these operating and capital costs over contractually defined periods (up to)				40.00%
Receivables from contracts with customers, net of allowance for doubtful accounts		945,000,000		$ 670,000,000	945,000,000
Restructuring cumulative cost incurred to date				79,000,000
Transaction, reorganization, and separation				54,000,000	50,000,000	28,000,000
Egypt
Schedule Of Significant Accounting Policies [Line Items]
Goodwill impairment	87,000,000			87,000,000	0	0
Employee Severance
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation				51,000,000	26,000,000	6,000,000
Consulting and Legal Fees
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation				2,000,000	2,000,000	22,000,000
Office closure
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation				1,000,000
Employee Termination and Office Closures
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation					15,000,000
Other restructuring
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation					7,000,000
Oil and gas, purchased
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas production revenues				398,000,000	176,000,000	357,000,000
Gathering, processing, and transmission				357,000,000	142,000,000	340,000,000
Oil and gas, purchased | Revision of Prior Period, Reclassification, Adjustment
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas production revenues					176,000,000	357,000,000
Gathering, processing, and transmission					142,000,000	340,000,000
Alpine High Play
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas property impaired, fair value		203,000,000			203,000,000
Oklahoma And Texas | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment			$ 240,000,000		255,000,000
(Loss) gain on sale of oil and gas properties			$ (7,000,000)
Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment				$ 4,319,000,000	1,484,000,000	328,000,000
Oil and gas proved property | Significant Unobservable Inputs (Level 3) | Measurement Input, Discount Rate
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas properties, measurement inputs				10.00%
Oil and gas proved property | United States
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment	3,900,000,000			$ 3,938,000,000	1,484,000,000	265,000,000
Oil and gas proved property | Egypt
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment	354,000,000			374,000,000	0	63,000,000
Oil and gas proved property | North Sea
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment	7,000,000			7,000,000	0	0
Oil and gas proved property | Oklahoma And Texas | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment					101,000,000
Gathering, processing, and transmission facilities
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment						56,000,000
Oil and gas property impaired, fair value	46,000,000
Gathering, processing, and transmission facilities ($206 and $203 related to Altus VIE)		799,000,000		670,000,000	799,000,000
Accumulated depreciation		310,000,000		323,000,000	310,000,000
(Loss) gain on sale of oil and gas properties					0	0
Gathering, processing, and transmission facilities | Egypt
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments	$ 68,000,000
Oil And Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment				101,000,000	768,000,000	224,000,000
Oil And Gas Properties, Unproved | United States
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment				92,000,000	760,000,000	96,000,000
Oil And Gas Properties, Unproved | Egypt
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment				8,000,000	8,000,000	0
Oil And Gas Properties, Unproved | North Sea
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment				1,000,000	0	128,000,000
Divested unproved properties and leasehold						$ 10,000,000
Oil And Gas Properties, Unproved | Oklahoma And Texas
Schedule Of Significant Accounting Policies [Line Items]
Divested unproved properties and leasehold					149,000,000
Oil And Gas Properties, Unproved | Oklahoma And Texas | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment					149,000,000
Other Working Capital | Oklahoma And Texas | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment					5,000,000
Power Generators
Schedule Of Significant Accounting Policies [Line Items]
(Loss) gain on sale of oil and gas properties				(2,000,000)
Other Property and Equipment
Schedule Of Significant Accounting Policies [Line Items]
Accumulated depreciation		817,000,000		$ 864,000,000	817,000,000
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
ALTM
Schedule Of Significant Accounting Policies [Line Items]
Cash and cash equivalent		6,000,000		$ 24,000,000	$ 6,000,000
ALTM | Gathering, processing, and transmission facilities
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment		$ 1,300,000,000
Apache Egypt | Sinopec
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners				33.33%
ALTM | Third-party investors
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners				21.00%			21.00%

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Asset Impairments Recorded in Connection with Fair Value Assessments (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Schedule Of Significant Accounting Policies [Line Items]
Equity method investment			$ 0	$ 0	$ 113
Divested unproved properties and leasehold			0	149	10
Goodwill			87	0	0
Inventory and other			27	21	4
Impairments	$ 1,400		4,501	2,949	511
Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Tangible Asset Impairment Charges		$ 20	4,319	1,484	328
Gathering, processing, and transmission facilities
Schedule Of Significant Accounting Policies [Line Items]
Tangible Asset Impairment Charges			$ 68	$ 1,295	$ 56

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Allowance for Credit Loss Roll-forward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Allowance for credit loss at beginning of year	$ 88	$ 92	$ 84
Accounts Receivable, Credit Loss Expense (Reversal)	7	3	9
Accounts Receivable, Allowance For Credit Loss, Write-offs, Net Of Recoveries	0	(7)	(1)
Allowance for credit loss at end of year	$ 95	$ 88	$ 92

SUMMARY OF SIGNIFICANT ACCOUN_7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Non-Cash Impairments of Proved and Unproved Property and Equipment (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment		$ 4,319	$ 1,484	$ 328
Oil And Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment		101	768	224
U.S. | Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment	$ 3,900	3,938	1,484	265
U.S. | Oil And Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment		92	760	96
Egypt | Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment	354	374	0	63
Egypt | Oil And Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment		8	8	0
North Sea | Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment	$ 7	7	0	0
North Sea | Oil And Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment		$ 1	$ 0	$ 128

SUMMARY OF SIGNIFICANT ACCOUN_8

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Changes to Goodwill (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Goodwill [Roll Forward]
Goodwill, Beginning Balance	$ 87	$ 87	$ 87	$ 87
Impairments		(87)	0	0
Goodwill, Ending Balance		0	87	87
Egypt
Goodwill [Roll Forward]
Goodwill, Beginning Balance	87	87	87	87
Impairments	$ (87)	(87)	0	0
Goodwill, Ending Balance		$ 0	$ 87	$ 87

ACQUISITIONS AND DIVESTITURES -

ACQUISITIONS AND DIVESTITURES - 2020 Activity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Leasehold and property acquisitions amount	$ 4	$ 40	$ 133
Proceeds from sale of oil and gas properties	166	718	138
Permian Region
Business Acquisition [Line Items]
Leasehold and property acquisitions amount	4	40	$ 133
Permian Region | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties	87	73
Gain (loss) on sale of oil and gas properties	$ 13	$ 33

ACQUISITIONS AND DIVESTITURES_2

ACQUISITIONS AND DIVESTITURES - 2019 Activity (Details) $ in Millions	1 Months Ended	3 Months Ended			12 Months Ended
	Dec. 31, 2019USD ($)equity_option	Mar. 31, 2020USD ($)	Sep. 30, 2019USD ($)	Jun. 30, 2019USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)equity_option	Dec. 31, 2018USD ($)
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties					$ 166	$ 718	$ 138
Leasehold and property acquisitions amount					4	$ 40	133
Number of joint venture equity options exercised | equity_option	4					4
Number of joint venture equity options | equity_option	5					5
OKLAHOMA
Business Acquisition [Line Items]
Gain (loss) on sale of oil and gas properties		$ 19
Permian Region
Business Acquisition [Line Items]
Leasehold and property acquisitions amount					4	$ 40	$ 133
Block 58 Offshore Suriname
Business Acquisition [Line Items]
Ownership percentage by noncontrolling owners	50.00%					50.00%
Proceeds received from joint venture	$ 100
Proceeds from joint venture agreement, for reimbursement of cost incurred	$ 79
Joint venture agreement, percentage of costs incurred for reimbursement	50.00%
Proceeds expected to receive from joint venture	$ 5,000					$ 5,000
Carrying cash consideration	$ 7,500					$ 7,500
Percentage of consideration carried on appraisal and development capital	25.00%					25.00%
Additional cash payment to receive upon achieving first production	$ 75
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Oklahoma And Texas
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties			$ 322
Asset retirement obligation assumed			49
Asset impairments for property and equipment			240			$ 255
Gain (loss) on sale of oil and gas properties			$ (7)
Disposal Group, Disposed of by Sale, Not Discontinued Operations | OKLAHOMA
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties				$ 223
Gain (loss) on sale of oil and gas properties				17
Property and equipment, net				$ 206
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Permian Region
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties					87	73
Gain (loss) on sale of oil and gas properties					$ 13	$ 33

ACQUISITIONS AND DIVESTITURES_3

ACQUISITIONS AND DIVESTITURES - 2018 Activity (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Nov. 30, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Leasehold and property acquisitions amount		$ 4	$ 40	$ 133
North Sea and Premian Regions
Business Acquisition [Line Items]
Proceeds from sale of certain non-core assets				138
Gain on sale of non-core assets				23
Permian Region
Business Acquisition [Line Items]
Leasehold and property acquisitions amount		4	40	$ 133
Noncontrolling Interest, Altus
Business Acquisition [Line Items]
Noncontrolling interest	$ 406	$ 69	$ 73
ALTM
Business Acquisition [Line Items]
Ownership percentage by parent	79.00%
Altus Midstream LP | KAAC
Business Acquisition [Line Items]
Proceeds from contribution	$ 628
Assets contributed	$ 1,100
Third-party investors | ALTM
Business Acquisition [Line Items]
Ownership percentage by noncontrolling owners	21.00%	21.00%

CAPITALIZED EXPLORATORY WELL _3

CAPITALIZED EXPLORATORY WELL COSTS - Capitalized Exploratory Well Costs Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Capitalized well costs at beginning of year	$ 141	$ 159	$ 350
Additions pending determination of proved reserves	226	286	602
Divestitures and other	(38)	(100)	(82)
Reclassifications to proved properties	(56)	(179)	(647)
Charged to exploration expense	(76)	(25)	(64)
Capitalized well costs at end of year	$ 197	$ 141	$ 159

CAPITALIZED EXPLORATORY WELL _4

CAPITALIZED EXPLORATORY WELL COSTS - Aging of Suspended Well Balances (Details) $ in Millions	Dec. 31, 2020USD ($)Project	Dec. 31, 2019USD ($)Project	Dec. 31, 2018USD ($)Project	Dec. 31, 2017USD ($)
Extractive Industries [Abstract]
Exploratory well costs capitalized for a period of one year or less	$ 184	$ 108	$ 126
Exploratory well costs capitalized for a period greater than one year	13	33	33
Capitalized exploratory well costs	$ 197	$ 141	$ 159	$ 350
Number of projects with exploratory well costs capitalized for a period greater than one year | Project	5	2	2

CAPITALIZED EXPLORATORY WELL _5

CAPITALIZED EXPLORATORY WELL COSTS - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 13	$ 33	$ 33
Block 58 Offshore Suriname
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Ownership percentage by noncontrolling owners		50.00%
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			$ 28

CAPITALIZED EXPLORATORY WELL _6

CAPITALIZED EXPLORATORY WELL COSTS - Aging by Geographic Area of Exploratory Well Costs Capitalized Greater than One Year (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 13	$ 33	$ 33
2019
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	4
2018
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
2017 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	0
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	13
Egypt | 2019
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	4
Egypt | 2018
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 | 2017 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	$ 0

DERIVATIVE INSTRUMENTS AND HE_3

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Additional Information (Details)	12 Months Ended
	Dec. 31, 2020Counterparty
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Number of derivative counterparties	6
Expected timing until exercise of exchange option	5 years 5 months 12 days

DERIVATIVE INSTRUMENTS AND HE_4

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Instruments (Details) - Natural Gas MMBTU in Thousands	12 Months Ended
	Dec. 31, 2020$ / MMBTUMMBTU
Basis Swap Purchased | April to December 2021 | NYMEX Henry Hub/IF Waha
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	37,580
Weighted average price differential | $ / MMBTU	(0.43)
Basis Swap Purchased | January to December 2022 | NYMEX Henry Hub/IF Waha
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	43,800
Weighted average price differential | $ / MMBTU	(0.45)
Basis Swap Sold | April to December 2021 | NYMEX Henry Hub/IF HSC
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	37,580
Weighted average price differential | $ / MMBTU	(0.07)
Basis Swap Sold | January to December 2022 | NYMEX Henry Hub/IF HSC
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	43,800
Weighted average price differential | $ / MMBTU	(0.08)

DERIVATIVE INSTRUMENTS AND HE_5

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Assets and Liabilities Measured at Fair Value (Details) - Recurring - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Commodity Derivative Instruments
Derivative [Line Items]
Derivative asset, fair value	$ 11
Derivative asset, netting	0
Derivative asset	11	$ 9
Derivative liability	192	103
Commodity Derivative Instruments | Quoted Price in Active Markets (Level 1)
Derivative [Line Items]
Derivative asset, fair value	0
Commodity Derivative Instruments | Significant Other Inputs (Level 2)
Derivative [Line Items]
Derivative asset, fair value	11
Commodity Derivative Instruments | Significant Unobservable Inputs (Level 3)
Derivative [Line Items]
Derivative asset, fair value	0
Pipeline capacity embedded derivatives
Derivative [Line Items]
Derivative asset, fair value		8
Derivative asset, netting		0
Derivative asset		8
Derivative liability, fair value	53
Derivative liability, netting	0
Derivative liability	53
Pipeline capacity embedded derivatives | Quoted Price in Active Markets (Level 1)
Derivative [Line Items]
Derivative asset, fair value		0
Derivative liability, fair value	0
Pipeline capacity embedded derivatives | Significant Other Inputs (Level 2)
Derivative [Line Items]
Derivative asset, fair value		8
Derivative liability, fair value	53
Pipeline capacity embedded derivatives | Significant Unobservable Inputs (Level 3)
Derivative [Line Items]
Derivative asset, fair value		0
Derivative liability, fair value	0
Preferred Units embedded derivative
Derivative [Line Items]
Derivative liability, fair value	139	103
Derivative liability, netting	0	0
Derivative liability	139	103
Preferred Units embedded derivative | Quoted Price in Active Markets (Level 1)
Derivative [Line Items]
Derivative liability, fair value	0	0
Preferred Units embedded derivative | Significant Other Inputs (Level 2)
Derivative [Line Items]
Derivative liability, fair value	0	0
Preferred Units embedded derivative | Significant Unobservable Inputs (Level 3)
Derivative [Line Items]
Derivative liability, fair value	$ 139	103
Foreign currency derivative instruments
Derivative [Line Items]
Derivative asset, fair value		1
Derivative asset, netting		0
Derivative asset		1
Foreign currency derivative instruments | Quoted Price in Active Markets (Level 1)
Derivative [Line Items]
Derivative asset, fair value		0
Foreign currency derivative instruments | Significant Other Inputs (Level 2)
Derivative [Line Items]
Derivative asset, fair value		1
Foreign currency derivative instruments | Significant Unobservable Inputs (Level 3)
Derivative [Line Items]
Derivative asset, fair value		$ 0

DERIVATIVE INSTRUMENTS AND HE_6

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Fair Value Measurement Inputs (Details) - Significant Unobservable Inputs (Level 3)	Dec. 31, 2020$ / MMBTU
Measurement Input, Risk Free Interest Rate | Minimum
Embedded Derivative [Line Items]
Preferred Units embedded derivative	0.0732
Measurement Input, Risk Free Interest Rate | Maximum
Embedded Derivative [Line Items]
Preferred Units embedded derivative	0.1173
Measurement Input Interest Rate Volatility
Embedded Derivative [Line Items]
Preferred Units embedded derivative	0.3708

DERIVATIVE INSTRUMENTS AND HE_7

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Assets and Liabilities and Locations on Consolidated Balance Sheet (Details) - Recurring - Commodity Derivative Instruments - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Derivatives, Fair Value [Line Items]
Derivative asset	$ 11	$ 9
Derivative liability	192	103
Current Assets: Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset	6	2
Noncurrent Assets: Deferred charges and other
Derivatives, Fair Value [Line Items]
Derivative asset	5	7
Deferred Credits and Other Noncurrent Liabilities: Other
Derivatives, Fair Value [Line Items]
Derivative liability	$ 192	$ 103

DERIVATIVE INSTRUMENTS AND HE_8

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Activities Recorded in the Statement of Consolidated Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss), net	$ (136)	$ 9	$ (120)
Unrealized gain (loss), net	(87)	(44)	103
Derivative instrument losses, net	(223)	(35)	(17)
Commodity Derivative Instruments
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss), net	(135)	27	(81)
Unrealized gain (loss), net	11	(44)	103
Amortization of put premium, realized loss
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss), net	0	0	(39)
Foreign currency derivative instruments
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss), net	(1)	0	0
Unrealized gain (loss), net	(1)	1	0
Treasury-lock
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss), net	0	(18)	0
Pipeline capacity embedded derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss), net	(61)	8	0
Preferred Units embedded derivative
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss), net	$ (36)	$ (9)	$ 0

OTHER CURRENT ASSETS (Details)

OTHER CURRENT ASSETS (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Inventories	$ 492	$ 502
Drilling advances	113	92
Prepaid assets and other	71	58
Total Other current assets	$ 676	$ 652

EQUITY METHOD INTERESTS - Summa

EQUITY METHOD INTERESTS - Summary of Investments (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Equity method interests	$ 1,555	$ 1,258
Shin Oak Pipeline (Breviloba, LLC)
Schedule of Equity Method Investments [Line Items]
Equity method interests		493
ALTM
Schedule of Equity Method Investments [Line Items]
Equity method interests	$ 1,555	1,258	$ 91
ALTM | Gulf Coast Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Interest	16.00%
Equity method interests	$ 284	291	91
ALTM | EPIC Crude Holdings, LP
Schedule of Equity Method Investments [Line Items]
Interest	15.00%
Equity method interests	$ 176	163	0
ALTM | Permian Highway Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Interest	26.70%
Equity method interests	$ 615	311	0
ALTM | Shin Oak Pipeline (Breviloba, LLC)
Schedule of Equity Method Investments [Line Items]
Interest	33.00%
Equity method interests	$ 480	$ 493	$ 0

EQUITY METHOD INTERESTS - Addit

EQUITY METHOD INTERESTS - Additional Information (Details) - ALTM $ in Millions	Dec. 31, 2020USD ($)entity	Dec. 31, 2019USD ($)entity
Schedule of Equity Method Investments [Line Items]
Number of long-haul pipeline entities | entity	4	4
Difference between carrying amount and underlying equity amount | $	$ 38	$ 30

EQUITY METHOD INTERESTS - Rollf

EQUITY METHOD INTERESTS - Rollforward Activity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance	$ 1,258
Acquisitions	0	$ 671	$ 91
Capital contributions	327	501	0
Equity method interest, ending balance	1,555	1,258
Shin Oak Pipeline (Breviloba, LLC)
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance	493
Equity method interest, ending balance		493
ALTM
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance	1,258	91
Acquisitions		671
Capital contributions	327	501
Distributions	(97)	(25)
Capitalized interest	8	2
Equity income (loss), net	59	19
Accumulated other comprehensive loss		(1)
Equity method interest, ending balance	1,555	1,258	91
ALTM | Gulf Coast Express Pipeline LLC
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance	291	91
Acquisitions		15
Capital contributions	2	184
Distributions	(51)	(16)
Capitalized interest	0	0
Equity income (loss), net	42	17
Accumulated other comprehensive loss		0
Equity method interest, ending balance	284	291	91
ALTM | EPIC Crude Holdings, LP
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance	163	0
Acquisitions		52
Capital contributions	29	123
Distributions	0
Capitalized interest	0	0
Equity income (loss), net	(16)	(11)
Accumulated other comprehensive loss		(1)
Equity method interest, ending balance	176	163	0
ALTM | Permian Highway Pipeline LLC
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance	311	0
Acquisitions		162
Capital contributions	296	147
Distributions	0
Capitalized interest	8	2
Equity income (loss), net	0	0
Accumulated other comprehensive loss		0
Equity method interest, ending balance	615	311	0
ALTM | Shin Oak Pipeline (Breviloba, LLC)
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance	493	0
Acquisitions		442
Capital contributions	0	47
Distributions	(46)	(9)
Capitalized interest	0	0
Equity income (loss), net	33	13
Accumulated other comprehensive loss		0
Equity method interest, ending balance	$ 480	$ 493	$ 0

EQUITY METHOD INTERESTS - Sum_2

EQUITY METHOD INTERESTS - Summary of Combined Statement of Operations Equity Method Interests (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Operating revenues	$ 4,308	$ 6,553	$ 7,764
Operating income (loss)	(4,102)	(2,152)	1,836
Net income (loss)	(4,904)	(3,682)	286
Other comprehensive loss	(2)	12	0
Equity Method Investment, Nonconsolidated Investee
Schedule of Equity Method Investments [Line Items]
Operating revenues	707	302	3
Operating income (loss)	331	121	(6)
Net income (loss)	256	120	(6)
Other comprehensive loss	$ 3	$ (8)	$ 0

EQUITY METHOD INTERESTS - Sum_3

EQUITY METHOD INTERESTS - Summary of Combined Statement of Balance Sheet Equity Method Interests (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Current assets	$ 1,846	$ 1,961
Total assets	12,746	18,107	$ 21,582
Current liabilities	1,308	1,855
Equity	(645)	4,465	$ 8,812	$ 8,791
TOTAL LIABILITIES AND EQUITY	12,746	18,107
Equity Method Investment, Nonconsolidated Investee
Schedule of Equity Method Investments [Line Items]
Current assets	260	441
Noncurrent assets	7,678	6,435
Total assets	7,938	6,876
Current liabilities	206	478
Noncurrent liabilities	1,191	958
Equity	6,541	5,440
TOTAL LIABILITIES AND EQUITY	$ 7,938	$ 6,876

OTHER CURRENT LIABILITIES (Deta

OTHER CURRENT LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Payables and Accruals [Abstract]
Accrued operating expenses	$ 91	$ 143
Accrued exploration and development	167	319
Accrued gathering, processing, and transmission - Altus	0	17
Accrued compensation and benefits	170	212
Accrued interest	140	135
Accrued income taxes	25	51
Current asset retirement obligation	56	47
Current operating lease liability	116	169
Other	97	56
Total Other current liabilities	$ 862	$ 1,149

ASSET RETIREMENT OBLIGATION - S

ASSET RETIREMENT OBLIGATION - Schedule of changes to Asset Retirement Obligation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of year	$ 1,858	$ 1,932
Liabilities incurred	10	41
Liabilities divested	(26)	(56)
Liabilities settled	(30)	(56)
Accretion expense	109	107
Revisions in estimated liabilities	23	(110)
Asset retirement obligation at end of year	1,944	1,858
Less current portion	(56)	(47)
Asset retirement obligation, long-term	$ 1,888	$ 1,811

ASSET RETIREMENT OBLIGATION - A

ASSET RETIREMENT OBLIGATION - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Additional abandonment liabilities associated with its drilling and development program	$ 10	$ 41
Revisions in estimated liabilities	$ (23)	$ 110

DEBT AND FINANCING COSTS - Addi

DEBT AND FINANCING COSTS - Additional Information (Details)	Aug. 18, 2020USD ($)	Jun. 21, 2019USD ($)	Mar. 31, 2019USD ($)	Nov. 30, 2018USD ($)contract	Aug. 31, 2018USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2020GBP (£)	Aug. 17, 2020USD ($)	Mar. 26, 2020GBP (£)	Dec. 31, 2019GBP (£)	Jun. 19, 2019USD ($)	Mar. 31, 2018USD ($)
Debt Instrument [Line Items]
Loss (gain) from extinguishment of debt						$ (160,000,000)	$ 75,000,000	$ 94,000,000
Unamortized discount						35,000,000	42,000,000
Debt issuance costs						57,000,000	53,000,000
Discount of debt amortization						7,000,000	2,000,000	$ 3,000,000
Commercial paper
Debt Instrument [Line Items]
Debt instrument, face amount						$ 3,500,000,000
Period for borrowing funds						270 days
Short-term debt outstanding						$ 0	0
Altus Midstream LP
Debt Instrument [Line Items]
Debt leverage ratio (less than)						4			4
Senior Notes
Debt Instrument [Line Items]
Debt repurchased principle amount		$ 932,000,000			$ 731,000,000
Extinguishment of debt amount		1,000,000,000			828,000,000
Loss (gain) from extinguishment of debt		75,000,000			94,000,000
Unamortized debt issuance costs and discount		$ 7,000,000			5,000,000
Apache credit facility
Debt Instrument [Line Items]
Line of credit outstanding						$ 150,000,000	0
Apache credit facility | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, committed amount														$ 4,000,000,000
Debt extension term			1 year
Quarterly facility fees at per annum rate						0.25%
Maximum potential lien on assets located in specified regions						$ 1,700,000,000
Apache credit facility | Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Debt-to-capital ratio								0.60
Percentage of liens of companies consolidated asset						15.00%			15.00%
Apache credit facility | Revolving Credit Facility | Base Rate
Debt Instrument [Line Items]
Margin percentage						0.50%
Apache credit facility | Revolving Credit Facility | LIBOR
Debt Instrument [Line Items]
Margin percentage						1.50%
Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, face amount										$ 1,250,000,000			$ 1,000,000,000
Unsecured Debt | 4.375% notes due 2028
Debt Instrument [Line Items]
Debt offering, aggregate principal amount					$ 1,000,000,000
Debt interest rate					4.375%	4.375%			4.375%
Unsecured Debt | 4.250% Notes Due January 15, 2030
Debt Instrument [Line Items]
Debt interest rate													4.25%
Debt instrument, face amount													$ 600,000,000
Unsecured Debt | 5.350% Notes Due July 1, 2049
Debt Instrument [Line Items]
Debt interest rate													5.35%
Debt instrument, face amount													$ 400,000,000
Unsecured Debt | 4.625% Senior Notes Due In 2025
Debt Instrument [Line Items]
Debt interest rate										4.625%
Debt instrument, face amount										$ 500,000,000
Unsecured Debt | 4.875% Senior Notes Due In 2027
Debt Instrument [Line Items]
Debt interest rate										4.875%
Debt instrument, face amount										$ 750,000,000
Senior Notes
Debt Instrument [Line Items]
Debt repurchased principle amount	$ 644,000,000					$ 588,000,000
Loss (gain) from extinguishment of debt	2,000,000					(158,000,000)
Discount to par of debt repurchase	38,000,000					168,000,000
Debt instrument, repurchase early tender premium	32,000,000
Debt repurchase, accrued and unpaid interest	$ 6,000,000
Debt instrument repurchase program						$ 428,000,000
Line of Credit | Altus Midstream LP
Debt Instrument [Line Items]
Debt covenant leverage ratio						5			5
Incentive distribution						$ 30,000,000
Adjusted pursuant agreement consecutive equals or exceeds						$ 350,000,000
Line of Credit | Altus Midstream LP | Maximum
Debt Instrument [Line Items]
Debt covenant leverage ratio						5.50			5.50
Line of Credit | Altus Midstream LP | Minimum
Debt Instrument [Line Items]
Debt covenant leverage ratio						4			4
Line of Credit | Revolving Credit Facility | Altus Midstream LP
Debt Instrument [Line Items]
Letters of credit outstanding, amount						$ 0	0
Debt extension term				1 year
Line of credit facility maximum borrowing capacity				$ 800,000,000
Line of credit facility, number of extension options | contract				2
Line of credit facility, maximum borrowing capacity, if adding new lenders				$ 1,500,000,000
Line of Credit | Letter of Credit | Altus Midstream LP
Debt Instrument [Line Items]
Line of credit facility maximum borrowing capacity				100,000,000
Line of Credit | Swingline Loan Subfacility | Altus Midstream LP
Debt Instrument [Line Items]
Line of credit facility maximum borrowing capacity				$ 100,000,000
Line of Credit | Uncommitted Lines of Credit
Debt Instrument [Line Items]
Line of credit outstanding						0	0
Line of Credit | Uncommitted Lines of Credit | Letter of Credit
Debt Instrument [Line Items]
Letters of credit outstanding, amount						17,000,000	3,000,000		£ 34,000,000			£ 22,000,000
Line of Credit | Apache credit facility | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility maximum borrowing capacity			$ 5,000,000,000
Line of Credit | Apache credit facility | Letter of Credit
Debt Instrument [Line Items]
Letters of credit outstanding, amount						40,000,000			£ 633,000,000		£ 633,000,000	£ 0
Line of credit facility, committed amount						2,080,000,000
Line of credit facility maximum borrowing capacity						3,000,000,000
Line of Credit | Altus credit facility | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit outstanding						624,000,000	396,000,000
Line of Credit | Altus credit facility | Revolving Credit Facility | Altus Midstream LP
Debt Instrument [Line Items]
Line of credit outstanding						$ 624,000,000	$ 396,000,000

DEBT AND FINANCING COSTS - Sche

DEBT AND FINANCING COSTS - Schedule of Debt (Details) - USD ($) $ in Millions	Nov. 03, 2020	Dec. 31, 2020	Dec. 31, 2019	Aug. 31, 2018
Debt Instrument [Line Items]
Long-term debt, gross		$ 8,052	$ 8,217
Finance lease obligations		38	48
Unamortized discount		(35)	(42)
Debt issuance costs		(57)	(53)
Total debt		8,772	8,566
Current maturities		(2)	(11)
Long-term debt		8,770	8,555
Apache credit facility
Debt Instrument [Line Items]
Credit facility		150	0
Notes and debentures before unamortized discount and debt issuance costs
Debt Instrument [Line Items]
Debt fair value		8,500	8,400
Unsecured Debt | 3.625% notes due 2021
Debt Instrument [Line Items]
Long-term debt, gross		0	293
Debt interest rate	3.625%
Redemption price, percentage of principal amount redeemed	100.00%
Unsecured Debt | 3.25% notes due 2022
Debt Instrument [Line Items]
Long-term debt, gross		$ 213	463
Debt interest rate		3.25%
Unsecured Debt | 2.625% notes due 2023
Debt Instrument [Line Items]
Long-term debt, gross		$ 123	181
Debt interest rate		2.625%
Unsecured Debt | 4.625% notes due 2025
Debt Instrument [Line Items]
Long-term debt, gross		$ 500	0
Debt interest rate		4.625%
Unsecured Debt | 7.7% notes due 2026
Debt Instrument [Line Items]
Long-term debt, gross		$ 79	79
Debt interest rate		7.70%
Unsecured Debt | 7.95% notes due 2026
Debt Instrument [Line Items]
Long-term debt, gross		$ 133	133
Debt interest rate		7.95%
Unsecured Debt | 4.875% notes due 2027
Debt Instrument [Line Items]
Long-term debt, gross		$ 750	0
Debt interest rate		4.875%
Unsecured Debt | 4.375% notes due 2028
Debt Instrument [Line Items]
Long-term debt, gross		$ 993	1,000
Debt interest rate		4.375%		4.375%
Unsecured Debt | 7.75% notes due in 2029
Debt Instrument [Line Items]
Long-term debt, gross		$ 235	247
Debt interest rate		7.75%
Unsecured Debt | 4.25% notes due 2030
Debt Instrument [Line Items]
Long-term debt, gross		$ 580	600
Debt interest rate		4.25%
Unsecured Debt | 6.0% notes due 2037
Debt Instrument [Line Items]
Long-term debt, gross		$ 443	467
Debt interest rate		6.00%
Unsecured Debt | 5.1% notes due 2040
Debt Instrument [Line Items]
Long-term debt, gross		$ 1,333	1,499
Debt interest rate		5.10%
Unsecured Debt | 5.25% notes due 2042
Debt Instrument [Line Items]
Long-term debt, gross		$ 399	500
Debt interest rate		5.25%
Unsecured Debt | 4.75% notes due 2043
Debt Instrument [Line Items]
Long-term debt, gross		$ 1,133	1,413
Debt interest rate		4.75%
Unsecured Debt | 4.25% notes due 2044
Debt Instrument [Line Items]
Long-term debt, gross		$ 559	753
Debt interest rate		4.25%
Unsecured Debt | 7.375% debentures due 2047
Debt Instrument [Line Items]
Long-term debt, gross		$ 150	150
Debt interest rate		7.375%
Unsecured Debt | 5.35% notes due 2049
Debt Instrument [Line Items]
Long-term debt, gross		$ 390	400
Debt interest rate		5.35%
Unsecured Debt | 7.625% debentures due 2096
Debt Instrument [Line Items]
Long-term debt, gross		$ 39	39
Debt interest rate		7.625%
Commercial paper
Debt Instrument [Line Items]
Long-term debt, gross		$ 0	0
Line of Credit | Altus credit facility | Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility		$ 624	$ 396

DEBT AND FINANCING COSTS - Sc_2

DEBT AND FINANCING COSTS - Schedule of Long Term Debt by Maturity (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Debt Disclosure [Abstract]
2021	$ 0
2022	213
2023	123
2024	0
2025	500
Thereafter	7,216
Notes and debentures, excluding discounts and debt issuance costs	$ 8,052	$ 8,217

DEBT AND FINANCING COSTS - Comp

DEBT AND FINANCING COSTS - Components of Financing Costs, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Debt Disclosure [Abstract]
Interest expense	$ 438	$ 430	$ 441
Amortization of debt issuance costs	8	7	9
Capitalized interest	(12)	(37)	(44)
Loss (gain) on extinguishment of debt	(160)	75	94
Interest income	(7)	(13)	(22)
Financing costs, net	$ 267	$ 462	$ 478

INCOME TAXES - Income (Loss) Be

INCOME TAXES - Income (Loss) Before Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
U.S.	$ (4,581)	$ (4,397)	$ (723)
Foreign	(259)	1,389	1,681
NET INCOME (LOSS) BEFORE INCOME TAXES	$ (4,840)	$ (3,008)	$ 958

INCOME TAXES - Total Provision

INCOME TAXES - Total Provision for Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current income taxes:
Federal	$ (2)	$ 1	$ (1)
State	0	0	0
Foreign	178	659	895
Total current income taxes	176	660	894
Deferred income taxes:
Federal	0	67	(65)
State	0	0	2
Foreign	(112)	(53)	(159)
Total deferred income taxes	(112)	14	(222)
Total	$ 64	$ 674	$ 672

INCOME TAXES - Reconciliation o

INCOME TAXES - Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income tax expense (benefit) at U.S. statutory rate	$ (1,016)	$ (631)	$ 201
State income tax, less federal effect	0	1	2
Taxes related to foreign operations	97	328	436
Tax credits	(13)	(6)	(13)
Tax on deemed repatriation of foreign earnings	0	0	103
Foreign tax credits	0	0	(336)
Change in U.S. tax rate	0	0	161
Net change in tax contingencies	1	1	(2)
Goodwill impairment	35	0	0
Sale of North Sea assets	0	0	(30)
Valuation allowances	965	972	118
All other, net	(5)	9	32
Total	$ 64	$ 674	$ 672

INCOME TAXES - Net Deferred Tax

INCOME TAXES - Net Deferred Tax Liability (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Deferred tax assets:
U.S. and state net operating losses	$ 2,306	$ 2,108
Capital losses	633	626
Tax credits and other tax incentives	33	32
Foreign tax credits	2,241	2,241
Accrued expenses and liabilities	93	97
Asset retirement obligation	654	618
Property & equipment	261	0
Investment in Altus Midstream LP	76	107
Net interest expense limitation	252	162
Lease liability	79	108
Other	1	88
Total deferred tax assets	6,629	6,187
Valuation allowance	(5,991)	(4,959)	$ (3,947)	$ (3,816)
Net deferred tax assets	638	1,228
Deferred tax liabilities:
Deferred income	0	1
Equity investments	4	0
Property and equipment	750	1,432
Right-of-use asset	74	106
Other	13	6
Total deferred tax liabilities	841	1,545
Net deferred income tax liability	$ 203	$ 317

INCOME TAXES - Net Deferred T_2

INCOME TAXES - Net Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Assets:
Deferred charges and other	$ 12	$ 29
Liabilities:
Income taxes	215	346
Net deferred income tax liability	$ 203	$ 317

INCOME TAXES - Additional Infor

INCOME TAXES - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax [Line Items]
Measurement period adjustment, additional deferred tax expense under the Act			$ 103
Increase (decrease) of valuation allowances	$ 1,000	$ 1,000	131
Net interest expense carryforward	1,100
Capital losses	633	626
Foreign tax credit carryforward, amount	2,241	2,241
Tax expense recorded for interest and penalties	1	1	1
Accrued for payment of interest and penalties	3	2	1
(Reduction) increase reserve for uncertain tax positions related to the current year	11	$ 58	$ 2
U.S.
Income Tax [Line Items]
Operating loss carryforwards	8,859
Operating loss carryforwards subject to annual limitation	186
Capital losses	$ 1,800
Capital loss carryforward carryover period	5 years
Canada
Income Tax [Line Items]
Capital losses	$ 836

INCOME TAXES - Summary of Valua

INCOME TAXES - Summary of Valuation Allowance Against Certain Foreign Net Deferred Tax Assets and State Net Operating Losses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Balance at beginning of year	$ 4,959	$ 3,947	$ 3,816
State	67	41	15
U.S.	960	971	124
Foreign	5	0	(8)
Balance at end of year	$ 5,991	$ 4,959	$ 3,947

INCOME TAXES - Net Operating Lo

INCOME TAXES - Net Operating Losses (Details) $ in Millions	Dec. 31, 2020USD ($)
U.S.
Schedule Of Income Tax [Line Items]
Net operating losses	$ 8,859
State
Schedule Of Income Tax [Line Items]
Net operating losses	$ 6,566

INCOME TAXES - Schedule of Fore

INCOME TAXES - Schedule of Foreign Tax Credit Carryforward (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Foreign tax credit carryforward, amount	$ 2,241	$ 2,241

INCOME TAXES - Reconciliation_2

INCOME TAXES - Reconciliation of Beginning and Ending Amount of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of year	$ 93	$ 82	$ 24	$ 26
Additions based on tax positions related to prior year	0	49	0
Additions based on tax positions related to the current year	11	9	0
Reductions for tax positions of prior years	0	0	(2)
Balance at end of year	$ 93	$ 82	$ 24	$ 26

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Additional Information (Details) $ in Millions

Sep. 10, 2020defendant

Sep. 11, 2019USD ($)plaintiff

Dec. 20, 2017Action

Jul. 17, 2017Actiondefendant

Mar. 21, 2016USD ($)

Mar. 20, 2016USD ($)

Dec. 31, 2020USD ($)Action

Dec. 31, 2019USD ($)

Dec. 31, 2018USD ($)

Dec. 31, 2013USD ($)

Aug. 03, 2020USD ($)

Dec. 31, 2017AUD ($)

Apr. 30, 2017AUD ($)

Mar. 12, 2014USD ($)

Commitment And Contingencies [Line Items]

Accrued liability for legal contingencies

$ 70,000,000

Environmental tax and royalty obligations

$ 100,000,000

Retain right of obligations

45,000,000

Number of plaintiffs | plaintiff

4

Maximum cost considered to be recognized for additional reserve

300,000

Undiscounted reserve for environmental remediation

2,000,000

Standby loan agreed to provide related to ARO

$ 400,000,000

Fixed operating lease expenses

149,000,000

$ 222,000,000

Short-term lease expense

80,000,000

18,000,000

Financing costs, net

267,000,000

462,000,000

$ 478,000,000

Variable lease payment

41,000,000

78,000,000

Assets Held Under Finance Leases

Commitment And Contingencies [Line Items]

Depreciation

2,000,000

7,000,000

Financing costs, net

2,000,000

$ 3,000,000

Apollo Exploration Lawsuit

Commitment And Contingencies [Line Items]

Loss contingency damages sought value

$ 200,000,000

Canadian Operations Divestiture Dispute

Commitment And Contingencies [Line Items]

Loss contingency punitive damages

$ 60,000,000

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

Castex Lawsuit

Commitment And Contingencies [Line Items]

Loss contingency damages sought value

200,000,000

Loss contingency estimate of possible loss

60,000,000

Oklahoma Class Actions

Commitment And Contingencies [Line Items]

Loss contingency damages sought value

$ 250,000,000

Number of actions filed | Action

2

Apache Australia Operation | Australian Operations Divestiture Dispute

Commitment And Contingencies [Line Items]

Gain contingency, unrecorded amount

$ 80

Loss contingency estimate of possible loss

$ 200

Gulf Of Mexico Shelf Operations And Properties | Disposal Group, Disposed of by Sale, Not Discontinued Operations

Commitment And Contingencies [Line Items]

Proceeds from sale of operations and properties

$ 3,750,000,000

Discounted asset abandonment liabilities assumed

$ 1,500,000,000

Percentage of net profits interest for funding trust account

10.00%

Minimum | Apollo Exploration Lawsuit

Commitment And Contingencies [Line Items]

Loss contingency damages sought value

$ 1,100,000,000

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - Company's Weighted Average Lease Term and Discount Rate related to Leases (Details)	Dec. 31, 2020
Accounting Policies [Abstract]
Operating leases, weighted average remaining lease term	3 years 8 months 12 days
Finance leases, weighted average remaining lease term	12 years 8 months 12 days
Operating leases, weighted average discount rate	4.20%
Finance leases, weighted average discount rate	4.40%

COMMITMENTS AND CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES - Schedule of Future Minimum Lease Payments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Leases
2021	$ 120
2022	70
2023	33
2024	27
2025	7
Thereafter	25
Total future minimum payments	282
Less: imputed interest	(21)
Total lease liabilities	261
Current portion	116	$ 169
Non-current portion	145
Finance Leases
2021	3
2022	3
2023	3
2024	4
2025	4
Thereafter	29
Total future minimum payments	46
Less: imputed interest	(8)
Total lease liabilities	38	48
Current portion	2
Non-current portion	36
Purchase Obligations
2021	236
2022	203
2023	203
2024	160
2025	159
Thereafter	600
Total future minimum payments	1,561
Total costs under take or pay and throughout obligation	$ 120	$ 111	$ 132
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	us-gaap:DeferredCostsAndOtherAssets	us-gaap:DeferredCostsAndOtherAssets
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:OtherLiabilitiesCurrent	us-gaap:OtherLiabilitiesCurrent
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:OtherLiabilitiesNoncurrent	us-gaap:OtherLiabilitiesNoncurrent

COMMITMENTS AND CONTINGENCIES_4

COMMITMENTS AND CONTINGENCIES - Schedule of ASU Leases (Topic 840) disclosures for prior periods (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Operating Leases
2019	$ 61
2020-2021	64
2022-2023	53
2024 & Beyond	42
Total	220
Finance Leases
2019	1
2020-2021	3
2022-2023	4
2024 & Beyond	32
Total	40
Net rental expenses	$ 76
Capital leases imputed interest rate	4.40%
Capital lease imputed interest rate amount	$ 16

RETIREMENT AND DEFERRED COMPE_3

RETIREMENT AND DEFERRED COMPENSATION PLANS - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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	$ 43	$ 52	$ 52
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	$ 207	$ 181	$ 167
Expected contribution towards pension and postretirement plan	5
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected contribution towards pension and postretirement plan	$ 2

RETIREMENT AND DEFERRED COMPE_4

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Change in Plan Assets
Fair value of plan assets at beginning of year	$ 228
Fair value of plan assets at end of year	262	$ 228
Pension Benefits
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	199	187	$ 216
Service cost	3	3	4
Interest cost	4	5	5
Foreign currency exchange rates	8	7	(11)
Actuarial losses (gains)	30	15	(11)
Plan settlements	0	(14)	(11)
Benefits paid	(11)	(4)	(5)
Retiree contributions	0	0	0
Projected benefit obligation at end of year	233	199	187
Change in Plan Assets
Fair value of plan assets at beginning of year	228	208	238
Actual return on plan assets	31	25	(6)
Foreign currency exchange rates	9	8	(13)
Employer contributions	5	5	5
Plan settlements	0	(14)	(11)
Benefits paid	(11)	(4)	(5)
Retiree contributions	0	0	0
Fair value of plan assets at end of year	262	228	208
Funded status at end of year	29	29	21
Amounts recognized in Consolidated Balance Sheet
Current liability	0	0	0
Non-current asset	29	29	21
Amounts recognized in Consolidated Balance Sheet	29	29	21
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$ (11)	$ (7)	$ (13)
Weighted Average Assumptions used as of December 31
Discount rate	1.40%	2.10%	2.90%
Salary increases	4.50%	4.30%	4.70%
Expected return on assets	2.20%	2.20%	2.80%
Postretirement Benefits
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	$ 20	$ 27	$ 27
Service cost	1	2	2
Interest cost	0	1	1
Foreign currency exchange rates	0	0	0
Actuarial losses (gains)	1	(9)	(2)
Plan settlements	0	0	0
Benefits paid	(4)	(2)	(3)
Retiree contributions	2	1	2
Projected benefit obligation at end of year	20	20	27
Change in Plan Assets
Fair value of plan assets at beginning of year	0	0	0
Actual return on plan assets	0	0	0
Foreign currency exchange rates	0	0	0
Employer contributions	2	1	2
Plan settlements	0	0	0
Benefits paid	(4)	(2)	(4)
Retiree contributions	2	1	2
Fair value of plan assets at end of year	0	0	0
Funded status at end of year	(20)	(20)	(27)
Amounts recognized in Consolidated Balance Sheet
Current liability	(2)	(2)	(2)
Non-current liability	(18)	(18)	(25)
Amounts recognized in Consolidated Balance Sheet	(20)	(20)	(27)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$ 16	$ 19	$ 10
Weighted Average Assumptions used as of December 31
Discount rate	2.06%	3.00%	4.13%
Healthcare cost trend
Initial	6.00%	6.25%	6.50%
Ultimate in 2025	5.00%	5.00%	5.00%

RETIREMENT AND DEFERRED COMPE_5

RETIREMENT AND DEFERRED COMPENSATION PLANS - Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset (Details)	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	100.00%
Percentage of Plan Assets at Year-End	100.00%	100.00%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	19.00%
Percentage of Plan Assets at Year-End	19.00%	23.00%
Overseas quoted equities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	19.00%
Percentage of Plan Assets at Year-End	19.00%	23.00%
Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	81.00%
Percentage of Plan Assets at Year-End	80.00%	77.00%
U.K. government bonds
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	65.00%
Percentage of Plan Assets at Year-End	64.00%	62.00%
U.K. corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	16.00%
Percentage of Plan Assets at Year-End	16.00%	15.00%
Cash
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	0.00%
Percentage of Plan Assets at Year-End	1.00%	0.00%

RETIREMENT AND DEFERRED COMPE_6

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, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 262	$ 228
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	49	52
Overseas quoted equities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	49	52
Debt securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	211	175
U.K. government bonds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	168	140
U.K. corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	43	35
Cash
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 2	$ 1

RETIREMENT AND DEFERRED COMPE_7

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Salary increases	4.30%	4.70%	4.70%
Expected return on assets	2.20%	2.80%	2.90%
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 3	$ 3	$ 4
Interest cost	4	5	5
Expected return on assets	(5)	(5)	(7)
Amortization of gain	0	0	0
Settlement loss	0	0	1
Net periodic benefit cost	$ 2	$ 3	$ 3
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	2.10%	2.90%	2.60%
Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 1	$ 2	$ 2
Interest cost	0	1	1
Expected return on assets	0	0	0
Amortization of gain	(1)	(1)	0
Settlement loss	0	0	0
Net periodic benefit cost	$ 0	$ 2	$ 3
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	3.00%	4.13%	3.44%
Healthcare cost trend
Initial	6.25%	6.50%	6.75%
Ultimate in 2025	5.00%	5.00%	5.00%

RETIREMENT AND DEFERRED COMPE_8

RETIREMENT AND DEFERRED COMPENSATION PLANS - Expected Future Benefit Payment (Details) $ in Millions	Dec. 31, 2020USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2021	$ 5
2022	6
2023	7
2024	6
2025	6
Years 2026-2030	36
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2021	2
2022	2
2023	2
2024	2
2025	2
Years 2026-2030	$ 6

REDEMABLE NONCONTROLLING INTE_3

REDEMABLE NONCONTROLLING INTEREST - ALTUS - Additional Information (Details) $ in Millions	Jun. 12, 2019USD ($)qtr	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Class of Stock [Line Items]
Redeemable noncontrolling interest - Altus Preferred Unit limited partners		$ 0	$ 611	$ 0
Altus Midstream LP
Class of Stock [Line Items]
Preferred Units, redemption terms, internal rate of return		11.50%
Preferred Units embedded derivative	$ 94	$ 139
Altus Midstream LP | Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners
Class of Stock [Line Items]
Aggregate issue price of Preferred Units	625
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	$ 611
Preferred Units, quarterly distribution rate per annum	7.00%
Preferred Units, increased quarterly distribution rate per annum upon specified events	10.00%
Preferred Units, distribution in-kind, number of quarters after issuance | qtr	6
Preferred Units, redemption terms, internal rate of return	11.50%
Preferred Units, redemption terms, internal rate of return after fifth anniversary of closing	13.75%
Preferred Units, redemption terms, multiple of invested capital	1.3	1.3
Preferred Units, exchangeable, number of preceding trading days	20 days
Preferred Units, exchangeable, discount percentage	6.00%
Maximum amount of distributions to common unit holders	$ 650
Issue discount	4
Transaction costs	10
Preferred Units embedded derivative	$ 94

REDEMABLE NONCONTROLLING INTE_4

REDEMABLE NONCONTROLLING INTEREST - ALTUS - Schedule of Preferred Units (Details) - Altus Midstream LP - USD ($) $ in Millions	Dec. 31, 2020	Jun. 12, 2019
Class of Stock [Line Items]
Preferred Units embedded derivative	$ 139	$ 94
Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners
Class of Stock [Line Items]
Redeemable noncontrolling interest - Altus Preferred Unit limited partners		517
Preferred Units embedded derivative		94
Transaction price, net		$ 611

REDEMABLE NONCONTROLLING INTE_5

REDEMABLE NONCONTROLLING INTEREST - ALTUS - Activity Related to Preferred Units (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Jun. 12, 2019
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance	$ 555
Ending balance	608	$ 555
Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance	555	0
Issuance of Altus Preferred Units		517
Allocation of Altus Midstream LP net income	76	38
Ending balance	608	$ 555
Altus Midstream LP
Increase (Decrease) in Temporary Equity [Roll Forward]
Preferred Units embedded derivative	139		$ 94
Redeemable noncontrolling interest, net of embedded derivative liability	$ 747
Preferred Units, redemption terms, internal rate of return	11.50%
Preferred units, invested capital	$ 813
Preferred units, redemption price	$ 717
Altus Midstream LP | Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners
Movement In Preferred Units [Roll Forward]
Preferred Units: beginning of period (in shares)	638,163	0
Issuance of Preferred Units, net (in shares)		625,000
Distribution of in-kind additional Preferred Units (in shares)	22,531	13,163
Cash distributions to Altus Preferred Unit limited partners (in shares)	0
Preferred Units: end of period (in shares)	660,694	638,163
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance	$ 555	$ 0
Issuance of Altus Preferred Units		517
Distribution of in-kind additional Preferred Units	0	0
Cash distributions to Altus Preferred Unit limited partners	(23)
Allocation of Altus Midstream LP net income	76	38
Ending balance	$ 608	$ 555
Preferred Units embedded derivative			$ 94
Preferred Units, redemption terms, internal rate of return			11.50%
Preferred Units, redemption terms, multiple of invested capital	1.3		1.3

CAPITAL STOCK - Common Stock Ou

CAPITAL STOCK - Common Stock Outstanding (Details) - shares	12 Months Ended			91 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2020
Movement In Common Stock Outstanding [Roll Forward]
Balance, beginning of year (in shares)	376,062,670	374,696,222	380,954,864
Shares issued for stock-based compensation plans:
Treasury shares issued (in shares)	17,448	31,701	2,454
Common shares issued (in shares)	1,402,512	1,334,747	1,566,237
Treasury shares acquired (in shares)	0	0	(7,827,333)	(40,000,000)
Balance, end of year (in shares)	377,482,630	376,062,670	374,696,222	377,482,630

CAPITAL STOCK - Net Income Per

CAPITAL STOCK - Net Income Per Common Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Basic:
Net loss attributable to common stock	$ (4,860)	$ (3,553)	$ 40
Weighted average number of shares outstanding, basic (in shares)	378	377	382
Basic net income (loss) per share (in USD per share)	$ (12.86)	$ (9.43)	$ 0.11
Effect of Dilutive Securities:
Stock options and other, shares (in shares)	0	0	2
Stock options and other, per share (in USD per share)	$ 0	$ 0	$ 0
Diluted:
Income (loss) attributable to common stock	$ (4,860)	$ (3,553)	$ 40
Weighted average number of shares outstanding, diluted (in shares)	378	377	384
Diluted net income (loss) per share (in USD per share)	$ (12.86)	$ (9.43)	$ 0.11

CAPITAL STOCK - Additional Info

CAPITAL STOCK - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended			91 Months Ended
	Jan. 31, 2021	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2020	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options and restricted stock, anti-dilutive (in shares)			4,500,000	5,000,000	5,600,000
Common stock share purchase, shares (in shares)					40,000,000		40,000,000	40,000,000
Treasury shares acquired (in shares)			0	0	7,827,333	40,000,000
Common stock share repurchase price (in USD per share)						$ 79.18
Common stock, quarterly dividend (in USD per share)		$ 0.025		$ 0.25
Common stock, dividends, per share (in USD per share)			$ 0.10	$ 1	$ 1
Shares authorized and available for grant (in shares)			14,100,000			14,100,000
Shares Issued in the period (in shares)			0	0
Shares exercised in the period (in shares)			0	0	(29,000)
Intrinsic value of options exercised					$ 0.1
Stock-settled and cash-settled compensation expensed			$ 40	$ 110	157
Stock-settled and cash-settled compensation capitalized			7	28	37
Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation cost related to non-vested awards not yet recognized			0			$ 0
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation cost related to non-vested awards not yet recognized			14			14
Stock-settled and cash-settled compensation expensed			39	104	101
Stock-settled and cash-settled compensation capitalized			$ 6	$ 24	$ 29
Awards granted during period (in shares)			1,352,000	1,479,000	608,000
Weighted average grant date fair value per share (in USD per share)			$ 24.60	$ 36.81	$ 45.59
Restricted Stock | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period in which stock options become exercisable	3 years
Total compensation cost related to non-vested awards not yet recognized	$ 22
Awards granted during period (in shares)	1,354,349
Weighted average grant date fair value per share (in USD per share)	$ 16.18
Restricted Stock | Subsequent Event | ALTM
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value per share (in USD per share)	$ 48.84
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation cost related to non-vested awards not yet recognized			$ 28			$ 28
Awards granted during period (in shares)			3,462,000	4,831,000	1,973,000
Phantom Units | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation cost related to non-vested awards not yet recognized	$ 71
Awards granted during period (in shares)	4,360,656
Phantom Units | Subsequent Event | ALTM
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation cost related to non-vested awards not yet recognized	$ 3
Awards granted during period (in shares)	56,836
In or after 2016 | 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

CAPITAL STOCK - Description of

CAPITAL STOCK - Description of Stock Based Compensation Plans and Related Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Equity [Abstract]
Stock-settled and cash-settled compensation expensed	$ 40	$ 110	$ 157
Stock-settled and cash-settled compensation capitalized	7	28	37
Total stock-settled and cash-settled compensation costs	$ 47	$ 138	$ 194

CAPITAL STOCK - Summary of Stoc

CAPITAL STOCK - Summary of Stock Options Activities (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding, beginning of year, Shares (in shares)	4,298,000	4,872,000	4,593,000
Granted, Shares (in shares)	0	0	812,000
Exercised, Shares (in shares)	0	0	(29,000)
Forfeited, Shares (in shares)	(37,000)	(80,000)	(121,000)
Expired, Shares (in shares)	(724,000)	(494,000)	(383,000)
Outstanding, end of year, Shares (in shares)	3,537,000	4,298,000	4,872,000
Expected to vest, Shares (in shares)	150,000	495,000	1,274,000
Exercisable, end of year, Shares (in shares)	3,387,000	3,803,000	3,598,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Outstanding, beginning of year, weighted average exercise price (in USD per share)	$ 75.24	$ 75.95	$ 83.36
Granted, weighted average exercise price (in USD per share)	0	0	45.93
Exercised, weighted average exercise price (in USD per share)	0	0	41.79
Forfeited, weighted average exercise price (in USD per share)	44.98	34.58	74.58
Expired, weighted average exercise price (in USD per share)	92.14	88.82	104.21
Outstanding, end of year, weighted average exercise price (in USD per share)	72.10	75.24	75.95
Expected to vest, weighted average exercise price (in USD per share)	45.77	49.11	48.74
Exercisable, end of year, weighted average exercise price (in USD per share)	$ 73.26	$ 78.64	$ 85.59
Weighted average remaining contractual life for options outstanding	3 years 7 months 6 days
Aggregate intrinsic value for options outstanding	$ 0
Weighted average remaining contractual life for expected to vest	7 years
Aggregate intrinsic value for expected to vest	$ 0
Weighted average remaining contractual life for exercisable	3 years 4 months 24 days
Aggregate intrinsic value for exercisable	$ 0

CAPITAL STOCK - Schedule of Ass

CAPITAL STOCK - Schedule of Assumptions Used (Details) - Stock Option	12 Months Ended
	Dec. 31, 2018$ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected volatility	33.74%
Expected dividend yields	2.16%
Expected term (in years)	6 years
Risk-free rate	2.42%
Weighted-average grant-date fair value (in USD per share)	$ 13.15

CAPITAL STOCK - Schedule of Res

CAPITAL STOCK - Schedule of Restricted Stock Activities (Details) $ / shares in Units, $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2020$ / sharesshares	Dec. 31, 2020USD ($)$ / sharesshares	Dec. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares
Weighted Average  Grant-Date  Fair Value
Total fair value of restricted stock awards vested | $		$ 94	$ 103	$ 111
Altus Midstream LP
Weighted Average  Grant-Date  Fair Value
Reverse stock split ratio	0.05
Restricted Stock
Units
Non-vested, beginning balance (in shares)	2,448,000	2,448,000	3,153,000	4,920,000
Granted, Shares (in shares)		1,352,000	1,479,000	608,000
Vested, Shares (in shares)		(1,933,000)	(1,899,000)	(2,023,000)
Forfeited, Shares (in shares)		(315,000)	(285,000)	(352,000)
Non-vested, ending balance (in shares)		1,552,000	2,448,000	3,153,000
Weighted Average  Grant-Date  Fair Value
Non-vested Beginning Balance, Weighted Average Grant Date Fair Value (in USD per share) | $ / shares	$ 46.65	$ 46.65	$ 55.54	$ 56.67
Granted, Weighted Average Grant-Date Fair Value (in USD per share) | $ / shares		24.60	36.81	45.59
Vested, Weighted Average Grant-Date Fair Value (in USD per share) | $ / shares		48.65	53.99	55.10
Forfeited, Weighted Average Grant-Date Fair Value (in USD per share) | $ / shares		30.09	45.06	56.69
Non-vested Ending Balance, Weighted Average Grant Date Fair Value (in USD per share) | $ / shares		$ 28.43	$ 46.65	$ 55.54
Total compensation cost related to non-vested awards not yet recognized | $		$ 14
Unvested restricted stock units (in shares)		1,551,807
Weighted-average remaining life of unvested restricted stock units		8 months 12 days
Phantom Units
Units
Non-vested, beginning balance (in shares)	5,384,000	5,384,000	1,818,000	59,000
Reverse stock split (in shares)		(1,246,000)	0	0
Granted, Shares (in shares)		3,462,000	4,831,000	1,973,000
Vested, Shares (in shares)		(1,618,000)	(616,000)	(38,000)
Forfeited, Shares (in shares)		(1,559,000)	(649,000)	(176,000)
Non-vested, ending balance (in shares)		4,423,000	5,384,000	1,818,000
Weighted Average  Grant-Date  Fair Value
Total compensation cost related to non-vested awards not yet recognized | $		$ 28
Phantom Units Issued Based on Per-Share Market Price of Apache Common Stock
Units
Granted, Shares (in shares)		3,378,486	3,401,477
Phantom Units Issued Based on Per-Share Market Price of ALTM Common Stock
Units
Granted, Shares (in shares)		83,239	1,429,135

CAPITAL STOCK - Performance Pro

CAPITAL STOCK - Performance Program Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended					12 Months Ended
	Jan. 31, 2021	Jan. 31, 2020	Jan. 31, 2019	Jan. 31, 2018	Jan. 31, 2017	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)						14,100,000
Compensation expense						$ 40	$ 110	$ 157
Stock-settled and cash-settled compensation capitalized						$ 7	$ 28	$ 37
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)						3,462,000	4,831,000	1,973,000
Phantom Units | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	4,360,656
Performance Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares allocation percentage						50.00%
Shares vesting period						3 years
Compensation expense						$ 8	$ 24	$ 38
Stock-settled and cash-settled compensation capitalized						$ 1	$ 3	$ 7
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%
2017 Performance Program | Conditional Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)					620,885
Shares paid out as percentage of target						54.00%
Total awards, outstanding (in shares)						111,126
2018 Performance Program | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)				931,049
Shares paid out as percentage of target						23.00%
Total awards, outstanding (in shares)						704,483
2019 Performance Program | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)			1,679,832
Total awards, outstanding (in shares)						1,301,893
2019 Performance Program | Phantom Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares awarded of target			0.00%
Shares authorized and available for grant (in shares)		0
2019 Performance Program | Phantom Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares awarded of target			200.00%
Shares authorized and available for grant (in shares)			2,603,786
2020 Performance Program | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)		1,687,307
Total awards, outstanding (in shares)						1,410,404
2020 Performance Program | Phantom Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares awarded of target		0.00%
Shares authorized and available for grant (in shares)		0
2020 Performance Program | Phantom Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares awarded of target		200.00%
Shares authorized and available for grant (in shares)		2,820,808
2021 Performance Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares allocation percentage						50.00%
2021 Performance Program | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares allocation percentage	50.00%
Shares vesting period	3 years
Shares vesting percentage	50.00%
2021 Performance Program | Phantom Units | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Initial number of share to be awarded	1,911,517
2021 Performance Program | Phantom Units | Monte Carlo Simulation | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value per share (in USD per share)	$ 23.73
2021 Performance Program | Phantom Units | Fair Market Value At Grant Date | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares allocation percentage	50.00%
Weighted average grant date fair value per share (in USD per share)	$ 16.18
2021 Performance Program | Phantom Units | Minimum | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ultimate number of share to be awarded	0
2021 Performance Program | Phantom Units | Maximum | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ultimate number of share to be awarded	3,823,034

CAPITAL STOCK - Schedule of Per

CAPITAL STOCK - Schedule of Performance Program Activities (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Weighted Average  Grant-Date  Fair Value
Expired, weighted average exercise price (in USD per share)	$ 92.14	$ 88.82	$ 104.21
Employee-related liabilities, current	$ 170	$ 212
Performance Program | Stock-settled conditional restricted stock unit
Units
Non-vested, beginning balance (in shares)	781,000
Granted, Shares (in shares)	18,000
Vested, Shares (in shares)	(445,000)
Forfeited, Shares (in shares)	(16,000)
Expired, Shares (in shares)	(227,000)
Non-vested, ending balance (in shares)	111,126	781,000
Weighted Average  Grant-Date  Fair Value
Non-vested Beginning Balance, Weighted Average Grant Date Fair Value (in USD per share)	$ 52.69
Granted, Weighted Average Grant-Date Fair Value (in USD per share)	62.31
Vested, Weighted Average Grant-Date Fair Value (in USD per share)	41.10
Forfeited, Weighted Average Grant-Date Fair Value (in USD per share)	56.66
Expired, weighted average exercise price (in USD per share)	70.70
Non-vested Ending Balance, Weighted Average Grant Date Fair Value (in USD per share)	$ 63.15	$ 52.69
Fair value of restricted stock, risk-free interest rate, period	3 years
Total compensation cost related to non-vested awards not yet recognized	$ 0
Weighted-average remaining life of unvested restricted stock units	0 years
Performance Program | Cash-settled conditional restricted stock unit
Units
Non-vested, beginning balance (in shares)	2,320,000
Granted, Shares (in shares)	1,687,000
Vested, Shares (in shares)	(2,000)
Forfeited, Shares (in shares)	(542,000)
Expired, Shares (in shares)	(46,000)
Non-vested, ending balance (in shares)	3,417,000	2,320,000
Weighted Average  Grant-Date  Fair Value
Employee-related liabilities, current	$ 14

ACCUMULATED OTHER COMPREHENSI_3

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Equity [Abstract]
Share of equity method interests other comprehensive loss	$ (1)	$ (1)	$ 0
Pension and postretirement benefit plan (Note 12)	15	17	4
Accumulated other comprehensive income	$ 14	$ 16	$ 4

MAJOR CUSTOMERS (Details)

MAJOR CUSTOMERS (Details) - Customer Concentration Risk - Oil and Gas Production Revenues	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Egyptian General Petroleum Corporation
Revenue, Major Customer [Line Items]
Concentration risk percentage	17.00%		10.00%
Vitol
Revenue, Major Customer [Line Items]
Concentration risk percentage	14.00%
BP plc
Revenue, Major Customer [Line Items]
Concentration risk percentage		10.00%	17.00%
China Petroleum & Chemical Corporation (Sinopec)
Revenue, Major Customer [Line Items]
Concentration risk percentage		11.00%	15.00%

BUSINESS SEGMENT INFORMATION -

BUSINESS SEGMENT INFORMATION - Additional Information (Details)	12 Months Ended
	Dec. 31, 2020Segment
Segment Reporting [Abstract]
Number of reporting segments	3

BUSINESS SEGMENT INFORMATION _2

BUSINESS SEGMENT INFORMATION - Financial Segment Information (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Expenses:
Lease operating expenses		$ 1,127	$ 1,447	$ 1,439
Taxes other than income		123	207	215
Exploration		274	805	503
Depreciation, depletion, and amortization		1,772	2,680	2,405
Asset retirement obligation accretion		109	107	108
Impairments	$ 1,400	4,501	2,949	511
Total operating expenses		8,537	8,643	5,869
Operating Income (Loss)		(4,102)	(2,152)	1,836
Other Income (Expense):
Gain on divestitures, net		32	43	23
Derivative instrument losses, net		(223)	(35)	(17)
Other		64	54	53
General and administrative		(290)	(406)	(431)
Transaction, reorganization, and separation		(54)	(50)	(28)
Financing costs, net		(267)	(462)	(478)
NET INCOME (LOSS) BEFORE INCOME TAXES		(4,840)	(3,008)	958
Total assets	18,107	12,746	18,107	21,582
Net Property and Equipment	14,158	8,819	14,158	18,421
Additions to Net Property and Equipment	2,734	1,162	2,734	3,914
Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil and gas production revenues		0	0	0
Operating Expenses:
Lease operating expenses		424	484	428
Taxes other than income		0	0	0
Exploration		63	100	88
Depreciation, depletion, and amortization		601	708	745
Asset retirement obligation accretion		0	0	0
Impairments		529	0	63
Total operating expenses		1,655	1,332	1,371
Operating Income (Loss)		(265)	944	1,377
Other Income (Expense):
Total assets	3,700	3,003	3,700	4,260
Net Property and Equipment	2,573	1,955	2,573	2,856
Additions to Net Property and Equipment	454	454	454	594
Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil and gas production revenues		0	0	0
Operating Expenses:
Lease operating expenses		305	320	341
Taxes other than income		0	0	0
Exploration		28	2	192
Depreciation, depletion, and amortization		380	366	375
Asset retirement obligation accretion		73	76	75
Impairments		7	0	10
Total operating expenses		843	809	1,035
Operating Income (Loss)		40	467	286
Other Income (Expense):
Total assets	2,473	2,220	2,473	2,456
Net Property and Equipment	1,956	1,773	1,956	2,148
Additions to Net Property and Equipment	183	215	183	223
Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil and gas production revenues		0	0	0
Operating Expenses:
Lease operating expenses		400	645	670
Taxes other than income		108	194	207
Exploration		168	688	219
Depreciation, depletion, and amortization		779	1,566	1,266
Asset retirement obligation accretion		32	29	32
Impairments		3,963	1,648	438
Total operating expenses		6,095	5,211	3,454
Operating Income (Loss)		(3,937)	(2,272)	182
Other Income (Expense):
Total assets	10,388	5,540	10,388	12,962
Net Property and Equipment	9,385	4,760	9,385	12,145
Additions to Net Property and Equipment	1,696	345	1,696	2,544
Operating Segments | Altus Midstream
Segment Reporting Information [Line Items]
Oil and gas production revenues		145	136	77
Operating Expenses:
Lease operating expenses		0	0	0
Taxes other than income		15	13	8
Exploration		0	0	0
Depreciation, depletion, and amortization		12	40	19
Asset retirement obligation accretion		4	2	1
Impairments		2	1,301	0
Total operating expenses		74	1,412	82
Operating Income (Loss)		75	(1,276)	(5)
Other Income (Expense):
Total assets	1,479	1,786	1,479	1,857
Net Property and Equipment	206	196	206	1,227
Additions to Net Property and Equipment	308	12	308	545
Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil and gas production revenues		(145)	(136)	(77)
Operating Expenses:
Lease operating expenses		(2)	(2)	0
Taxes other than income		0	0	0
Exploration		15	15	4
Depreciation, depletion, and amortization		0	0	0
Asset retirement obligation accretion		0	0	0
Impairments		0	0	0
Total operating expenses		(130)	(121)	(73)
Operating Income (Loss)		(15)	(15)	(4)
Other Income (Expense):
Total assets	67	197	67	47
Net Property and Equipment	38	135	38	45
Additions to Net Property and Equipment	$ 93	136	93	8
Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Oil and gas production revenues		4,037	6,315	7,348
Operating Expenses:
Gathering, processing, and transmission		274	306	348
Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil and gas production revenues		1,390	2,276	2,748
Operating Expenses:
Gathering, processing, and transmission		38	40	47
Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil and gas production revenues		883	1,276	1,321
Operating Expenses:
Gathering, processing, and transmission		50	45	42
Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil and gas production revenues		1,764	2,763	3,279
Operating Expenses:
Gathering, processing, and transmission		291	299	282
Oil and gas, excluding purchased | Operating Segments | Altus Midstream
Segment Reporting Information [Line Items]
Oil and gas production revenues		0	0	0
Operating Expenses:
Gathering, processing, and transmission		38	56	54
Oil and gas, excluding purchased | Intersegment Eliminations & Other
Operating Expenses:
Gathering, processing, and transmission		(143)	(134)	(77)
Oil and gas, purchased
Segment Reporting Information [Line Items]
Oil and gas production revenues		398	176	357
Operating Expenses:
Gathering, processing, and transmission		357	142	340
Oil and gas, purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil and gas production revenues		0	0	0
Operating Expenses:
Gathering, processing, and transmission		0	0	0
Oil and gas, purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil and gas production revenues		0	0	0
Operating Expenses:
Gathering, processing, and transmission		0	0	0
Oil and gas, purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil and gas production revenues		394	176	357
Operating Expenses:
Gathering, processing, and transmission		354	142	340
Oil and gas, purchased | Operating Segments | Altus Midstream
Segment Reporting Information [Line Items]
Oil and gas production revenues		4	0	0
Operating Expenses:
Gathering, processing, and transmission		3	0	0
Oil and gas, purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil and gas production revenues		0	0	0
Operating Expenses:
Gathering, processing, and transmission		0	0	0
Oil and gas
Segment Reporting Information [Line Items]
Oil and gas production revenues		4,435	6,491	7,705
Oil and gas | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil and gas production revenues		1,390	2,276	2,748
Oil and gas | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil and gas production revenues		883	1,276	1,321
Oil and gas | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil and gas production revenues		2,158	2,939	3,636
Oil and gas | Operating Segments | Altus Midstream
Segment Reporting Information [Line Items]
Oil and gas production revenues		149	136	77
Oil and gas | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil and gas production revenues		(145)	(136)	(77)
Oil
Other Income (Expense):
Revenue from non-customers		95	410	592
Oil | Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Oil and gas production revenues		3,106	5,230	5,846
Oil | Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil and gas production revenues		1,102	1,969	2,396
Oil | Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil and gas production revenues		795	1,163	1,179
Oil | Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil and gas production revenues		1,209	2,098	2,271
Oil | Oil and gas, excluding purchased | Operating Segments | Altus Midstream
Segment Reporting Information [Line Items]
Oil and gas production revenues		0	0	0
Oil | Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil and gas production revenues		0	0	0
Natural Gas
Other Income (Expense):
Revenue from non-customers		14	40	58
Natural Gas | Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Oil and gas production revenues		598	678	919
Natural Gas | Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil and gas production revenues		280	295	339
Natural Gas | Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil and gas production revenues		67	90	122
Natural Gas | Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil and gas production revenues		251	293	458
Natural Gas | Oil and gas, excluding purchased | Operating Segments | Altus Midstream
Segment Reporting Information [Line Items]
Oil and gas production revenues		0	0	0
Natural Gas | Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil and gas production revenues		0	0	0
Natural Gas Liquids
Other Income (Expense):
Revenue from non-customers		0	1	2
Natural Gas Liquids | Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Oil and gas production revenues		333	407	583
Natural Gas Liquids | Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil and gas production revenues		8	12	13
Natural Gas Liquids | Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil and gas production revenues		21	23	20
Natural Gas Liquids | Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil and gas production revenues		304	372	550
Natural Gas Liquids | Oil and gas, excluding purchased | Operating Segments | Altus Midstream
Segment Reporting Information [Line Items]
Oil and gas production revenues		0	0	0
Natural Gas Liquids | Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil and gas production revenues		$ 0	$ 0	$ 0

SUPPLEMENTAL OIL AND GAS DISC_3

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Asset retirement obligation accretion	$ 109	$ 107	$ 108
Lease operating expenses	1,127	1,447	1,439
Oil and Gas, Exploration and Production
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	4,037	6,315	7,348
Depreciation, depletion, and amortization	1,643	2,512	2,265
Asset retirement obligation accretion	105	105	107
Lease operating expenses	1,129	1,449	1,439
Gathering, processing, and transmission	379	384	371
Exploration expenses	274	805	503
Impairments related to oil and gas properties	4,319	1,633	338
Production taxes	106	191	203
Income tax	(823)	175	848
Operating costs	7,132	7,254	6,074
Results of operations	(3,095)	(939)	1,274
Oil and Gas, Exploration and Production | United States
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	1,764	2,763	3,279
Depreciation, depletion, and amortization	726	1,508	1,206
Asset retirement obligation accretion	32	29	32
Lease operating expenses	400	645	670
Gathering, processing, and transmission	291	299	282
Exploration expenses	168	688	219
Impairments related to oil and gas properties	3,938	1,633	265
Production taxes	106	191	203
Income tax	(818)	(468)	87
Operating costs	4,843	4,525	2,964
Results of operations	(3,079)	(1,762)	315
Oil and Gas, Exploration and Production | Egypt
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	1,390	2,276	2,748
Depreciation, depletion, and amortization	540	641	688
Asset retirement obligation accretion	0	0	0
Lease operating expenses	424	484	428
Gathering, processing, and transmission	38	40	47
Exploration expenses	63	100	88
Impairments related to oil and gas properties	374	0	63
Production taxes	0	0	0
Income tax	(22)	455	645
Operating costs	1,417	1,720	1,959
Results of operations	(27)	556	789
Oil and Gas, Exploration and Production | North Sea
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	883	1,276	1,321
Depreciation, depletion, and amortization	377	363	371
Asset retirement obligation accretion	73	76	75
Lease operating expenses	305	320	341
Gathering, processing, and transmission	50	45	42
Exploration expenses	28	2	192
Impairments related to oil and gas properties	7	0	10
Production taxes	0	0	0
Income tax	17	188	116
Operating costs	857	994	1,147
Results of operations	26	282	174
Oil and Gas, Exploration and Production | 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	15	15	4
Impairments related to oil and gas properties	0	0	0
Production taxes	0	0	0
Income tax	0	0	0
Operating costs	15	15	4
Results of operations	$ (15)	$ (15)	$ (4)

SUPPLEMENTAL OIL AND GAS DISC_4

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	$ 7	$ 8	$ 6
Unproved	4	57	127
Exploration	328	468	940
Development	872	1,996	2,381
Costs incurred	1,211	2,529	3,454
Capitalized interest	3	32	36
Asset retirement costs	38	(97)	31
United States
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	0	3	0
Unproved	4	47	111
Exploration	8	162	640
Development	332	1,500	1,791
Costs incurred	344	1,712	2,542
Capitalized interest	0	23	23
Asset retirement costs	9	14	93
Egypt
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	7	5	6
Unproved	0	10	16
Exploration	102	139	175
Development	378	374	457
Costs incurred	487	528	654
Capitalized interest	0	0	0
Asset retirement costs	0	0	0
North Sea
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	0	0	0
Unproved	0	0	0
Exploration	68	62	113
Development	162	119	133
Costs incurred	230	181	246
Capitalized interest	0	5	11
Asset retirement costs	29	(111)	(62)
Other International
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	0	0	0
Unproved	0	0	0
Exploration	150	105	12
Development	0	3	0
Costs incurred	150	108	12
Capitalized interest	3	4	2
Asset retirement costs	$ 0	$ 0	$ 0

SUPPLEMENTAL OIL AND GAS DISC_5

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Reserve Quantities [Line Items]
Proved properties	$ 41,217	$ 40,540
Unproved properties	602	666
Capitalized costs, gross	41,819	41,206
Accumulated DD&A	(33,623)	(27,860)
Capitalized costs, net	8,196	13,346
United States
Reserve Quantities [Line Items]
Proved properties	20,343	20,291
Unproved properties	348	509
Capitalized costs, gross	20,691	20,800
Accumulated DD&A	(16,252)	(11,783)
Capitalized costs, net	4,439	9,017
Egypt
Reserve Quantities [Line Items]
Proved properties	12,069	11,614
Unproved properties	77	109
Capitalized costs, gross	12,146	11,723
Accumulated DD&A	(10,290)	(9,377)
Capitalized costs, net	1,856	2,346
North Sea
Reserve Quantities [Line Items]
Proved properties	8,805	8,635
Unproved properties	42	10
Capitalized costs, gross	8,847	8,645
Accumulated DD&A	(7,081)	(6,700)
Capitalized costs, net	1,766	1,945
Other International
Reserve Quantities [Line Items]
Proved properties	0	0
Unproved properties	135	38
Capitalized costs, gross	135	38
Accumulated DD&A	0	0
Capitalized costs, net	$ 135	$ 38

SUPPLEMENTAL OIL AND GAS DISC_6

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Oil and Gas Reserve Information (Details) MBoe in Thousands	12 Months Ended
	Dec. 31, 2020MBoeMBblsMMcf	Dec. 31, 2019MBoeMBblsMMcf	Dec. 31, 2018MBoeMMcfMBbls	Dec. 31, 2017MBoeMMcfMBbls
Reserve Quantities [Line Items]
Proved developed reserves	797,843	892,816	1,081,316	1,023,663
Proved undeveloped reserves	75,840	117,972	153,081	151,323
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	1,010,788	1,234,397	1,174,986
Extensions, discoveries and other additions	78,303	176,366	302,509
Purchases of minerals in-place			331
Revisions of previous estimates	(44,910)	(119,473)	(73,319)
Production	(160,945)	(172,948)	(170,051)
Sales of minerals in-place	(9,553)	(107,554)	(59)
Ending balance	873,683	1,010,788	1,234,397
United States
Reserve Quantities [Line Items]
Proved developed reserves	532,994	594,595	769,125	699,786
Proved undeveloped reserves	53,408	89,458	123,493	111,001
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	684,053	892,618	810,787
Extensions, discoveries and other additions	39,454	135,174	240,322
Purchases of minerals in-place			331
Revisions of previous estimates	(33,854)	(133,974)	(63,451)
Production	(93,698)	(102,211)	(95,312)
Sales of minerals in-place	(9,553)	(107,554)	(59)
Ending balance	586,402	684,053	892,618
Egypt
Reserve Quantities [Line Items]
Proved developed reserves	164,870	176,470	189,871	215,364
Proved undeveloped reserves	13,449	15,038	15,045	24,112
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	191,508	204,916	239,476
Extensions, discoveries and other additions	31,905	26,859	35,849
Purchases of minerals in-place			0
Revisions of previous estimates	(502)	8,355	(16,007)
Production	(44,592)	(48,622)	(54,402)
Sales of minerals in-place	0	0	0
Ending balance	178,319	191,508	204,916
North Sea
Reserve Quantities [Line Items]
Proved developed reserves	99,979	121,751	122,320	108,513
Proved undeveloped reserves	8,983	13,476	14,543	16,210
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	135,227	136,863	124,723
Extensions, discoveries and other additions	6,944	14,333	26,338
Purchases of minerals in-place			0
Revisions of previous estimates	(10,554)	6,146	6,139
Production	(22,655)	(22,115)	(20,337)
Sales of minerals in-place	0	0	0
Ending balance	108,962	135,227	136,863
Noncontrolling Interests | Egypt
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved developed reserves (Energy) | MBoe	59	64	68	80
Crude Oil and Condensate
Reserve Quantities [Line Items]
Proved developed reserves	389,483	483,430	514,989	521,445
Proved undeveloped reserves	44,017	67,596	65,944	62,115
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	551,026	580,933	583,560
Extensions, discoveries and other additions	40,988	82,353	100,131
Purchases of minerals in-place			140
Revisions of previous estimates	(71,462)	(6,562)	(13,277)
Production	(78,331)	(87,386)	(89,574)
Sales of minerals in-place	(8,721)	(18,312)	(47)
Ending balance	433,500	551,026	580,933
Crude Oil and Condensate | United States
Reserve Quantities [Line Items]
Proved developed reserves	206,936	278,145	300,484	304,279
Proved undeveloped reserves	25,516	46,716	45,182	31,904
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	324,861	345,666	336,183
Extensions, discoveries and other additions	17,858	52,297	61,976
Purchases of minerals in-place			140
Revisions of previous estimates	(69,247)	(16,446)	(14,334)
Production	(32,299)	(38,344)	(38,252)
Sales of minerals in-place	(8,721)	(18,312)	(47)
Ending balance	232,452	324,861	345,666
Crude Oil and Condensate | Egypt
Reserve Quantities [Line Items]
Proved developed reserves	95,981	103,573	110,014	124,568
Proved undeveloped reserves	11,228	10,831	9,484	16,198
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	114,404	119,498	140,766
Extensions, discoveries and other additions	17,855	21,039	22,473
Purchases of minerals in-place			0
Revisions of previous estimates	2,541	4,752	(9,556)
Production	(27,591)	(30,885)	(34,185)
Sales of minerals in-place	0	0	0
Ending balance	107,209	114,404	119,498
Crude Oil and Condensate | North Sea
Reserve Quantities [Line Items]
Proved developed reserves	86,566	101,712	104,491	92,598
Proved undeveloped reserves	7,273	10,049	11,278	14,013
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	111,761	115,769	106,611
Extensions, discoveries and other additions	5,275	9,017	15,682
Purchases of minerals in-place			0
Revisions of previous estimates	(4,756)	5,132	10,613
Production	(18,441)	(18,157)	(17,137)
Sales of minerals in-place	0	0	0
Ending balance	93,839	111,761	115,769
Crude Oil and Condensate | Noncontrolling Interests | Egypt
Reserve Quantities [Line Items]
Proved developed reserves	36,000	38,000	40,000	47,000
Natural Gas Liquids
Reserve Quantities [Line Items]
Proved developed reserves	153,368	161,778	200,014	173,715
Proved undeveloped reserves	15,587	24,319	34,487	29,951
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	186,097	234,501	203,666
Extensions, discoveries and other additions	11,844	42,067	62,578
Purchases of minerals in-place			40
Revisions of previous estimates	(412)	(31,716)	(10,038)
Production	(28,118)	(25,933)	(21,740)
Sales of minerals in-place	(456)	(32,822)	(5)
Ending balance	168,955	186,097	234,501
Natural Gas Liquids | United States
Reserve Quantities [Line Items]
Proved developed reserves	150,599	158,794	197,574	171,005
Proved undeveloped reserves	15,141	23,569	33,796	29,559
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	182,363	231,370	200,564
Extensions, discoveries and other additions	11,435	41,343	60,990
Purchases of minerals in-place			40
Revisions of previous estimates	(469)	(32,569)	(9,250)
Production	(27,133)	(24,959)	(20,969)
Sales of minerals in-place	(456)	(32,822)	(5)
Ending balance	165,740	182,363	231,370
Natural Gas Liquids | Egypt
Reserve Quantities [Line Items]
Proved developed reserves	716	667	502	685
Proved undeveloped reserves	126	90	60	39
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	757	562	724
Extensions, discoveries and other additions	97	27	144
Purchases of minerals in-place			0
Revisions of previous estimates	264	508	31
Production	(276)	(340)	(337)
Sales of minerals in-place	0	0	0
Ending balance	842	757	562
Natural Gas Liquids | North Sea
Reserve Quantities [Line Items]
Proved developed reserves	2,053	2,317	1,938	2,025
Proved undeveloped reserves	320	660	631	353
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	2,977	2,569	2,378
Extensions, discoveries and other additions	312	697	1,444
Purchases of minerals in-place			0
Revisions of previous estimates	(207)	345	(819)
Production	(709)	(634)	(434)
Sales of minerals in-place	0	0	0
Ending balance	2,373	2,977	2,569
Natural Gas Liquids | Noncontrolling Interests | Egypt
Reserve Quantities [Line Items]
Proved developed reserves	281	252	187	241
Natural Gas
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	1,529,950	1,485,649	2,197,882	1,971,018
Proved undeveloped reserves | MMcf	97,417	156,348	315,900	355,544
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	1,641,997	2,513,782	2,326,562
Extensions, discoveries and other additions | MMcf	152,823	311,674	838,803
Purchases of minerals in-place | MMcf			906
Revisions of previous estimates | MMcf	161,776	(487,168)	(300,029)
Production | MMcf	(326,974)	(357,771)	(352,419)
Sales of minerals in-place | MMcf	(2,255)	(338,520)	(41)
Ending balance | MMcf	1,627,367	1,641,997	2,513,782
Natural Gas | United States
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	1,052,756	945,938	1,626,403	1,347,009
Proved undeveloped reserves | MMcf	76,504	115,040	267,090	297,226
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	1,060,978	1,893,493	1,644,235
Extensions, discoveries and other additions | MMcf	60,965	249,205	704,135
Purchases of minerals in-place | MMcf			906
Revisions of previous estimates | MMcf	215,166	(509,753)	(239,204)
Production | MMcf	(205,594)	(233,447)	(216,538)
Sales of minerals in-place | MMcf	(2,255)	(338,520)	(41)
Ending balance | MMcf	1,129,260	1,060,978	1,893,493
Natural Gas | Egypt
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	409,035	433,382	476,132	540,667
Proved undeveloped reserves | MMcf	12,572	24,704	33,006	47,255
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	458,086	509,138	587,922
Extensions, discoveries and other additions | MMcf	83,718	34,758	79,394
Purchases of minerals in-place			0
Revisions of previous estimates	(19,849)	18,570	(38,892)
Production	(100,348)	(104,380)	(119,286)
Sales of minerals in-place	0	0	0
Ending balance | MMcf	421,607	458,086	509,138
Natural Gas | North Sea
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	68,159	106,329	95,347	83,342
Proved undeveloped reserves | MMcf	8,341	16,604	15,804	11,063
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	122,933	111,151	94,405
Extensions, discoveries and other additions | MMcf	8,140	27,711	55,274
Purchases of minerals in-place			0
Revisions of previous estimates	(33,541)	4,015	(21,933)
Production	(21,032)	(19,944)	(16,595)
Sales of minerals in-place	0	0	0
Ending balance | MMcf	76,500	122,933	111,151
Natural Gas | Noncontrolling Interests | Egypt
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	141,000	153,000	170,000	196,000

SUPPLEMENTAL OIL AND GAS DISC_7

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Additional Information (Details) - MBoe MBoe in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions	78	176	303
Revision of previous estimate	(45)	(119)	(73)
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	39	135	240
Southern Midland Basin
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions	26
International Regions
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions	39	41	62
Egypt
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions	32	27	36
North Sea
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions	7	14	26
Eastern Shelf and Magnet Withers/Pickett Ridge
Reserve Quantities [Line Items]
Sale of mineral in place	10
Anadarko Basin
Reserve Quantities [Line Items]
Sale of mineral in place		107
Premian Basin
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		129	217
MidContinent Region
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		6	20
Changes in Product Prices
Reserve Quantities [Line Items]
Revision of previous estimate	(70)	(139)	(24)
Changes in Engineering and Performance
Reserve Quantities [Line Items]
Revision of previous estimate	27	20	(44)
Interest Revisions
Reserve Quantities [Line Items]
Revision of previous estimate	(2)		(5)

SUPPLEMENTAL OIL AND GAS DISC_8

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	$ 22,219	$ 37,454	$ 48,978
Production costs	(10,336)	(15,219)	(18,086)
Development costs	(4,636)	(5,098)	(5,656)
Income tax expense	(780)	(2,741)	(3,826)
Net cash flows	6,467	14,396	21,410
10 percent discount rate	(1,155)	(4,514)	(7,689)
Discounted future net cash flows	$ 5,312	9,882	13,721
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	$ 7,100	12,400	16,900
United States
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	12,537	21,694	29,906
Production costs	(6,244)	(10,642)	(13,699)
Development costs	(1,555)	(1,740)	(2,150)
Income tax expense	0	(27)	(19)
Net cash flows	4,738	9,285	14,038
10 percent discount rate	(1,829)	(4,003)	(6,516)
Discounted future net cash flows	2,909	5,282	7,522
Egypt
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	5,560	8,306	9,866
Production costs	(1,704)	(1,847)	(1,799)
Development costs	(633)	(707)	(792)
Income tax expense	(1,096)	(1,930)	(2,455)
Net cash flows	2,127	3,822	4,820
10 percent discount rate	(437)	(808)	(1,066)
Discounted future net cash flows	1,690	3,014	3,754
Egypt | Noncontrolling Interests
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Discounted future net cash flows	563	1,000	1,300
North Sea
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	4,122	7,454	9,206
Production costs	(2,388)	(2,730)	(2,588)
Development costs	(2,448)	(2,651)	(2,714)
Income tax expense	316	(784)	(1,352)
Net cash flows	(398)	1,289	2,552
10 percent discount rate	1,111	297	(107)
Discounted future net cash flows	$ 713	$ 1,586	$ 2,445

SUPPLEMENTAL OIL AND GAS DISC_9

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Extractive Industries [Abstract]
Sales, net of production costs	$ (2,422)	$ (4,291)	$ (5,335)
Net change in prices and production costs	(5,753)	(3,034)	3,902
Discoveries and improved recovery, net of related costs	751	2,042	3,889
Change in future development costs	20	(75)	47
Previously estimated development costs incurred during the period	576	983	910
Revision of quantities	(418)	(741)	(648)
Purchases of minerals in-place	0	0	6
Accretion of discount	1,236	1,693	1,216
Change in income taxes	1,533	720	(1,125)
Sales of minerals in-place	(104)	(817)	(1)
Change in production rates and other	11	(319)	777
Change in the discounted future net cash flows, Total	$ (4,570)	$ (3,839)	$ 3,638