Apache 10-K 23 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Jan. 31, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Trading Symbol	APA
Entity Registrant Name	APACHE CORP
Entity Central Index Key	6,769
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		381,447,822
Entity Public Float			$ 18,257,879,903

STATEMENT OF CONSOLIDATED OPERA

STATEMENT OF CONSOLIDATED OPERATIONS - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil and gas production revenues:
Oil and gas production revenues	$ 5,887	$ 5,367	$ 6,510
Derivative instrument gains (losses), net	(135)	0	0
Other	44	(34)	98
Gain on divestiture	627	21	281
Total revenues and other	6,423	5,354	6,889
OPERATING EXPENSES:
Lease operating expenses	1,400	1,494	1,854
Gathering and transportation	179	200	211
Taxes other than income	151	126	282
Exploration	549	473	2,771
General and administrative	395	410	380
Transaction, reorganization, and separation	16	39	132
Oil and gas property and equipment
Depreciation, depletion, and amortization	2,280	2,618	3,300
Asset retirement obligation accretion	130	156	145
Impairments	8	1,103	9,472
Financing costs, net	397	417	511
Total operating expenses	5,505	7,036	19,058
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	918	(1,682)	(12,169)
Current income tax provision	595	391	435
Deferred income tax benefit	(1,180)	(833)	(1,445)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	1,503	(1,240)	(11,159)
Net income (loss) from discontinued operations, net of tax	0	(33)	492
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	1,503	(1,273)	(10,667)
Net income (loss) attributable to noncontrolling interest	199	132	(315)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	1,304	(1,405)	(10,352)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Net income (loss) from continuing operations attributable to common shareholders	1,304	(1,372)	(10,844)
Net income (loss) from discontinued operations	0	(33)	492
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$ 1,304	$ (1,405)	$ (10,352)
NET INCOME (LOSS) PER COMMON SHARE:
Basic net income (loss) from continuing operations per share (in USD per share)	$ 3.42	$ (3.62)	$ (28.70)
Basic net income (loss) from discontinued operations per share (in USD per share)	0	(0.09)	1.30
Basic net income (loss) per share (in USD per share)	3.42	(3.71)	(27.40)
DILUTED NET INCOME (LOSS) PER COMMON SHARE:
Diluted net income (loss) from continuing operations per share (in USD per share)	3.41	(3.62)	(28.70)
Diluted net income (loss) from discontinued operations per share (in USD per share)	0	(0.09)	1.30
Diluted net income (loss) per share (in USD per share)	$ 3.41	$ (3.71)	$ (27.40)
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic (in shares)	381	379	378
Diluted (in shares)	383	379	378
DIVIDENDS DECLARED PER COMMON SHARE (in USD per share)	$ 1	$ 1	$ 1
Oil and gas property and equipment
Oil and gas property and equipment
Depreciation, depletion, and amortization	$ 2,136	$ 2,460	$ 2,976
Other assets
Oil and gas property and equipment
Depreciation, depletion, and amortization	144	158	324
Oil
Oil and gas production revenues:
Oil and gas production revenues	4,598	4,172	5,107
Natural Gas
Oil and gas production revenues:
Oil and gas production revenues	959	967	1,176
Natural Gas Liquids
Oil and gas production revenues:
Oil and gas production revenues	$ 330	$ 228	$ 227

STATEMENT OF CONSOLIDATED COMPR

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	$ 1,503	$ (1,273)	$ (10,667)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and postretirement benefit plan, net of tax	7	7	(3)
Currency translation adjustment	109	0	0
Other comprehensive income (loss), net of tax	116	7	(3)
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	1,619	(1,266)	(10,670)
Comprehensive income (loss) attributable to noncontrolling interest	199	132	(315)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$ 1,420	$ (1,398)	$ (10,355)

STATEMENT OF CONSOLIDATED CASH

STATEMENT OF CONSOLIDATED CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	$ 1,503,000	$ (1,273,000)	$ (10,667,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss (income) from discontinued operations	0	33,000	(492,000)
Unrealized derivative instrument losses, net	59,000	0	0
Gain on divestitures	(627,000)	(21,000)	(281,000)
Exploratory dry hole expense and unproved leasehold impairments	429,000	353,000	2,595,000
Depreciation, depletion, and amortization	2,280,000	2,618,000	3,300,000
Asset retirement obligation accretion	130,000	156,000	145,000
Impairments	8,000	1,103,000	9,472,000
Benefit from deferred income taxes	(1,180,000)	(833,000)	(1,445,000)
Other	146,000	164,000	7,000
Changes in operating assets and liabilities:
Receivables	(270,000)	126,000	663,000
Inventories	32,000	(27,000)	21,000
Drilling advances	(128,000)	91,000	138,000
Deferred charges and other	(58,000)	115,000	(345,000)
Accounts payable	63,000	(63,000)	(489,000)
Accrued expenses	4,000	(9,000)	(156,000)
Deferred credits and noncurrent liabilities	37,000	(80,000)	88,000
NET CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES	2,428,000	2,453,000	2,554,000
NET CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS	0	(23,000)	113,000
NET CASH PROVIDED BY OPERATING ACTIVITIES	2,428,000	2,430,000	2,667,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(2,052,000)	(1,610,000)	(4,208,000)
Additions to gas gathering, transmission, and processing facilities	(530,000)	(158,000)	(233,000)
Leasehold and property acquisitions	(178,000)	(181,000)	(367,000)
Proceeds from sale of Kitimat LNG	0	0	854,000
Proceeds from sale of Yara Pilbara	0	0	391,000
Proceeds from sale of Canadian assets, net of cash divested	661,000	0	0
Proceeds from sale of oil and gas properties, other	758,000	134,000	268,000
Other, net	(75,000)	155,000	6,000
NET CASH USED IN CONTINUING INVESTING ACTIVITIES	(1,416,000)	(1,660,000)	(3,289,000)
NET CASH PROVIDED BY DISCONTINUED OPERATIONS	0	0	4,372,000
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(1,416,000)	(1,660,000)	1,083,000
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facilities and bank notes, net	0	0	(1,570,000)
Payments on fixed-rate debt	(70,000)	(181,000)	(939,000)
Distributions to noncontrolling interest	(265,000)	(293,000)	(129,000)
Dividends paid	(380,000)	(379,000)	(377,000)
Other	(6,000)	(7,000)	53,000
NET CASH USED IN FINANCING ACTIVITIES	(721,000)	(860,000)	(2,962,000)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	291,000	(90,000)	788,000
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	1,377,000	1,467,000	679,000
CASH AND CASH EQUIVALENTS AT END OF PERIOD	1,668,000	1,377,000	1,467,000
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	405,000	413,000	461,000
Income taxes paid, net of refunds	$ 516,000	$ 305,000	$ 573,000

CONSOLIDATED BALANCE SHEET

CONSOLIDATED BALANCE SHEET - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
CURRENT ASSETS:
Cash and cash equivalents	$ 1,668,000	$ 1,377,000
Receivables, net of allowance	1,345,000	1,128,000
Inventories	368,000	476,000
Drilling advances	207,000	81,000
Prepaid assets and other	137,000	179,000
Total current assets	3,725,000	3,241,000
Oil and gas, on the basis of successful efforts accounting:
Proved properties	39,197,000	42,693,000
Unproved properties and properties under development	1,783,000	1,969,000
Gathering, transmission, and processing facilities	1,376,000	976,000
Other	1,046,000	1,111,000
Property and equipment, gross	43,402,000	46,749,000
Less: Accumulated depreciation, depletion, and amortization	(25,643,000)	(27,882,000)
Property and equipment, net	17,759,000	18,867,000
OTHER ASSETS:
Deferred charges and other	438,000	411,000
Total assets	21,922,000	22,519,000
CURRENT LIABILITIES:
Accounts payable	641,000	585,000
Current debt	550,000	0
Other current liabilities (Note 5)	1,373,000	1,258,000
Total current liabilities	2,564,000	1,843,000
LONG-TERM DEBT	7,934,000	8,544,000
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	545,000	1,710,000
Asset retirement obligation	1,792,000	2,432,000
Other	296,000	311,000
Total deferred credits and other noncurrent liabilities	2,633,000	4,453,000
COMMITMENTS AND CONTINGENCIES (Note 9)
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 414,125,879 and 412,612,102 shares issued, respectively	259,000	258,000
Paid-in capital	12,128,000	12,364,000
Accumulated deficit	(2,088,000)	(3,385,000)
Treasury stock, at cost, 33,171,015 and 33,172,426 shares, respectively	(2,887,000)	(2,887,000)
Accumulated other comprehensive income (loss)	4,000	(112,000)
APACHE SHAREHOLDERS’ EQUITY	7,416,000	6,238,000
Noncontrolling interest	1,375,000	1,441,000
TOTAL EQUITY	8,791,000	7,679,000
TOTAL LIABILITIES AND EQUITY	$ 21,922,000	$ 22,519,000

CONSOLIDATED BALANCE SHEET (Par

CONSOLIDATED BALANCE SHEET (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common stock, par value (in USD per share)	$ 0.625	$ 0.625
Common stock, shares authorized	860,000,000	860,000,000
Common stock, shares issued	414,125,879	412,612,102
Treasury stock, shares	33,171,015	33,172,426

STATEMENT OF CONSOLIDATED CHANG

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY - USD ($) $ in Millions	Total	Common Stock	Paid-In Capital	Retained Earnings (Accumulated Deficit)	Treasury Stock	Accumulated Other Comprehensive Income (Loss)	APACHE SHAREHOLDERS’ EQUITY	Noncontrolling Interest
Beginning Balance at Dec. 31, 2014	$ 20,541	$ 256	$ 12,590	$ 8,655	$ (2,890)	$ (116)	$ 18,495	$ 2,046
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(10,667)			(10,352)			(10,352)	(315)
Distributions to noncontrolling interest	(129)							(129)
Pension & Postretirement benefit plans, net of tax	(3)					(3)	(3)
Common dividends ($1.00 per share)	(378)		(95)	(283)			(378)
Common stock activity, net	(14)	1	(15)				(14)
Treasury stock activity, net	0		(1)		1
Compensation expense	140		140				140
Ending Balance at Dec. 31, 2015	9,490	257	12,619	(1,980)	(2,889)	(119)	7,888	1,602
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(1,273)			(1,405)			(1,405)	132
Distributions to noncontrolling interest	(293)							(293)
Pension & Postretirement benefit plans, net of tax	7					7	7
Common dividends ($1.00 per share)	(379)		(379)				(379)
Common stock activity, net	(38)	1	(39)				(38)
Treasury stock activity, net	1		(1)		2		1
Compensation expense	164		164				164
Ending Balance at Dec. 31, 2016	7,679	258	12,364	(3,385)	(2,887)	(112)	6,238	1,441
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	1,503			1,304			1,304	199
Distributions to noncontrolling interest	(265)							(265)
Pension & Postretirement benefit plans, net of tax	7					7	7
Common dividends ($1.00 per share)	(381)		(381)				(381)
Common stock activity, net	(39)	1	(40)				(39)
Compensation expense	174		174				174
Other	113		11	(7)		109	113
Ending Balance at Dec. 31, 2017	$ 8,791	$ 259	$ 12,128	$ (2,088)	$ (2,887)	$ 4	$ 7,416	$ 1,375

STATEMENT OF CONSOLIDATED CHAN8

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Stockholders' Equity [Abstract]
Common stock, dividends, per share (in USD per share)	$ 1	$ 1	$ 1

Nature of Operations

Nature of Operations	12 Months Ended
	Dec. 31, 2017
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 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 exploration interests in Suriname that may, over time, result in a reportable discovery and development opportunity.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2017
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. During the second quarter of 2015, Apache completed the sale of its Australian LNG business and oil and gas assets. Results of operations and cash flows for the divested Australia assets are reflected as discontinued operations in the Company’s financial statements for all periods presented. 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, Apache 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 Apache subsidiary 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 Apache’s consolidated balance sheet. Investments in which Apache holds less than 50 percent of the voting interest are typically accounted for under the equity method of accounting, with the balance recorded as a component of “Deferred charges and other” in Apache’s consolidated balance sheet and results of operations recorded as a component of “Other” under “Revenues and Other” in the Company’s statement of consolidated operations. 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 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. Apache evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of its financial statements and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the fair value determination of acquired assets and liabilities (see Note 2—Acquisitions and Divestitures), the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (see Note 15—Supplemental Oil and Gas Disclosures), the assessment of asset retirement obligations (see Note 6—Asset Retirement Obligation), the estimates of fair value for long-lived assets and goodwill (see “Fair Value Measurements,” “Property and Equipment,” and “Goodwill” sections in this Note 1 below), and the estimate of income taxes (see Note 8—Income Taxes). 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 7—Debt, and Note 10—Retirement and Deferred Compensation Plans. Apache also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. For the year ended December 31, 2017, the Company recorded asset impairments totaling $8 million in connection with fair value assessments. In 2016, the U.K. government enacted Finance Bill 2016, providing tax relief to exploration and production (E&P) companies operating in the U.K. North Sea. Under the enacted legislation, the U.K. Petroleum Revenue Tax (PRT) rate was reduced to zero from the previously enacted 35 percent rate in effect from January 1, 2016. PRT expense ceased prospectively from that date. During 2017, the Company fully impaired the aggregate remaining value of the recoverable PRT decommissioning asset of $8 million that would have been realized from future abandonment activities. The recoverable value of the PRT decommissioning asset was estimated using the income approach. The expected future cash flows used in the determination were based on anticipated spending and timing of planned future abandonment activities for applicable fields, considering all available information at the date of review. Apache has classified this fair value measurement as Level 3 in the fair value hierarchy. For the year ended December 31, 2016, the Company recorded asset impairments totaling $1.1 billion in connection with fair value assessments in the current low commodity price environment. Impairments totaling $427 million and $135 million were recorded for proved properties and gathering, transmission, and processing (GTP) facilities, respectively, which were written down to their fair values. These impairments are discussed in further detail below in “Property and Equipment.” Also in 2016, the Company recorded $486 million for the impairment of the recoverable value of the PRT decommissioning asset and $55 million for inventory write-downs. For the year ended December 31, 2015, the Company recorded asset impairments totaling $9.5 billion in connection with fair value assessments. Impairments totaling $7.4 billion and $1.7 billion were recorded for proved properties and GTP facilities, respectively, which were written down to their fair values. These impairments are discussed in further detail below in “Property and Equipment.” Also in 2015, the Company recorded $163 million for the impairment of goodwill, $148 million for the impairment of an equity method investment sold in the fourth quarter, and $55 million for inventory write-downs. For a discussion of the equity method investment impairment, see Note 2—Acquisitions and Divestitures. Restricted Cash and Cash Equivalents In November 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash.” ASU 2016-18 requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. The guidance is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The Company adopted ASU 2016-18 in the third quarter of 2017, and it did not have an impact on the Company’s consolidated financial statements. As of December 31, 2017 , and 2016 , the Company had no restricted cash. 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, 2017 and 2016 , Apache had $1.7 billion and $1.4 billion , respectively, of cash and cash equivalents. Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for doubtful accounts. The carrying amount of Apache’s accounts receivable approximates fair value because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables. Many of Apache’s receivables are from joint interest owners on properties Apache operates. The Company may have the ability to withhold future revenue disbursements to recover any non-payment of these joint interest billings. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2017 , 2016 , and 2015 , the Company had an allowance for doubtful accounts of $84 million , $93 million , and $103 million , respectively. The following table describes changes to the Company’s allowance for doubtful accounts for 2017 , 2016 , and 2015 : 2017 2016 2015 (In millions) Allowance for doubtful accounts at beginning of year $ 93 $ 103 $ 98 Additional provisions for the year 4 14 40 Uncollectible accounts written off net of recoveries (13 ) (24 ) (35 ) Allowance for doubtful accounts at end of year $ 84 $ 93 $ 103 Inventories Inventories consist principally of tubular goods and equipment, stated at weighted-average cost, and oil produced but not sold, stated at the lower of cost or market. Property and Equipment The carrying value of Apache’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 those reserves. 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 costs for exploratory and development wells 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 proved oil and gas properties may be impaired, 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 the ASC 820. If applicable, the Company utilizes prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a discount rate believed to be consistent with those applied by market participants. Apache has classified these fair value measurements as Level 3 in the fair value hierarchy. The following table represents non-cash impairments of the carrying value of the Company’s proved and unproved property and equipment for 2017 , 2016 , and 2015 : For the Year Ended December 31, 2017 2016 2015 (In millions) Oil and Gas Property: Proved $ — $ 427 $ 7,389 Unproved 246 272 2,462 Proved properties impaired had aggregate fair values as of the most recent date of impairment of $306 million and $3.9 billion for 2016 and 2015 , respectively. On the statement of consolidated operations, unproved impairments are recorded in exploration expense, and proved impairments are recorded in impairments. Gains and losses on significant divestitures are recognized in the statement of consolidated operations. See Note 2—Acquisitions and Divestitures for more detail. Gathering, Transmission, and Processing Facilities GTP facilities totaled $1.4 billion and $976 million at December 31, 2017 and 2016 , respectively, with accumulated depreciation for these assets totaling $194 million and $130 million for the respective periods. GTP 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 GTP assets, whether Apache-operated or third party, as well as potential development plans by Apache for undeveloped acreage within or in close proximity to those fields. The Company assesses the carrying amount of its GTP facilities whenever events or changes in circumstances indicate that their 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. During 2017, the Company recorded no impairments on GTP assets. During 2016, the Company recorded impairments of $135 million on certain GTP assets in the North Sea, which were written down to their fair values of $142 million . During 2015, the Company recorded impairments of $1.7 billion on certain GTP assets, including $1.1 billion in Egypt, $555 million in Canada, and $103 million in the U.S., which were written down to their fair values of $306 million in aggregate. The fair values of the impaired assets were determined using a combination of the income approach and the market approach. The income approach considers 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 a discount rate 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. The costs of GTP facilities retired 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. During 2017, Apache recorded a gain totaling $6 million associated with the Company’s divestiture of its 30.28 percent interest in the Scottish Area Gas Evacuation system (SAGE) and its 60.56 percent interest in the Beryl pipeline in the North Sea. For more information regarding this transaction, please refer to Note 2—Acquisitions and Divestitures. No gain or loss on the sales of GTP facilities was recognized during 2016. During 2015, Apache recorded a gain on the sale of GTP facilities totaling $59 million associated with the Company’s divestitures of certain Permian Basin assets. 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. Accumulated depreciation for these assets totaled $739 million and $780 million at December 31, 2017 and 2016 , 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 or impairment. 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. As of December 31, 2017 , 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 the implied fair value of the goodwill through a charge to expense. In order to determine the fair value of the reporting unit, the Company uses a combination of the income approach and the market approach. The income approach considers management views on current operating measures as well as assumptions pertaining to market forces in the oil and gas industry, such as future production, future commodity prices, and costs. These assumptions are applied to develop future cash flow projections that are then discounted to estimate fair value, using a discount rate similar to those used by the Company in the valuation of acquisitions and divestitures. To assess the reasonableness of its fair value estimate, the Company uses a market approach to compare the fair value to similar businesses whose securities are actively traded in the public market. This requires management to make certain judgments about the selection of comparable companies, recent comparable asset transactions, and transaction premiums. Associated market multiples are applied to various financial metrics of the reporting unit to estimate fair value. Apache has classified this reporting unit estimation as a non-recurring Level 3 fair value measurement. 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 2017 , 2016 , and 2015 : Egypt North Sea Total (In millions) Goodwill at December 31, 2014 $ 87 $ 163 $ 250 Impairments — (163 ) (163 ) Goodwill at December 31, 2015 87 — 87 Impairments — — — Goodwill at December 31, 2016 87 — 87 Impairments — — — Goodwill at December 31, 2017 $ 87 $ — $ 87 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 Apache’s North Sea reporting unit. This goodwill impairment has been recorded in “Impairments” in the Company’s statement of consolidated operations. Accounts Payable Included in accounts payable at December 31, 2017 and 2016 , are liabilities of approximately $76 million and $86 million , respectively, representing the amount by which checks issued but not presented to the Company’s banks for collection exceeded balances in applicable bank accounts. 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. Revenue Recognition and Imbalances Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met. Apache uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Apache is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to Apache will not be sufficient to enable the under-produced owner to recoup its entitled share through production. The Company’s recorded liability is generally reflected in other non-current liabilities. No receivables are recorded for those wells where Apache has taken less than its share of production. Gas imbalances are reflected as adjustments to estimates of proved gas reserves and future cash flows in the unaudited supplemental oil and gas disclosures. Apache markets its own North American natural gas production. Since the Company’s production fluctuates because of operational issues, it is occasionally necessary to purchase third-party oil and gas to fulfill sales obligations and commitments. The costs of third-party oil and gas purchases totaled $254 million , $159 million , and $105 million , for 2017 , 2016 , and 2015 , respectively, which offset the related sales proceeds recorded as “Other” under “Revenues and Other” in the statement of consolidated operations. The Company’s Egyptian operations are conducted pursuant to production sharing contracts under which contractor partners pay all operating and capital costs for exploring and developing the concessions. A percentage of the production, generally up to 40 percent , is available to contractor partners to recover these operating and capital costs over contractually defined periods. Cost recovery is reflected in revenue. The balance of the production is split among the contractor partners and the Egyptian General Petroleum Corporation on a contractually defined basis. Derivative Instruments and Hedging Activities Apache periodically enters into derivative contracts to manage its exposure to commodity price risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options. The oil and gas reference prices upon which the commodity derivative contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and gas production. Apache records all derivative instruments, other than those that meet the normal purchases and sales exception, on the balance sheet as either an asset or liability measured at fair value. Changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting are reported in current-period income as “Derivative instrument gains (losses), net” under “Revenues and Other” in the statement of consolidated operations. Hedge accounting treatment allows unrealized gains and losses on cash flow hedges to be deferred in other comprehensive income. For more information, please refer to Note 4—Derivative Instruments and Hedging Activities. 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. Foreign Currency Transaction Gains and Losses The U.S. dollar is the functional currency for each of Apache’s international operations. The functional currency is determined country-by-country based on relevant facts and circumstances of the cash flows, commodity pricing environment and financing arrangements in each country. Foreign currency transaction gains and losses arise when monetary assets and liabilities denominated in foreign currencies are remeasured to their U.S. dollar equivalent at the exchange rate in effect at the end of each reporting period. Foreign currency gains and losses also arise when revenue and disbursement transactions denominated in a country’s local currency are converted to a U.S. dollar equivalent based on the average exchange rates during the reporting period. Foreign currency transaction gains and losses related to current taxes payable and deferred tax assets and liabilities are recorded as components of the provision for income taxes. For further discussion, please refer to Note 8—Income Taxes. All other foreign currency transaction gains and losses are reflected in “Other” under “Revenues and Other” in the statement of consolidated operations. The Company’s other foreign currency gains and losses netted to losses of $11 million , $25 million , and $11 million in 2017, 2016, and 2015, respectively. Insurance Coverage The Company recognizes an insurance receivable when collection of the receivable is deemed probable. Any recognition of an insurance receivable is recorded by crediting and offsetting the original charge. Any differential arising between insurance recoveries and insurance receivables is recorded as a capitalized cost or as an expense, consistent with its original treatment. Earnings Per Share The Company’s basic earnings per share (EPS) amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was fully vested. Stock-Based Compensation The Company accounts for stock-based compensation under the fair value recognition provisions of ASC Topic 718, “Compensation—Stock Compensation.” The Company grants various types of stock-based awards including stock options, nonvested restricted stoc

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
ACQUISITIONS AND DIVESTITURES	ACQUISITIONS AND DIVESTITURES 2017 Activity Canada Divestitures During the third quarter, Apache announced the sale of its subsidiary Apache Canada Ltd. (ACL) and complete exit of its Canadian operations. On June 30, 2017, Apache completed the sale of its Canadian assets at Midale and House Mountain, located in Saskatchewan and Alberta, for aggregate cash proceeds of approximately $228 million . The Company recognized a $52 million loss during the second quarter of 2017 in association with this sale. In August of 2017, Apache completed the sale of its remaining Canadian operations for aggregate cash proceeds of approximately $478 million . The Company recognized a $74 million gain upon closing of these transactions in the third quarter of 2017. A summary of the Company’s Canadian assets and liabilities at the time of close is detailed below: (In millions) ASSETS Cash $ 46 Other current assets 64 Property, plant & equipment 1,132 Total Assets $ 1,242 LIABILITIES Current liabilities, excluding asset retirement obligation $ 120 Asset retirement obligation 780 Other long-term liabilities 46 Total Liabilities $ 946 The net carrying value of the assets disposed included a currency translation loss of $109 million , which was recorded in “Accumulated other comprehensive income (loss)” on the Company’s consolidated balance sheet at December 31, 2016. The currency translation loss was recognized as a reduction of the net gain on sale during the third quarter of 2017 upon closing of the transactions. Apache’s Canadian operations recorded pretax losses of $141 million , $684 million , and $2.0 billion for the years ended 2017, 2016, and 2015, respectively. U.S. Divestitures During 2017, Apache completed the sale of certain non-core assets, primarily leasehold acreage in the Permian and Midcontinent/Gulf Coast regions, in multiple transactions for cash proceeds of $798 million , subject to customary closing adjustments. Refundable deposits totaling $40 million were received in the fourth quarter of 2016 in connection with certain of these transactions and were recorded in “Other current liabilities” on the consolidated balance sheet as of December 31, 2016. In the first quarter of 2017, Apache completed these transactions, and the liabilities related to the refundable deposits were released. The Company recognized gains of approximately $599 million during 2017 in connection with these transactions. North Sea GTP Divestiture During the fourth quarter of 2016, Apache entered into an agreement to sell its 30.28 percent interest in the SAGE gas plant and its 60.56 percent interest in the Beryl pipeline in the North Sea to Ancala Midstream Acquisitions Limited. A refundable deposit of $134 million was received in the fourth quarter of 2016 in connection with this transaction and was recorded in “Other current liabilities” on the consolidated balance sheet as of December 31, 2016. In November 2017, Apache completed the sale, and the liability related to the refundable deposit was released. No additional proceeds were received, and the Company recognized a $6 million gain upon closing of this transaction. Leasehold and Property Acquisitions Apache completed $188 million of leasehold and property acquisitions during 2017, primarily in its North America onshore regions. 2016 Activity Leasehold and Property Acquisitions Apache completed $181 million of leasehold and property acquisitions during 2016, primarily in its North America onshore regions. Divestiture of Other Oil and Gas Properties Apache recorded $134 million of proceeds from the divestiture of other oil and gas properties during 2016. An associated $21 million of gain was recorded in 2016. 2015 Activity Yara Pilbara Holdings Pty Limited Sale In October 2015, Apache sold its 49 percent interest in Yara Pilbara Holdings Pty Limited (YPHPL) for total cash proceeds of $391 million . The investment in YPHPL was accounted for under the equity method of accounting, with the balance recorded as a component of “Deferred charges and other” in Apache’s consolidated balance sheet and the results of operations recorded as a component of “Other” under “Revenue and other” in the Company’s statement of consolidated operations. As of September 30, 2015, Apache recognized an impairment of $148 million on the YPHPL equity investment based on negotiated sales proceeds. No additional gain or loss was recorded upon completion of the sale. Canada LNG Project Divestiture In April 2015, Apache completed the sale of its 50 percent interest in the Kitimat LNG project and upstream acreage in the Horn River and Liard natural gas basins to Woodside Petroleum Limited (Woodside). Proceeds at closing were $854 million , of which approximately $344 million was associated with LNG assets and $510 million was associated with upstream assets. Apache recognized a $146 million gain on the sale of the upstream assets upon completion of the sale. Australia Divestitures Woodside Sale In April 2015, Apache completed the sale of the Wheatstone LNG project and associated upstream oil and gas assets to Woodside. Proceeds at closing were $2.8 billion , of which approximately $1.4 billion was associated with LNG assets and $1.4 billion was associated with the upstream assets. The Wheatstone LNG assets and associated upstream assets were classified as held for sale and impaired $833 million in the fourth quarter of 2014. An additional impairment of approximately $49 million was recognized in the first quarter of 2015. During the third quarter of 2016, Apache recognized an additional $23 million loss on the sale related to post-closing adjustments. Consortium Sale In June 2015, Apache completed the sale of its Australian subsidiary Apache Energy Limited (AEL) to a consortium of private equity funds managed by Macquarie Capital Group Limited and Brookfield Asset Management Inc. Total proceeds of $1.9 billion include customary, post-closing adjustments for the period between the effective date, October 1, 2014, and closing. A loss of approximately $139 million was recognized for the sale of AEL. Upon closing of the sale of substantially all Australian operations, the associated results of operations for the divested Australian assets and the losses on disposal were classified as discontinued operations in the Company’s financial statements for all periods presented. Discontinued Operations Apache sold its operations in Argentina and Australia in 2014 and 2015, respectively. The results of operations related to the Argentina and Australia dispositions and the losses on disposals were classified as discontinued operations in the Company’s financial statements. During 2016, the Company incurred additional losses on these dispositions. The components of the Company’s loss from discontinued operations were as follows: For the Year Ended December 31, 2017 2016 2015 (In millions) Revenues and other from discontinued operations $ — $ — $ 288 Impairment on Woodside sale $ — $ — $ (49 ) Loss on Woodside sale — (23 ) — Loss on Consortium sale — — (139 ) Income from divested Australian operations — — 28 Loss from Argentina divestiture — (10 ) — Income tax benefit — — 652 Income (loss) from discontinued operations, net of tax $ — $ (33 ) $ 492 Leasehold and Property Acquisitions Apache completed $367 million of leasehold and property acquisitions during 2015, primarily in its North America onshore regions. Divestiture of Other Oil and Gas Properties Apache recorded $268 million of proceeds from the divestiture of other oil and gas properties during 2015. An associated $135 million of gain was recorded in 2015. Transaction, Reorganization, and Separation Apache recorded $16 million , $39 million , and $132 million of expenses during 2017 , 2016 , and 2015 , respectively, primarily related to company reorganization, including separation costs, investment banking fees and other associated costs. The charges for 2017 include $11 million for consulting fees related to divestitures and $5 million related to employee separation, consolidation of office space, and other reorganization efforts.

CAPITALIZED EXPLORATORY WELL CO

CAPITALIZED EXPLORATORY WELL COSTS	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
CAPITALIZED EXPLORATORY WELL COSTS	CAPITALIZED EXPLORATORY WELL COSTS The following summarizes the changes in capitalized exploratory well costs for each of the last three years ended December 31, 2017 , 2016 , and 2015 . Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year. 2017 2016 2015 (In millions) Balance at January 1 $ 264 $ 245 $ 849 Additions pending determination of proved reserves 477 249 382 Divestitures and other (3 ) — (557 ) Reclassifications to proved properties (373 ) (211 ) (369 ) Charged to exploration expense (15 ) (19 ) (60 ) Balance at December 31 (1) $ 350 $ 264 $ 245 (1) Includes $2 million of assets related to the Canada divestiture at December 31, 2015. 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: 2017 2016 2015 (In millions) Exploratory well costs capitalized for a period of one year or less $ 160 $ 119 $ 184 Exploratory well costs capitalized for a period greater than one year 190 145 61 Balance at December 31 $ 350 $ 264 $ 245 Number of projects with exploratory well costs capitalized for a period greater than one year 4 3 2 The following summarizes a further aging by geographic area of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling at December 31, 2017 : 2014 and Total 2016 2015 Prior North Sea $ 160 $ 47 $ 53 $ 60 Other International 30 — 28 2 $ 190 $ 47 $ 81 $ 62 Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether reserves can be attributed to these projects. Suspended exploratory well costs capitalized at December 31, 2017 for a period greater than one year since the completion of drilling primarily relate to the Seagull, Corona, and Storr discoveries in the North Sea. The Seagull joint venture partnership has selected the host facility and expects to complete the field development plan in late 2018 and achieve the final investment decision by 2019. The suspended exploratory well costs related to the Corona discovery are pending development plan approval. In December 2016, the Company submitted the full field development plan to the Oil and Gas Authority in the U.K. which has been conditionally approved and awaits the U.K. Business, Energy and Industrial Strategy environmental approvals expected by the second quarter of 2018. The final investment decision will be approved in 2018. Storr was a more recent discovery in the North Sea and development plans are actively being evaluated to bring forth a Storr field development plan during 2018 with final investment decision expected to take place in 2019. The remaining capitalized well costs in excess of one year relate to exploratory drilling in Suriname. Well costs have been suspended pending ongoing activities, including analysis of well results and geologic and geophysical studies of nearby blocks. Remaining activities required to classify the associated reserves as proved include additional exploratory and appraisal drilling, geologic and geophysical studies, reservoir modeling and simulation, economic modeling, pre-development studies, approval of development plans, and project sanctioning.

DERIVATIVE INSTRUMENTS AND HEDG

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Objectives and Strategies The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production. Apache manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production. The Company utilizes various types of derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. 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, 2017 , Apache had derivative positions with 14 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 lower commodity prices. Derivative Instruments As of December 31, 2017 , Apache had the following open crude oil derivative positions: Put Options (1)(2) Production Period Settlement Index Mbbls Weighted Average Strike Price January—December 2018 Dated Brent 3,650 $50.00 (1) The remaining unamortized premium paid as of December 31, 2017 , was $9 million . (2) Subsequent to December 31, 2017 , the Company entered into put option contracts settling against NYMEX WTI totaling 5,520 Mbbls with a strike price of $53.00 for the second half of 2018 and Dated Brent totaling 5,520 Mbbls with a strike price of $58.00 for the second half of 2018. Apache paid total premiums of $9 million and $11 million for the NYMEX WTI and Dated Brent put contracts, respectively. Fixed-Price Swaps Collars Call Options (3) Production Period Settlement Index Mbbls Weighted Average Fixed Price Mbbls Weighted Average Floor Price Weighted Average Ceiling Price Mbbls Strike Price January—June 2018 NYMEX WTI 2,715 $51.23 2,715 $45.00 $56.45 — — January—June 2018 Dated Brent 2,172 $54.57 2,172 $50.00 $58.77 — — January—December 2018 NYMEX WTI — — 6,753 $45.00 $57.00 6,753 $60.03 (3) The remaining unamortized premium paid as of December 31, 2017 , was $10 million . As of December 31, 2017 , Apache had the following open natural gas derivative positions: Fixed-Price Swaps Production Period Settlement Index MMBtu (in 000’s) Weighted Average Fixed Price January—March 2018 NYMEX Henry Hub 13,500 $3.39 January—June 2018 NYMEX Henry Hub 22,625 $3.17 April—June 2018 NYMEX Henry Hub 16,835 $2.92 July—December 2018 NYMEX Henry Hub 33,580 $2.96 As of December 31, 2017 , Apache had the following open natural gas financial basis swap contracts: Production Period Settlement Index MMBtu (in 000’s) Weighted Average Price Differential January—March 2018 NYMEX Henry Hub/Waha 9,450 $(0.43) July—December 2018 NYMEX Henry Hub/Waha 33,120 $(0.53) October—December 2018 NYMEX Henry Hub/Waha 1,380 $(0.51) January—March 2019 NYMEX Henry Hub/Waha 1,350 $(0.54) January—June 2019 NYMEX Henry Hub/Waha 32,580 $(0.53) January—December 2019 NYMEX Henry Hub/Waha 14,600 $(0.45) Fair Value Measurements Apache’s commodity derivative instruments consist of variable-to-fixed price commodity swaps, options, and collars. The fair values of the Company’s derivatives are not actively quoted in the open market. The Company uses a market approach to estimate the fair values of its derivative instruments on a recurring basis, utilizing commodity futures pricing for the underlying commodities provided by a reputable third party, a Level 2 fair value measurement. The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis: Fair Value Measurements Using Quoted Price in Active Markets (Level 1) Significant Other Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value Netting (1) Carrying Amount (In millions) December 31, 2017 Assets: Commodity Derivative Instruments $ — $ 67 $ — $ 67 $ (43 ) $ 24 Liabilities: Commodity Derivative Instruments — 107 — 107 (43 ) 64 December 31, 2016 Assets: Commodity Derivative Instruments $ — $ — $ — $ — $ — $ — Liabilities: Commodity Derivative Instruments — — — — — — (1) The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties. 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: December 31, 2017 December 31, 2016 (In millions) Current Assets: Prepaid assets and other $ 8 $ — Other Assets: Deferred charges and other 16 — Total Assets $ 24 $ — Current Liabilities: Other current liabilities $ 64 $ — Total Liabilities $ 64 $ — 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, 2017 2016 2015 (In millions) Realized gain (loss): Derivative settlements, realized gain $ 24 $ — $ — Amortization of put premium, realized loss (100 ) — — Unrealized loss (59 ) — — Derivative instrument gain (losses), net $ (135 ) $ — $ — Unrealized gains and losses for derivative activity recorded in the statement of consolidated operations is reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument losses, net” in “Adjustments to reconcile net income (loss) to net cash provided by operating activities.”

OTHER CURRENT LIABILITIES

OTHER CURRENT LIABILITIES	12 Months Ended
	Dec. 31, 2017
Payables and Accruals [Abstract]
OTHER CURRENT LIABILITIES	OTHER CURRENT LIABILITIES The following table provides detail of the Company’s other current liabilities at December 31, 2017 and 2016 : December 31, 2017 2016 (In millions) Accrued operating expenses $ 72 $ 110 Accrued exploration and development 802 463 Accrued compensation and benefits 115 201 Accrued interest 145 145 Accrued income taxes 55 22 Current asset retirement obligation 43 66 Refundable deposits — 174 Other 141 77 Total Other current liabilities $ 1,373 $ 1,258

ASSET RETIREMENT OBLIGATION

ASSET RETIREMENT OBLIGATION	12 Months Ended
	Dec. 31, 2017
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 years ended December 31, 2017 and 2016 : 2017 2016 (In millions) Asset retirement obligation at beginning of year $ 2,498 $ 2,598 Liabilities incurred 58 41 Liabilities divested (818 ) (7 ) Liabilities settled (45 ) (57 ) Accretion expense 130 156 Revisions in estimated liabilities 12 (233 ) Asset retirement obligation at end of year 1,835 2,498 Less current portion (43 ) (66 ) Asset retirement obligation, long-term $ 1,792 $ 2,432 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. 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 balance. During 2017 and 2016 , the Company recorded $58 million and $41 million , respectively, in abandonment liabilities resulting from Apache’s exploration and development capital program. Liabilities divested primarily relate to Canada. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period. During 2017 , approximately $12 million of abandonment costs were revised upward to reflect changes in estimates of timing and costs in the U.S. and North Sea. During 2016 , approximately $233 million of abandonment costs were revised downward, primarily in the North Sea.

DEBT

DEBT	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
DEBT	DEBT 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. The indentures for the notes described below place certain restrictions on the Company, including limits on Apache’s ability to incur debt secured by certain liens and its ability to enter into certain sale and leaseback transactions. Upon certain changes in control, all of these debt instruments would be subject to mandatory repurchase, at the option of the holders. None of the indentures for the notes contain prepayment obligations in the event of a decline in credit ratings. In November 2016, the Company initiated a program to purchase in the open market up to $250 million in aggregate principal amount of senior notes issued under its indentures. In the fourth quarter of 2016, Apache purchased and canceled $181 million aggregate principal amount of its senior notes through open market repurchases for $182 million in cash, including accrued interest and $0.5 million of premium. These repurchases resulted in a $1 million net loss on extinguishment of debt, which is included in “Financing costs, net” in Apache’s consolidated statement of operations. The net loss includes an acceleration of related discount and deferred financing costs. In January 2017, the Company purchased and canceled an additional $69 million aggregate principal amount of senior notes for $71 million in cash, including accrued interest and $1 million of premium, which completed the open market repurchase program. These repurchases resulted in a $1 million net loss on extinguishment of debt, which is included in “Financing costs, net” in the Company’s consolidated statement of operations. The net loss includes an acceleration of related discount and deferred financing costs. In August 2017, Apache Corporation assumed the obligations of Apache Finance Canada Corporation (AFCC) in respect of $300 million 7.75% notes due in 2029 which AFCC issued and the Company guaranteed pursuant to the governing indenture. The assumption was permitted by the indenture and effected pursuant to a supplemental indenture thereto. As a result of the assumption, the Company is the obligor under the notes and indenture, and AFCC is released from its obligations thereunder. The $300 million 7.75% notes historically have been included in the Company’s long-term debt; accordingly, the assumption did not change the Company’s long-term debt or total debt. The following table presents the carrying value of the Company’s debt at December 31, 2017 and 2016 : December 31, 2017 2016 (In millions) Commercial paper $ — $ — 6.9% notes due 2018 (1) 400 400 7.0% notes due 2018 (2) 150 150 7.625% notes due 2019 150 150 3.625% notes due 2021 (1) 493 493 3.25% notes due 2022 (1) 814 857 2.625% notes due 2023 (1) 528 528 7.7% notes due 2026 100 100 7.95% notes due 2026 180 180 7.75% notes due 2029 (3) 300 300 6.0% notes due 2037 (1) 1,000 1,000 5.1% notes due 2040 (1) 1,499 1,499 5.25% notes due 2042 (1) 500 500 4.75% notes due 2043 (1) 1,413 1,413 4.25% notes due 2044 (1) 753 780 7.375% debentures due 2047 150 150 7.625% debentures due 2096 150 150 Debt before unamortized discount and deferred loan costs 8,580 8,650 Unamortized discount (47 ) (50 ) Deferred loan costs (49 ) (56 ) Total debt 8,484 8,544 Current maturities (550 ) — Long-term debt $ 7,934 $ 8,544 (1) These notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The remaining notes and debentures are not redeemable. (2) On February 1, 2018, Apache’s 7.0% notes due 2018 in original principal amount of $150 million matured and were repaid. (3) Assumed in August 2017 as permitted by terms of these notes originally issued by a subsidiary and guaranteed by Apache. Since these notes historically have been included in Apache’s long-term debt, the assumption did not change Apache’s long-term debt or total debt. Debt maturities as of December 31, 2017 , excluding discounts and deferred loan costs, are as follows: (In millions) 2018 $ 550 2019 150 2020 — 2021 493 2022 814 Thereafter 6,573 Total Debt, excluding discounts and deferred loan costs $ 8,580 Fair Value Apache’s debt is recorded at the carrying amount, net of unamortized discount and deferred loan costs, on the Company’s consolidated balance sheet. The carrying amount, if any, of the Company’s commercial paper and uncommitted credit facilities and overdraft lines approximate fair value because the interest rates are variable and reflective of market rates. Apache uses a market approach to determine the fair value of its fixed-rate debt using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement). December 31, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value (In millions) Commercial paper $ — $ — $ — $ — Notes and debentures 8,484 9,244 8,544 9,183 Total Debt $ 8,484 $ 9,244 $ 8,544 $ 9,183 Money Market and Overdraft Lines of Credit The Company has certain uncommitted money market and overdraft lines of credit that are used from time to time for working capital purposes. As of December 31, 2017 and 2016 , there were no outstanding balances on Apache’s lines of credit. Unsecured Committed Bank Credit Facilities In June 2015, the Company entered into a five -year revolving credit facility which matures in June 2020 , subject to Apache’s two , one -year extension options. The facility provides for aggregate commitments of $3.5 billion (including a $750 million letter of credit subfacility), with rights to increase commitments up to an aggregate $4.5 billion . Proceeds from borrowings may be used for general corporate purposes. Apache’s available borrowing capacity under this facility supports its commercial paper program. As of December 31, 2017 , there were no borrowings under this credit facility, leaving aggregate available borrowing capacity at $3.5 billion . At the Company’s option, the interest rate per annum for borrowings under the 2015 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, 2017 , the base rate margin was 0.075 percent , the LIBOR margin was 1.075 percent , and the facility fee was 0.175 percent . The financial covenants of the 2015 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 2015 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, purchase money liens, 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. The Company also may incur liens on assets if debt secured thereby does not exceed 5 percent of the Company’s consolidated assets, or approximately $1.1 billion as of December 31, 2017 . 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 February 2016, Apache entered into a letter of credit facility providing £900 million in commitments and rights to increase commitments to £1.075 billion . The facility matures in February 2020 and is available for letters of credit denominated in pounds sterling, U.S. Dollars, Canadian Dollars, and any other foreign currency consented to by an issuing bank. The facility also is available for loans in pounds sterling, U.S. Dollars, and Canadian Dollars to cash collateralize letters of credit or obligations to provide letters of credit, in each case, to the extent letters of credit are unavailable under the facility. The facility’s representations and warranties, covenants, and events of default are substantially similar to those in Apache’s 2015 $3.5 billion revolving credit facility. Commissions are payable on letters of credit outstanding under the 2016 facility at a per annum rate equal to a LIBOR margin. Borrowings bear interest per annum at a base rate or LIBOR, plus a margin. A facility fee at a per annum rate on aggregate commitments also is payable. Letter of credit commissions, the interest margin, and the facility fee vary depending on Apache’s senior unsecured long-term debt rating. At December 31, 2017 , the LIBOR margin was 1.075 percent , the base rate margin was 0.075 percent , and the facility fee was 0.175 percent . The 2016 facility is available for the Company’s letter of credit needs, particularly those which may arise in respect of abandonment obligations assumed in various North Sea acquisitions. As of December 31, 2017 , three letters of credit aggregating approximately £129.1 million and no borrowings were outstanding under this facility. There are no clauses in the 2015 $3.5 billion or 2016 £900 million credit facilities that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. The agreements for these facilities do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, the agreements allow the lenders to accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches, and if the Company 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 if the Company undergoes a specified change in control or any borrower has specified pension plan liabilities in excess of the stated threshold. The Company was in compliance with the terms of these credit facilities as of December 31, 2017 . Commercial Paper Program The Company has available a $3.5 billion commercial paper program which, subject to market availability, facilitates Apache borrowing funds for up to 270 days at competitive interest rates. The commercial paper program is fully supported by available borrowing capacity under the Company’s 2015 committed credit facility. At December 31, 2017 and 2016 , 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, 2017 2016 2015 (In millions) Interest expense $ 457 $ 464 $ 486 Amortization of deferred loan costs 9 8 11 Capitalized interest (51 ) (48 ) (15 ) Loss on extinguishment of debt 1 1 39 Interest income (19 ) (8 ) (10 ) Financing costs, net $ 397 $ 417 $ 511 As of December 31, 2017 , the Company has $47 million of debt discounts, which will be charged to interest expense over the life of the related debt issuances. Discount amortization of $3 million was recorded as interest expense in each of 2017 , 2016 , and 2015 .

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Income (loss) from continuing operations before income taxes is composed of the following: For the Year Ended December 31, 2017 2016 2015 (In millions) U.S. $ (3,620 ) $ (997 ) $ (9,386 ) Foreign 4,538 (685 ) (2,783 ) Total $ 918 $ (1,682 ) $ (12,169 ) The total income tax provision (benefit) from continuing operations consists of the following: For the Year Ended December 31, 2017 2016 2015 (In millions) Current income taxes: Federal $ (38 ) $ (14 ) $ 363 State (8 ) (30 ) 41 Foreign 641 435 31 595 391 435 Deferred income taxes: Federal (1,010 ) (257 ) (1,123 ) State — — (51 ) Foreign (170 ) (576 ) (271 ) (1,180 ) (833 ) (1,445 ) Total $ (585 ) $ (442 ) $ (1,010 ) The total income tax provision (benefit) 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) from continuing operations before income taxes and total tax expense is shown below: For the Year Ended December 31, 2017 2016 2015 (In millions) Income tax expense (benefit) at U.S. statutory rate $ 321 $ (589 ) $ (4,259 ) State income tax, less federal effect (1) (6 ) (19 ) (7 ) Taxes related to foreign operations (105 ) 303 (662 ) Tax credits (33 ) (1 ) (6 ) Tax on distributed foreign earnings — 80 726 Tax on deemed repatriation of foreign earnings 419 — — Foreign tax credits (201 ) (136 ) (2,090 ) Deferred tax on undistributed foreign earnings (1,872 ) (31 ) 1,903 Tax impact of goodwill adjustments — — 82 Change in U.K. tax rate — (238 ) (414 ) Change in U.S. tax rate 516 — — Net change in tax contingencies (1 ) (19 ) 20 Canadian USD functional currency election — 158 — Sale of Canadian assets 279 — — Sale of North Sea GTP assets (48 ) — — Valuation allowances (1) 161 10 3,746 All other, net (15 ) 40 (49 ) $ (585 ) $ (442 ) $ (1,010 ) (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: December 31, 2017 2016 (In millions) Deferred tax assets: Deferred income $ 13 $ 105 U.S. and state net operating losses 1,230 1,095 Capital losses 620 — Foreign net operating losses 6 1,424 Tax credits and other tax incentives 28 62 Foreign tax credits 2,427 2,226 Accrued expenses and liabilities 110 153 Asset retirement obligation 629 875 Property and equipment — 1,189 Other 42 — Total deferred tax assets 5,105 7,129 Valuation allowance (3,816 ) (5,401 ) Net deferred tax assets 1,289 1,728 Deferred tax liabilities: Investment in foreign subsidiaries — 1,872 Equity investments 18 23 Property and equipment 1,798 1,533 Other — 5 Total deferred tax liabilities 1,816 3,433 Net deferred income tax liability $ 527 $ 1,705 Net deferred tax assets and liabilities are included in the consolidated balance sheet as follows: December 31, 2017 2016 (In millions) Assets: Deferred charges and other $ 18 $ 5 Liabilities: Deferred income taxes 545 1,710 Net deferred income tax liability $ 527 $ 1,705 On December 22, 2017, the Tax Cuts and Jobs Act (the Act) was signed into law. In addition to reducing the corporate income tax rate from 35 percent to 21 percent effective January 1, 2018, certain provisions in the Act move the U.S. away from a worldwide tax system and closer to a territorial system for earnings of foreign corporations, establishing a participation exemption system for taxation of foreign income. The new law includes a transition rule to effect this participation exemption regime. As a result of the enacted legislation, taxpayers are required to include in taxable income for the tax year ending December 31, 2017, the pro rata share of deferred income of each specified foreign corporation with respect to which the taxpayer is a U.S. shareholder. In 2017, the Company recorded a provisional net deferred tax benefit of $822 million to reverse a previously recorded deferred tax liability for unrepatriated earnings and to account for the transition rule under the new law. In addition and as a result of the decrease in the corporate income tax rate, the Company recorded a provisional $516 million deferred tax expense in 2017 related to the remeasurement of the Company’s December 31, 2017 deferred tax asset. The Company continues to assess other provisions of the Act including, among other items, the interaction between the deemed repatriation of foreign earnings and 2017 net operating losses as well as the applicability of new taxes on certain future foreign earnings. Provisional amounts for the income tax effects of the Act have been recorded as of December 31, 2017 and are subject to change during 2018. In 2016, the U.K. government enacted Finance Bill 2016, which provides tax relief to E&P companies operating in the North Sea through a reduction of Supplementary Charge from 20 percent to 10 percent , effective January 1, 2016. As a result of the enacted legislation, in 2016, Apache recorded a deferred tax benefit of $238 million related to the remeasurement of the Company’s December 31, 2015 U.K. deferred income tax liability. In 2015, Apache repatriated the sales proceeds from the divestment of its interest in LNG projects and Australian upstream assets. Upon the repatriation of these proceeds, Apache recognized a U.S. current income tax liability of $560 million . Also in 2015, the U.K. government enacted Finance Bill 2015, which provided a reduction of Supplementary Charge from 32 percent to 20 percent , effective January 1, 2015. As a result of the enacted legislation, in 2015, Apache recorded a deferred tax benefit of $414 million related to the remeasurement of the Company’s December 31, 2014 U.K. deferred income tax liability. 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 2017 , 2016 , and 2015 , the Company’s valuation allowance decreased by $1.6 billion , decreased by $33 million , and increased by $3.9 billion , respectively, as detailed in the table below: 2017 2016 2015 (In millions) Balance at beginning of year $ 5,401 $ 5,434 $ 1,564 State (1) 139 (43 ) 151 U.S. 905 139 2,159 Foreign (2) (2,629 ) (129 ) 1,560 Balance at end of year $ 3,816 $ 5,401 $ 5,434 (1) Reported as a component of state income taxes. (2) In 2017, the Company completed the sale of its Canadian assets. As such, except for capital losses incurred on the sale, the deferred tax assets, liabilities, and valuation allowance related to these assets were removed for 2017. In 2015, Apache's subsidiaries completed the sale of its interest in the Kitimat LNG project. As such, the deferred tax assets, liabilities, and valuation allowance related to the project were removed for 2015. On December 31, 2017 , the Company had net operating losses as follows: Amount Expiration (In millions) Net operating losses: U.S. $ 4,037 2018 - 2038 State 5,301 Various The Company has a U.S. net operating loss carryforward of $4.0 billion , which includes $197 million of net operating loss subject to annual limitation under Section 382 of the Internal Revenue Code. The Company also has a U.S. capital loss carryforward of $1.8 billion , which has a five year carryover period 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 U.S. capital loss and the Canadian capital loss because it is probable that these attributes will not be realized. On December 31, 2017 , the Company had foreign tax credits as follows: Amount Expiration (In millions) Foreign tax credits $ 2,427 2025-2026 The Company has a $2.4 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 probable 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: 2017 2016 2015 (In millions) Balance at beginning of year $ 15 $ 19 $ — Additions based on tax positions related to the current year 12 15 19 Reductions for tax positions of prior years (1 ) (19 ) — Balance at end of year $ 26 $ 15 $ 19 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 the years ended December 31, 2017 and 2016 , the Company recorded no tax expense for interest and penalties. During the year ended December 31, 2015, the Company recorded tax expense of $1 million for interest and penalties. At December 31, 2017 and 2016 , the Company had no accrued liability for interest and penalties. At December 31, 2015 , the Company had an accrued liability for interest and penalties of $1 million . In 2017, 2016 and 2015, the Company recorded an $11 million net increase, $4 million net reduction, and a $19 million increase in its reserve for uncertain tax positions, respectively. In April 2017, the Internal Revenue Service (IRS) began their audit of the Company’s 2014 income tax year. 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. 2012 Egypt 1998 U.K. 2016

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES Legal Matters Apache is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls. The Company has an accrued liability of approximately $37 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. Apache’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 Apache’s financial position, results of operations, or liquidity after consideration of recorded accruals. For material matters that Apache 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 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 $67.5 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 Apache, 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, except as noted. Further, the overall exposure related to these lawsuits and claims is not currently determinable. While an adverse judgment against Apache is possible, Apache intends to actively defend these lawsuits and claims. On July 24, 2013, a lawsuit captioned Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East v. Tennessee Gas Pipeline Company et al. , Case No. 2013-6911 was filed in the Civil District Court for the Parish of Orleans, State of Louisiana, in which plaintiff on behalf of itself and as the board governing the levee districts of Orleans, Lake Borgne Basin, and East Jefferson alleged that Louisiana coastal lands have been damaged as a result of oil and gas industry activity, including a network of canals for access and pipelines. The defendants removed the case from state court to federal court and, on February 13, 2015, the federal court entered judgment in favor of defendants dismissing all of plaintiff’s claims with prejudice. Plaintiff appealed the lower court’s dismissal to the 5 th Circuit Court of Appeals and additionally challenged the defendants’ right to remove the case to federal court. On March 3, 2017, the 5 th Circuit Court of Appeals affirmed the propriety of federal jurisdiction based in part on Apache’s argument that plaintiff’s state-based claims required a resolution of substantial questions of federal law and also affirmed the dismissal of the action. The Plaintiff filed a Petition for a Writ of Certiorari with the United States Supreme Court and that Petition was denied. Starting in November of 2013 and continuing into 2017, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including Apache. These cases are pending in federal and state courts in Louisiana. 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 state 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 an adverse judgment against Apache might be possible, Apache 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 385t h Judicial District Court, Midland County, Texas, plaintiffs allege 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. Apache believes that plaintiffs’ claims lack merit, and further that plaintiffs’ alleged damages are grossly inflated. Apache will vigorously oppose the claims. Escheat Audits In September 2010, the State of Delaware, Department of Finance, Division of Revenue (Unclaimed Property) (Delaware), notified Apache Corporation that Delaware’s consultant, Kelmar Associates, would examine Apache’s books and records and those of its subsidiaries and related entities to determine compliance with Delaware Escheat Laws. Delaware has notified the Company that its audit is complete and the matter has been resolved for an amount that is not material to the Company. Australian Operations Divestiture Dispute By a Sale and Purchase Agreement dated April 9, 2015 (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, Apache filed suit against Quadrant for breach of the SPA. In its suit, Apache seeks approximately $80 million . In December 2017, Quadrant filed a defense of equitable set-off to Apache’s claim and a counterclaim seeking approximately $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. California 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, gas, and coal 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. Apache believes that the claims made against it are baseless 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. Apache 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 Apache’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 Apache’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, 2017 , the Company had an undiscounted reserve for environmental remediation of approximately $4 million . Apache is not aware of any environmental claims existing as of December 31, 2017 that have not been provided for or would otherwise have a material impact on its financial position or results of operations. 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. ACL, a former subsidiary of the Company, previously reported produced water spills in a remote area of the Bellow Field and a hydrogen sulfide and oil emulsion leak in the Zama area. The Company sold ACL in a transaction that was completed in the third quarter of 2017. The Canadian environmental litigation and liabilities remained with ACL and are now the responsibility of the acquirer. Contractual Obligations At December 31, 2017 , contractual obligations for long-term operating leases, capital leases, and purchase obligations are as follows: Net Minimum Commitments Total 2018 2019-2020 2021-2022 2023 & Beyond (In millions) Drilling rigs (1) $ 85 $ 20 $ 65 $ — $ — Purchase obligations (2) 1,275 183 296 214 582 Operating lease obligations (3) 233 54 81 57 41 Capital lease obligations (4) $ 41 $ 1 $ 3 $ 3 $ 34 Total Net Minimum Commitments (5) $ 1,634 $ 258 $ 445 $ 274 $ 657 (1) Payments associated with the drilling of exploratory wells and development wells net of amounts billed to partners will be capitalized as a component of oil and gas properties, and either depreciated, impaired, or written off as exploration expense. (2) Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Includes amounts related to firm transportation capacity on the Gulf Coast Express Pipeline Project (GCX Project), expected to be in service in October 2019. 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. (3) Amounts include long-term lease payments for office space, aircraft, supply and standby vessels, land leases, and equipment related to exploration, development, and production activities. The Company expects to receive $1 million in sublease income associated with these leases. (4) This represents our capital lease obligation related to our 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 $18 million as of December 31, 2017. (5) Excludes purchase commitments for jointly owned fields and facilities for which the Company is not the operator. The table above includes leases for buildings, facilities, and related equipment with varying expiration dates through 2042 . Total rent expense, net of amounts capitalized and sublease income, for continuing operations was $82 million , $59 million , and $57 million for 2017 , 2016 , and 2015 , respectively. Costs incurred under take-or-pay and throughput obligations were $134 million , $86 million , and $92 million for 2017 , 2016 , and 2015 , respectively.

RETIREMENT AND DEFERRED COMPENS

RETIREMENT AND DEFERRED COMPENSATION PLANS	12 Months Ended
	Dec. 31, 2017
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 annually contributes 6 percent of each participating employee’s annual eligible compensation to a money purchase retirement plan. The 401(k) savings plan and the money purchase retirement plan are subject to certain annually-adjusted, government-mandated restrictions that limit the amount of employee and Company contributions. For certain eligible employees, the Company also provides a non-qualified retirement/savings plan or a non-qualified restorative retirement savings plan. These plans allow the deferral of up to 50 percent of each employee’s base salary, up to 75 percent of each employee’s annual bonus (that accepts employee contributions) and the Company’s matching contributions in excess of the government mandated limitations imposed in the 401(k) savings plan and money purchase retirement plan. Vesting in the Company’s contributions in the 401(k) savings plan, the money purchase retirement plan, the non-qualified retirement savings plan and the non-qualified restorative retirement savings plan occurs at the rate of 20 percent for every completed year of employment. Upon a change in control of ownership of 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 $55 million , $52 million , and $59 million for 2017 , 2016 , and 2015 , 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, 2017 , 2016 , and 2015 , 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. 2017 2016 2015 Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits (In millions) Change in Projected Benefit Obligation Projected benefit obligation beginning of year $ 202 $ 26 $ 202 $ 26 $ 216 $ 22 Service cost 4 2 4 2 5 2 Interest cost 6 1 7 1 8 1 Foreign currency exchange rate changes 20 — (39 ) — (10 ) — Actuarial losses (gains) (4 ) 1 32 (2 ) (10 ) — Effect of curtailment and settlements — — — — — 2 Benefits paid (12 ) (4 ) (4 ) (3 ) (7 ) (2 ) Retiree contributions — 1 — 2 — 1 Projected benefit obligation at end of year 216 27 202 26 202 26 Change in Plan Assets Fair value of plan assets at beginning of year 206 — 197 — 206 — Actual return on plan assets 17 — 46 — 1 — Foreign currency exchange rates 22 — (39 ) — (10 ) — Employer contributions 5 3 6 1 7 1 Benefits paid (12 ) (4 ) (4 ) (3 ) (7 ) (2 ) Retiree contributions — 1 — 2 — 1 Fair value of plan assets at end of year 238 — 206 — 197 — Funded status at end of year $ 22 $ (27 ) $ 4 $ (26 ) $ (5 ) $ (26 ) Amounts recognized in Consolidated Balance Sheet Current liability $ — $ (2 ) $ — $ (2 ) $ — $ (2 ) Non-current asset (liability) 22 (25 ) 4 (24 ) (5 ) (24 ) $ 22 $ (27 ) $ 4 $ (26 ) $ (5 ) $ (26 ) Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss) Accumulated gain (loss) $ (11 ) $ 8 $ (25 ) $ 9 $ (32 ) $ 9 Weighted Average Assumptions used as of December 31 Discount rate 2.60 % 3.44 % 2.70 % 3.76 % 3.90 % 3.95 % Salary increases 4.70 % N/A 4.80 % N/A 4.60 % N/A Expected return on assets 2.90 % N/A 3.40 % N/A 4.10 % N/A Healthcare cost trend Initial N/A 6.75 % N/A 7.00 % N/A 7.00 % Ultimate in 2025 N/A 5.00 % N/A 5.00 % N/A 5.00 % As of December 31, 2017 , 2016 , and 2015 , the accumulated benefit obligation for the U.K. Pension Plan was $193 million , $181 million , and $169 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 Allocation Percentage of Plan Assets at Year-End 2017 2017 2016 Asset Category Equity securities: U.K. quoted equities — — 14 % Overseas quoted equities 26 % 26 % 26 % Total equity securities 26 % 26 % 40 % Debt securities: U.K. Government bonds 59 % 58 % 47 % U.K. corporate bonds 15 % 14 % 12 % Debt securities 74 % 72 % 59 % Cash — 2 % 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 is 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, 2017 and December 31, 2016 : Fair Value Measurements Using: Quoted Price in Active Markets (Level 1) Significant Other Inputs (Level 2) Unobservable Inputs (Level 3) Total Fair Value (In millions) December 31, 2017 Equity securities: Overseas quoted equities (1) $ 61 $ — $ — $ 61 Total equity securities 61 — — 61 Debt securities: U.K. Government bonds (2) 138 — — 138 U.K. corporate bonds (3) 33 — — 33 Total debt securities 171 — — 171 Cash 6 — — 6 Fair value of plan assets $ 238 $ — $ — $ 238 December 31, 2016 Equity securities: U.K. quoted equities (4) $ 28 $ — $ — $ 28 Overseas quoted equities (1) 54 — — 54 Total equity securities 82 — — 82 Debt securities: U.K. Government bonds (2) 97 — — 97 U.K. corporate bonds (3) 25 — — 25 Total debt securities 122 — — 122 Cash 2 — — 2 Fair value of plan assets $ 206 $ — $ — $ 206 (1) This category includes overseas equities, which comprises 20 percent passive global equities benchmarked against the MSCI World (NDR) Index, 25 percent passive global equities (hedged) benchmarked against the MSCI World (NDR) Hedged Index, 20 percent fundamental indexation global equities benchmarked against the FTSE RAFI Developed 1000 index, 25 percent fundamental indexation global equities (hedged) benchmarked against the FTSE RAFI Developed 1000 Hedge Index, and 10 percent emerging markets benchmarked against the MSCI Emerging Markets (NDR) Index, which has a performance target of 2 percent per annum over the benchmark over a rolling three -year period. (2) This category includes U.K. Government bonds, which comprises 47 percent index-linked gilts benchmarked against the FTSE Actuaries Government Securities Index-Linked Over 5 Years Index, 38 percent sterling nominal LDI bonds, and 15 percent sterling inflation linked LDI bonds, both benchmarked against ILIM Custom Benchmark index. (3) This category comprises U.K. corporate bonds benchmarked against the BofAML Sterling Corporate & Collaterlised (excluding Subordinated) Index. (4) This category comprises U.K. passive equities, which are benchmarked against the FTSE 350 Index. 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, 2017 , 2016 , and 2015 : 2017 2016 2015 Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits (In millions) Components of Net Periodic Benefit Cost Service cost $ 4 $ 2 $ 4 $ 2 $ 5 $ 2 Interest cost 6 1 7 1 8 1 Expected return on assets (8 ) — (7 ) — (8 ) — Amortization of actuarial (gain) loss — (1 ) 1 (1 ) 2 — Net periodic benefit cost $ 2 $ 2 $ 5 $ 2 $ 7 $ 3 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31 Discount rate 2.70 % 3.76 % 3.90 % 3.95 % 3.70 % 3.62 % Salary increases 4.80 % N/A 4.60 % N/A 4.60 % N/A Expected return on assets 3.40 % N/A 4.10 % N/A 3.90 % N/A Healthcare cost trend Initial N/A 7.00 % N/A 7.00 % N/A 7.00 % Ultimate in 2025 N/A 5.00 % N/A 5.00 % N/A 5.00 % Assumed health care cost trend rates affect amounts reported for postretirement benefits. A one-percentage-point change in assumed health care cost trend rates would have the following effects: Postretirement Benefits 1% Increase 1% Decrease (In millions) Effect on service and interest cost components $ 1 $ (1 ) Effect on postretirement benefit obligation 5 (4 ) Apache expects to contribute approximately $6 million to its pension plan and $2 million to its postretirement benefit plan in 2018 . The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: Pension Benefits Postretirement Benefits (In millions) 2018 $ 3 $ 2 2019 3 2 2020 4 2 2021 4 2 2022 4 2 Years 2023-2027 21 8

CAPITAL STOCK

CAPITAL STOCK	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
CAPITAL STOCK	CAPITAL STOCK Common Stock Outstanding A summary of the shares issued and outstanding for the years ended December 31, 2017 , 2016 , and 2015 is presented in the table below. 2017 2016 2015 Balance, beginning of year 379,439,676 378,034,175 376,504,892 Shares issued for stock-based compensation plans: Treasury shares issued 1,411 11,504 17,525 Common shares issued 1,513,777 1,393,997 1,511,758 Balance, end of year 380,954,864 379,439,676 378,034,175 Net Income (Loss) per Common Share A reconciliation of the components of basic and diluted net income (loss) per common share for the years ended December 31, 2017 , 2016 , and 2015 is presented in the table below. 2017 2016 2015 Income Shares Per Share Loss Shares Per Share Income (Loss) Shares Per Share (In millions, except per share amounts) Basic: Income (loss) from continuing operations $ 1,304 381 $ 3.42 $ (1,372 ) 379 $ (3.62 ) $ (10,844 ) 378 $ (28.70 ) Income (loss) from discontinued operations — 381 — (33 ) 379 (0.09 ) 492 378 1.30 Income (loss) attributable to common stock $ 1,304 381 $ 3.42 $ (1,405 ) 379 $ (3.71 ) $ (10,352 ) 378 $ (27.40 ) Effect of Dilutive Securities: Stock options and other $ — 2 $ (0.01 ) $ — — $ — $ — — $ — Diluted: Income (loss) from continuing operations $ 1,304 383 $ 3.41 $ (1,372 ) 379 $ (3.62 ) $ (10,844 ) 378 $ (28.70 ) Income (loss) from discontinued operations — 383 — (33 ) 379 (0.09 ) 492 378 1.30 Income (loss) attributable to common stock $ 1,304 383 $ 3.41 $ (1,405 ) 379 $ (3.71 ) $ (10,352 ) 378 $ (27.40 ) The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 7.3 million , 4.7 million , and 7.0 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Stock Repurchase Program Apache’s Board of Directors has 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, 2017 , had repurchased a total of 32.2 million shares at an average price of $88.96 per share. The Company is not obligated to acquire any specific number of shares and has not purchased any shares during 2017 . Common Stock Dividend For each of the years ended December 31, 2017, 2016, and 2015, the Company paid common stock dividends of $1.00 per share. Stock Compensation Plans The Company has 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 intended to provide eligible employees with equity-based incentives. The 2016 Plan provides for the granting of 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. A total of 16.9 million shares were authorized and available for grant under the 2016 Plan as of December 31, 2017 . 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. For 2017 , 2016 , and 2015 , stock-based compensation expensed was $142 million , $131 million , and $100 million , respectively. Costs related to the plans are capitalized or expensed based on the nature of each employee’s activities. A description of the Company’s stock-based compensation plans and related costs follows: 2017 2016 2015 (In millions) Stock-based compensation expensed $ 142 $ 131 $ 100 Stock-based compensation capitalized 41 40 53 Total stock-based compensation costs $ 183 $ 171 $ 153 Stock Options As of December 31, 2017 , the Company had issued options to purchase shares of the Company’s common stock under the 2007 Omnibus Equity Compensation Plan, the 2011 Omnibus Equity Compensation Plan (2011 Plan), and the 2016 Plan (together, the Omnibus Plans). New shares of Company 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 issued prior to 2016 generally become exercisable ratably over a four -year period and expire 10 years after granted. Options granted in or after 2016 become exercisable ratably over a three -year period and expire 10 years after granted. The Omnibus Plans were submitted to and approved by the Company’s shareholders. A summary of stock options issued and outstanding under the Omnibus Plans is presented in the table and narrative below: 2017 Shares Under Option Weighted Average Exercise Price (In thousands) Outstanding, beginning of year 5,113 $ 84.89 Granted 490 63.25 Exercised (15 ) 41.24 Forfeited or expired (995 ) 82.03 Outstanding, end of year (1) 4,593 83.37 Expected to vest (2) 947 51.83 Exercisable, end of year (3) 3,646 91.56 (1) As of December 31, 2017 , options outstanding had a weighted average remaining contractual life of 4.7 years and aggregate intrinsic value of $0.7 million . (2) As of December 31, 2017 , options expected to vest had a weighted average remaining contractual life of 8.5 years and aggregate intrinsic value of $0.5 million . (3) As of December 31, 2017 , options exercisable had a weighted average remaining contractual life of 3.7 years and aggregate intrinsic value of $0.2 million . The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model. Assumptions used in the valuation are disclosed in the following table. Expected volatilities are based on historical volatility of the Company’s 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. 2017 2016 2015 Expected volatility 34.58 % 32.72 % N/A Expected dividend yields 1.58 % 2.42 % N/A Expected term (in years) 6 6 N/A Risk-free rate 2.02 % 1.44 % N/A Weighted-average grant-date fair value $ 19.38 $ 10.38 N/A The intrinsic values of options exercised during 2017 and 2015 were approximately $0.2 million and $3 million , respectively. There were no options exercised during 2016. As of December 31, 2017 , the total compensation cost related to non-vested options not yet recognized was $8 million , which will be recognized over the remaining vesting period of the options. In January 2018, the Company issued 760,904 options to purchase shares of the Company’s common stock to eligible employees under the 2016 Plan, at an average fair value of $13.15 per share. The total compensation cost of $10 million is estimated to be recognized over a three -year vesting period of these options. Restricted Stock and Restricted Stock Units The Company has restricted stock and restricted stock unit plans for eligible employees including officers. The programs created under the Omnibus Plans have been approved by Apache’s Board of Directors. In 2017 , the Company awarded 1,947,506 restricted stock units at a weighted-average per-share market price of $62.74 . In 2016 and 2015 , the Company awarded 4,049,023 and 2,976,562 restricted stock units at a weighted-average per-share market price of $47.37 and $61.65 , respectively. The value of the stock issued was established by the market price on the date of grant and is being recorded as compensation expense ratably over the vesting terms. During 2017 , 2016 , and 2015 , $108 million , $113 million , and $90 million , respectively, were charged to expense. In 2017 , 2016 , and 2015 , $35 million , $35 million , and $48 million were capitalized, respectively. As of December 31, 2017 , there was $158 million of total unrecognized compensation cost related to 4,919,681 unvested restricted stock units. The weighted-average remaining life of unvested restricted stock units is approximately 1.0 years. The fair values of the awards vested during 2017 , 2016 , and 2015 were approximately $135 million , $151 million , and $149 million , respectively. A summary of restricted stock unit activity for the year ended December 31, 2017 , is presented below. Shares Weighted- Average Grant- Date Fair Value (In thousands) Non-vested at January 1, 2017 6,062 $ 55.11 Granted 1,948 62.74 Vested (2,288 ) 58.77 Forfeited (802 ) 55.54 Non-vested at December 31, 2017 4,920 56.34 In January 2018, the Company awarded 507,042 restricted stock units and 1,954,474 cash-settled awards (phantom units) at a weighted-average per-share market price of $46.27 under the 2016 Plan to eligible employees. The phantom units represent a hypothetical interest in the Company’s stock and, once vested, are settled in cash. Total compensation cost for restricted stock units and phantom units absent any forfeitures, is estimated to be $23 million and $90 million , respectively, and was calculated based on the 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. Performance Program To provide long-term incentives for Apache employees to deliver competitive returns to the Company’s stockholders, the Company has granted 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, 2017 , are as described below: • In February 2015, the Company’s Board of Directors approved the 2015 Performance Program, pursuant to the 2011 Plan. Eligible employees received initial conditional restricted stock unit awards totaling 602,304 units. The results for the performance period ending December 31, 2017, yielded a payout of 100 percent of target. A total of 384,967 units were outstanding as of December 31, 2017 . • In January 2016, the Company’s Board of Directors approved the 2016 Performance Program, pursuant to the 2011 Plan. Eligible employees received initial conditional restricted stock unit awards totaling 871,369 . The actual amount of shares awarded will be between zero and 200 percent of target. A total of 749,334 units were outstanding as of December 31, 2017 , from which a minimum of zero and a maximum of 1,498,668 units could be awarded. • In January 2017, the Company’s Board of Directors approved the 2017 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial conditional restricted stock unit awards totaling 620,885 units. The actual amount of shares awarded will be between zero and 200 percent of target. A total of 559,336 units were outstanding as of December 31, 2017 , from which a minimum of zero to a maximum of 1,118,672 units could be awarded. The fair value cost of the awards was estimated on the date of grant and is being recorded as compensation expense ratably over the vesting terms. During 2017 , 2016 , and 2015 , $23 million , $14 million , and $3 million , respectively, were charged to expense. During 2017 , 2016 , and 2015 , $4 million , $2 million , and $1 million were capitalized, respectively. As of December 31, 2017 , there was $38 million of total unrecognized compensation cost related to 1,693,637 unvested conditional restricted stock units. The weighted-average remaining life of the unvested conditional restricted stock units is approximately 1.6 years. Shares Weighted Average Grant- Date Fair Value (1) (In thousands) Non-vested at January 1, 2017 1,225 $ 45.62 Granted 621 66.97 Forfeited (152 ) 52.90 Non-vested at December 31, 2017 1,694 52.39 (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. In January 2018, the Company’s Board of Directors approved the 2018 Performance Program, pursuant to the 2016 Plan, with terms similar to the 2017 Performance Program described above. Eligible employees received the initial conditional phantom units totaling 872,030 units, with the ultimate number of phantom units to be awarded ranging from zero to a maximum of 1,744,060 units. These phantom units represent a hypothetical interest in the Company’s stock, and, once vested, are settled in cash. The TSR component of the award had a grant date fair value per award of $54.70 based on a Monte Carlo simulation. The grant date fair value per award for the remaining 50 percent was $46.27 based on the fair market value of a share of common stock of the Company as of the grant date. These phantom units will be classified as a liability and remeasured at the end of each reporting period.

ACCUMULATED OTHER COMPREHENSIVE

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Components of accumulated other comprehensive income (loss) include the following: For the Year Ended December 31, 2017 2016 2015 (In millions) Currency translation adjustment (1) $ — $ (109 ) $ (109 ) Pension and postretirement benefit plan (Note 10) 4 (3 ) (10 ) Accumulated other comprehensive income (loss) $ 4 $ (112 ) $ (119 ) (1) Currency translation adjustments resulting from translating Apache’s Canadian subsidiaries’ financial statements into U.S. dollar equivalents, prior to adoption of the U.S. dollar as their functional currency, were reported separately and accumulated in other comprehensive loss. This currency translation loss was recognized as a reduction of the net gain on divestiture during the third quarter of 2017 in connection with the Canada divestitures. For more information regarding these divestitures, please refer to Note 2—Acquisitions and Divestitures.

MAJOR CUSTOMERS

MAJOR CUSTOMERS	12 Months Ended
	Dec. 31, 2017
Risks and Uncertainties [Abstract]
MAJOR CUSTOMERS	MAJOR CUSTOMERS For the years ended 2017 , 2016 , and 2015 , the customers, including their subsidiaries, that represented more than 10 percent of the Company’s worldwide oil and gas production revenues were as follows: For the Year Ended December 31, 2017 2016 2015 BP plc 12 % 9 % 8 % China Petroleum & Chemical Corporation 16 % 21 % 12 % Egyptian General Petroleum Corporation 11 % 12 % 11 % Royal Dutch Shell plc 6 % 5 % 11 %

BUSINESS SEGMENT INFORMATION

BUSINESS SEGMENT INFORMATION	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
BUSINESS SEGMENT INFORMATION	BUSINESS SEGMENT INFORMATION Apache is engaged in a single line of business. Both domestically and internationally, the Company explores for, develops, and produces natural gas, crude oil and natural gas liquids. At December 31, 2017 , the Company had operations in three reporting segments: the U.S., Egypt, and the North Sea. Apache also has exploration interests in Suriname that may, over time, result in a reportable discovery and development opportunity. In the second quarter of 2015, Apache completed the sale of its Australian LNG business and oil and gas assets, and as such the results of Australia oil and gas assets have been classified as discontinued operations. Financial information for each area is presented below: United Canada (1) Egypt (2) North Sea Other Total (2) (In millions) 2017 Oil and gas production revenues $ 2,271 $ 231 $ 2,307 $ 1,078 $ — $ 5,887 Operating Expenses: Lease operating expenses 600 103 362 335 — 1,400 Gathering and transportation 71 34 44 30 — 179 Taxes other than income 153 12 — (14 ) — 151 Depreciation, depletion, and amortization 1,000 76 758 446 — 2,280 Exploration 363 11 62 86 27 549 Asset retirement obligation accretion 31 27 — 72 — 130 Impairments — — — 8 — 8 Operating Income (Loss) $ 53 $ (32 ) $ 1,081 $ 115 $ (27 ) 1,190 Other Income (Expense): Gain on divestitures, net 627 Derivative instrument gains (losses), net (135 ) Other 44 General and administrative (395 ) Transaction, reorganization, and separation (16 ) Financing costs, net (397 ) Income Before Income Taxes $ 918 Net Property and Equipment $ 12,070 $ — $ 3,099 $ 2,553 $ 37 $ 17,759 Total Assets $ 14,228 $ — $ 4,658 $ 2,977 $ 59 $ 21,922 Additions to Net Property and Equipment $ 2,397 $ — $ 517 $ 374 $ 14 $ 3,302 United Canada Egypt (2) North Sea Other Total (2) (In millions) 2016 Oil and gas production revenues $ 1,997 $ 343 $ 2,057 $ 970 $ — $ 5,367 Operating Expenses: Lease operating expenses 553 181 446 314 — 1,494 Gathering and transportation 80 68 44 8 — 200 Taxes other than income 139 20 — (33 ) — 126 Depreciation, depletion, and amortization 1,138 183 778 519 — 2,618 Exploration 285 88 48 37 15 473 Asset retirement obligation accretion 34 47 — 75 — 156 Impairments 80 367 1 655 — 1,103 Operating Income (Loss) $ (312 ) $ (611 ) $ 740 $ (605 ) $ (15 ) (803 ) Other Income (Expense): Gain on divestitures, net 21 Other (34 ) General and administrative (410 ) Transaction, reorganization, and separation (39 ) Financing costs, net (417 ) Net Loss From Continuing Operations Before Income Taxes $ (1,682 ) Net Property and Equipment $ 11,168 $ 1,464 $ 3,362 $ 2,834 $ 39 $ 18,867 Total Assets $ 12,403 $ 1,591 $ 4,893 $ 3,584 $ 48 $ 22,519 Additions to Net Property and Equipment $ 926 $ 34 $ 459 $ 260 $ 2 $ 1,681 2015 Oil and gas production revenues $ 2,637 $ 498 $ 2,095 $ 1,280 $ — $ 6,510 Operating Expenses: Lease operating expenses 739 244 522 349 — 1,854 Gathering and transportation 68 89 45 9 — 211 Taxes other than income 184 26 9 63 — 282 Depreciation, depletion, and amortization 1,558 301 927 514 — 3,300 Exploration 2,145 231 154 237 4 2,771 Asset retirement obligation accretion 28 43 — 74 — 145 Impairments 6,266 1,593 1,255 211 147 9,472 Operating Loss $ (8,351 ) $ (2,029 ) $ (817 ) $ (177 ) $ (151 ) (11,525 ) Other Income (Expense): Gain on divestitures, net 281 Other 98 General and administrative (380 ) Transaction, reorganization, and separation (132 ) Financing costs, net (511 ) Net Loss From Continuing Operations Before Income Taxes $ (12,169 ) Net Property and Equipment $ 11,753 $ 2,074 $ 3,712 $ 3,263 $ 36 $ 20,838 Total Assets $ 12,782 $ 2,225 $ 6,165 $ 4,280 $ 48 $ 25,500 Additions to Net Property and Equipment $ 2,099 $ 403 $ 862 $ 715 $ 27 $ 4,106 (1) During the third quarter of 2017, Apache completed the sale of its Canadian operations. For more information regarding this divestiture, please refer to Note 2—Acquisitions and Divestitures. (2) Includes a noncontrolling interest in Egypt.

SUPPLEMENTAL OIL AND GAS DISCLO

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)	12 Months Ended
	Dec. 31, 2017
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. In the second quarter of 2015, Apache completed the sale of its Australian LNG business and oil and gas assets, and as such the results of Australia oil and gas assets have been classified as discontinued operations. United States Canada (3) Egypt (4) North Sea Other International Total (4)(5) (In millions, except per boe) 2017 Oil and gas production revenues $ 2,271 $ 231 $ 2,307 $ 1,078 $ — $ 5,887 Operating cost: Depreciation, depletion, and amortization (1) 924 72 707 433 — 2,136 Asset retirement obligation accretion 31 27 — 72 — 130 Lease operating expenses 600 103 362 335 — 1,400 Gathering and transportation 71 34 44 30 — 179 Exploration expenses 363 11 62 86 27 549 Production taxes (2) 153 11 — (14 ) — 150 Income tax 45 (7 ) 509 54 — 601 2,187 251 1,684 996 27 5,145 Results of operation $ 84 $ (20 ) $ 623 $ 82 $ (27 ) $ 742 2016 Oil and gas production revenues $ 1,997 $ 343 $ 2,057 $ 970 $ — $ 5,367 Operating cost: Depreciation, depletion, and amortization (1) 1,055 174 733 498 — 2,460 Asset retirement obligation accretion 34 47 — 75 — 156 Lease operating expenses 553 181 446 314 — 1,494 Gathering and transportation 80 68 44 8 — 200 Exploration expenses 285 88 48 37 15 473 Impairments related to oil and gas properties 61 366 — — — 427 Production taxes (2) 135 18 — (33 ) — 120 Income tax (72 ) (162 ) 354 28 — 148 2,131 780 1,625 927 15 5,478 Results of operation $ (134 ) $ (437 ) $ 432 $ 43 $ (15 ) $ (111 ) 2015 Oil and gas production revenues $ 2,637 $ 498 $ 2,095 $ 1,280 $ — $ 6,510 Operating cost: Depreciation, depletion, and amortization (1) 1,455 251 780 490 — 2,976 Asset retirement obligation accretion 28 43 — 74 — 145 Lease operating expenses 739 244 522 349 — 1,854 Gathering and transportation 68 89 45 9 — 211 Exploration expenses 2,145 231 154 237 4 2,771 Impairments related to oil and gas properties 6,154 1,031 193 11 — 7,389 Production taxes (2) 178 23 — 58 — 259 Income tax (2,886 ) (369 ) 180 26 — (3,049 ) 7,881 1,543 1,874 1,254 4 12,556 Results of operation $ (5,244 ) $ (1,045 ) $ 221 $ 26 $ (4 ) $ (6,046 ) (1) This amount only reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 14—Business Segment Information. (2) Only reflects amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 14—Business Segment Information. (3) During the third quarter of 2017, Apache completed the sale of its Canadian operations. For more information regarding this divestiture, please refer to Note 2—Acquisitions and Divestitures (4) Includes noncontrolling interest in Egypt. (5) Prior year amounts have been recast to exclude discontinued operations. Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities United States Canada Egypt (2) Australia North Sea Other International Total (2) (In millions) 2017 Acquisitions: Proved $ 3 $ — $ 4 $ — $ — $ — $ 7 Unproved 136 5 40 — — — 181 Exploration 602 11 122 — 131 25 891 Development 1,118 52 387 — 250 — 1,807 Costs incurred (1) $ 1,859 $ 68 $ 553 $ — $ 381 $ 25 $ 2,886 (1) Includes capitalized interest and asset retirement costs as follows: Capitalized interest $ 23 $ 2 $ — $ — $ 17 $ 2 $ 44 Asset retirement costs 15 — — — 55 — 70 2016 Acquisitions: Proved $ — $ 1 $ 6 $ — $ 38 $ — $ 45 Unproved 110 7 49 — 4 — 170 Exploration 278 23 67 — 84 18 470 Development 420 27 353 — 150 — 950 Costs incurred (1) $ 808 $ 58 $ 475 $ — $ 276 $ 18 $ 1,635 (1) Includes capitalized interest and asset retirement costs as follows: Capitalized interest $ 21 $ 6 $ — $ — $ 21 $ — $ 48 Asset retirement costs (51 ) (13 ) — — (128 ) — (192 ) 2015 Acquisitions: Proved $ 1 $ 8 $ 29 $ — $ — $ — $ 38 Unproved 313 23 — — — — 336 Exploration 194 51 125 32 246 29 677 Development 1,729 151 741 98 479 — 3,198 Costs incurred (1) $ 2,237 $ 233 $ 895 $ 130 $ 725 $ 29 $ 4,249 (1) Includes capitalized interest and asset retirement costs as follows: Capitalized interest $ — $ — $ 8 $ 6 $ 7 $ — $ 21 Asset retirement costs 123 8 — — (66 ) — 65 (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 States Canada Egypt (1) North Sea Other International Total (1) (In millions) 2017 Proved properties $ 20,408 $ — $ 10,590 $ 8,199 $ — $ 39,197 Unproved properties 1,312 — 137 297 37 1,783 21,720 — 10,727 8,496 37 40,980 Accumulated DD&A (10,766 ) — (7,985 ) (5,960 ) — (24,711 ) $ 10,954 $ — $ 2,742 $ 2,536 $ 37 $ 16,269 2016 Proved properties $ 19,170 $ 5,434 $ 10,169 $ 7,920 $ — $ 42,693 Unproved properties 1,465 109 76 280 39 1,969 20,635 5,543 10,245 8,200 39 44,662 Accumulated DD&A (10,034 ) (4,120 ) (7,287 ) (5,531 ) — (26,972 ) $ 10,601 $ 1,423 $ 2,958 $ 2,669 $ 39 $ 17,690 (1) Includes a noncontrolling interest in Egypt. Oil and Gas Reserve Information Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and natural gas liquids (NGLs) that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, 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 which 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 Apache’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 (Thousands of barrels) United States Canada Egypt (1) Australia North Sea Total (1) Proved developed reserves: December 31, 2014 444,440 75,876 128,712 29,996 105,746 784,770 December 31, 2015 348,797 67,847 144,164 — 104,255 665,063 December 31, 2016 300,900 51,508 138,771 — 91,138 582,317 December 31, 2017 304,279 — 124,568 — 92,598 521,445 Proved undeveloped reserves: December 31, 2014 170,125 59,923 14,617 25,775 19,059 289,499 December 31, 2015 60,505 38,326 17,856 — 11,309 127,996 December 31, 2016 21,088 7,906 20,187 — 10,784 59,965 December 31, 2017 31,904 — 16,198 — 14,013 62,115 Total proved reserves: Balance December 31, 2014 614,565 135,799 143,329 55,771 124,805 1,074,269 Extensions, discoveries and other additions 13,903 4,550 24,524 — 16,579 59,556 Purchases of minerals in-place — 1,763 — — — 1,763 Revisions of previous estimates (173,907 ) (27,966 ) 27,330 11,189 (2,255 ) (165,609 ) Production (45,138 ) (5,755 ) (33,163 ) (2,778 ) (21,657 ) (108,491 ) Sales of minerals in-place (121 ) (2,218 ) — (64,182 ) (1,908 ) (68,429 ) Balance December 31, 2015 409,302 106,173 162,020 — 115,564 793,059 Extensions, discoveries and other additions 9,614 3,372 17,599 — 9,766 40,351 Purchases of minerals in-place 21 — — — 438 459 Revisions of previous estimates (58,882 ) (43,282 ) 17,301 — (3,851 ) (88,714 ) Production (38,000 ) (4,787 ) (37,962 ) — (19,995 ) (100,744 ) Sales of minerals in-place (67 ) (2,062 ) — — — (2,129 ) Balance December 31, 2016 321,988 59,414 158,958 — 101,922 642,282 Extensions, discoveries and other additions 48,391 14,025 27,140 — 16,023 105,579 Purchases of minerals in-place 46 375 — — — 421 Revisions of previous estimates 825 1,829 (9,839 ) — 6,510 (675 ) Production (33,394 ) (2,425 ) (35,493 ) — (17,844 ) (89,156 ) Sales of minerals in-place (1,673 ) (73,218 ) — — — (74,891 ) Balance December 31, 2017 336,183 — 140,766 — 106,611 583,560 (1) 2017 , 2016 , 2015 , and 2014 includes proved reserves of 47 MMbbls, 53 MMbbls, 54 MMbbls, and 48 MMbbls, respectively, attributable to a noncontrolling interest in Egypt. Natural Gas Liquids (Thousands of barrels) United States Canada Egypt (1) North Sea Total (1) Proved developed reserves: December 31, 2014 183,565 17,947 1,346 1,770 204,628 December 31, 2015 150,265 15,246 1,491 1,784 168,786 December 31, 2016 155,124 13,866 1,266 1,627 171,883 December 31, 2017 171,005 — 685 2,025 173,715 Proved undeveloped reserves: December 31, 2014 69,828 7,168 212 371 77,579 December 31, 2015 24,939 4,839 78 295 30,151 December 31, 2016 17,311 2,473 131 646 20,561 December 31, 2017 29,559 — 39 353 29,951 Total proved reserves: Balance December 31, 2014 253,393 25,115 1,558 2,141 282,207 Extensions, discoveries and other additions 5,768 1,473 144 689 8,074 Purchases of minerals in-place — 976 — — 976 Revisions of previous estimates (64,226 ) (4,886 ) 255 (321 ) (69,178 ) Production (19,684 ) (2,236 ) (388 ) (413 ) (22,721 ) Sales of minerals in-place (47 ) (357 ) — (17 ) (421 ) Balance December 31, 2015 175,204 20,085 1,569 2,079 198,937 Extensions, discoveries and other additions 10,238 755 208 671 11,872 Purchases of minerals in-place 2 — — 5 7 Revisions of previous estimates 6,824 (1,355 ) 17 141 5,627 Production (19,824 ) (2,098 ) (397 ) (623 ) (22,942 ) Sales of minerals in-place (9 ) (1,048 ) — — (1,057 ) Balance December 31, 2016 172,435 16,339 1,397 2,273 192,444 Extensions, discoveries and other additions 33,806 1,794 50 845 36,495 Purchases of minerals in-place 206 199 — — 405 Revisions of previous estimates 12,982 (1,060 ) (425 ) (321 ) 11,176 Production (17,766 ) (1,032 ) (298 ) (419 ) (19,515 ) Sales of minerals in-place (1,099 ) (16,240 ) — — (17,339 ) Balance December 31, 2017 200,564 — 724 2,378 203,666 (1) 2017 , 2016 , 2015 , and 2014 includes proved reserves of 241 Mbbls, 466 Mbbls, 523 Mbbls, and 519 Mbbls, respectively, attributable to a noncontrolling interest in Egypt. Natural Gas (Millions of cubic feet) United States Canada Egypt (1) Australia North Sea Total (1) Proved developed reserves: December 31, 2014 1,616,504 990,145 637,187 640,265 87,259 3,971,360 December 31, 2015 1,364,174 759,321 776,263 — 85,532 2,985,290 December 31, 2016 1,200,379 553,724 675,559 — 86,948 2,516,610 December 31, 2017 1,347,009 — 540,667 — 83,342 1,971,018 Proved undeveloped reserves: December 31, 2014 580,299 527,623 171,696 964,554 23,228 2,267,400 December 31, 2015 208,594 162,809 53,969 — 19,760 445,132 December 31, 2016 231,304 45,312 42,109 — 23,813 342,538 December 31, 2017 297,226 — 47,255 — 11,063 355,544 Total proved reserves: Balance December 31, 2014 2,196,803 1,517,768 808,883 1,604,819 110,487 6,238,760 Extensions, discoveries and other additions 40,901 121,216 94,777 — 41,755 298,649 Purchases of minerals in-place — 24,727 — — — 24,727 Revisions of previous estimates (503,939 ) (325,375 ) 61,442 8,162 (22,373 ) (782,083 ) Production (160,614 ) (100,289 ) (134,870 ) (34,352 ) (23,647 ) (453,772 ) Sales of minerals in-place (383 ) (315,917 ) — (1,578,629 ) (930 ) (1,895,859 ) Balance December 31, 2015 1,572,768 922,130 830,232 — 105,292 3,430,422 Extensions, discoveries and other additions 219,633 30,234 35,202 — 20,814 305,883 Purchases of minerals in-place 7 — — — 6,677 6,684 Revisions of previous estimates (215,378 ) (242,080 ) (4,305 ) — 4,239 (457,524 ) Production (145,019 ) (88,792 ) (143,461 ) — (26,261 ) (403,533 ) Sales of minerals in-place (328 ) (22,456 ) — — — (22,784 ) Balance December 31, 2016 1,431,683 599,036 717,668 — 110,761 2,859,148 Extensions, discoveries and other additions 378,747 49,780 81,245 — 17,646 527,418 Purchases of minerals in-place 4,434 4,319 — — — 8,753 Revisions of previous estimates (5,431 ) 92,207 (70,030 ) — (17,387 ) (641 ) Production (143,943 ) (47,990 ) (140,961 ) — (16,615 ) (349,509 ) Sales of minerals in-place (21,255 ) (697,352 ) — — — (718,607 ) Balance December 31, 2017 1,644,235 — 587,922 — 94,405 2,326,562 (1) 2017 , 2016 , 2015 , and 2014 include proved reserves of 196 Bcf, 239 Bcf, 277 Bcf, and 270 Bcf, respectively, attributable to a noncontrolling interest in Egypt. Total Equivalent Reserves (Thousands barrels of oil equivalent) United States Canada Egypt (1) Australia North Sea Total (1) Proved developed reserves: December 31, 2014 897,422 258,848 236,256 136,707 122,058 1,651,291 December 31, 2015 726,424 209,647 275,033 — 120,293 1,331,397 December 31, 2016 656,087 157,662 252,630 — 107,256 1,173,635 December 31, 2017 699,786 — 215,364 — 108,513 1,023,663 Proved undeveloped reserves: December 31, 2014 336,670 155,028 43,446 186,534 23,301 744,979 December 31, 2015 120,210 70,300 26,929 — 14,897 232,336 December 31, 2016 76,950 17,931 27,336 — 15,399 137,616 December 31, 2017 111,001 — 24,112 — 16,210 151,323 Total proved reserves: Balance December 31, 2014 1,234,092 413,876 279,702 323,241 145,359 2,396,270 Extensions, discoveries and other additions 26,488 26,226 40,464 — 24,227 117,405 Purchases of minerals in-place — 6,860 — — — 6,860 Revisions of previous estimates (322,123 ) (87,081 ) 37,825 12,549 (6,305 ) (365,135 ) Production (91,591 ) (24,706 ) (56,029 ) (8,503 ) (26,011 ) (206,840 ) Sales of minerals in-place (232 ) (55,228 ) — (327,287 ) (2,080 ) (384,827 ) Balance December 31, 2015 846,634 279,947 301,962 — 135,190 1,563,733 Extensions, discoveries and other additions 56,458 9,166 23,674 — 13,906 103,204 Purchases of minerals in-place 24 — — — 1,556 1,580 Revisions of previous estimates (87,954 ) (84,984 ) 16,599 — (3,002 ) (159,341 ) Production (81,994 ) (21,684 ) (62,269 ) — (24,995 ) (190,942 ) Sales of minerals in-place (131 ) (6,852 ) — — — (6,983 ) Balance December 31, 2016 733,037 175,593 279,966 — 122,655 1,311,251 Extensions, discoveries and other additions 145,322 24,115 40,731 — 19,809 229,977 Purchases of minerals in-place 991 1,294 — — — 2,285 Revisions of previous estimates 12,903 16,136 (21,936 ) — 3,291 10,394 Production (75,151 ) (11,455 ) (59,285 ) — (21,032 ) (166,923 ) Sales of minerals in-place (6,315 ) (205,683 ) — — — (211,998 ) Balance December 31, 2017 810,787 — 239,476 — 124,723 1,174,986 (1) 2017 , 2016 , 2015 , and 2014 include total proved reserves of 80 MMboe, 93 MMboe, 101 MMboe, and 93 MMboe, respectively, attributable to a noncontrolling interest in Egypt. During 2017 , Apache sold a combined 212 MMboe primarily through divestiture transactions in Canada. The Company added 2 MMboe of estimated proved reserves through purchases of minerals in-place and 230 MMboe from extensions, discoveries, and other additions. The Company recorded 169 MMboe of exploration and development adds in North America, primarily associated with Woodford, Bone Springs, Yeso, Barnett, and Wolfcamp drilling programs in the Permian Basin ( 128 MMboe), Montney and Duverney drilling in Canada ( 24 MMboe), and Woodford and Austin Chalk drilling activity in the MidContinent region ( 17 MMboe). The international regions contributed 61 MMboe of exploration and development adds during 2017 with Egypt contributing 41 MMboe from onshore exploration and appraisal activity in the Khalda Extension 2, Khalda, Khalda Extension 3, Matruh, and West Kalabsha concessions. The North Sea offshore region contributed 20 MMboe from drilling success in the Beryl and Forties fields. During 2017 , Apache also had combined upward revisions of previously estimated reserves of 10 MMboe. Changes in product prices accounted for 32 MMboe, offset by engineering and performance downward revisions totaling 22 MMboe. Approximately 9 percent of Apache’s year-end 2017 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 15, under “Future Net Cash Flows.” Future Net Cash Flows Future cash inflows as of December 31, 2017 and 2016 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. 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 States Canada Egypt (2) North Sea Total (2) (In millions) 2017 Cash inflows $ 24,271 $ — $ 9,254 $ 6,230 $ 39,755 Production costs (10,618 ) — (1,749 ) (2,459 ) (14,826 ) Development costs (1,659 ) — (1,052 ) (2,795 ) (5,506 ) Income tax expense (42 ) — (2,078 ) (353 ) (2,473 ) Net cash flows 11,952 — 4,375 623 16,950 10 percent discount rate (6,080 ) — (1,034 ) 247 (6,867 ) Discounted future net cash flows (1) $ 5,872 $ — $ 3,341 $ 870 $ 10,083 2016 Cash inflows $ 20,067 $ 3,625 $ 8,778 $ 4,734 $ 37,204 Production costs (8,858 ) (2,582 ) (1,967 ) (2,255 ) (15,662 ) Development costs (1,653 ) (1,565 ) (1,111 ) (2,410 ) (6,739 ) Income tax expense (32 ) — (1,775 ) (8 ) (1,815 ) Net cash flows 9,524 (522 ) 3,925 61 12,988 10 percent discount rate (5,319 ) 549 (956 ) 798 (4,928 ) Discounted future net cash flows (1) $ 4,205 $ 27 $ 2,969 $ 859 $ 8,060 (1) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $12.2 billion and $9.5 billion as of December 31, 2017 and 2016 , respectively. (2) Includes discounted future net cash flows of approximately $1.1 billion and $1.0 billion in 2017 and 2016 , respectively, attributable to a noncontrolling interest in Egypt. The following table sets forth the principal sources of change in the discounted future net cash flows: For the Year Ended December 31, 2017 2016 2015 (In millions) Sales, net of production costs $ (4,158 ) $ (3,479 ) $ (4,056 ) Net change in prices and production costs 3,651 (3,835 ) (21,710 ) Discoveries and improved recovery, net of related costs 2,273 1,153 1,953 Change in future development costs (279 ) 309 705 Previously estimated development costs incurred during the period 719 986 1,991 Revision of quantities (344 ) (574 ) (2,292 ) Purchases of minerals in-place 9 8 22 Accretion of discount 952 1,313 3,642 Change in income taxes (617 ) 1,070 7,264 Sales of minerals in-place (809 ) (52 ) (5,240 ) Change in production rates and other 626 567 (3,343 ) $ 2,023 $ (2,534 ) $ (21,064 )

SUPPLEMENTAL QUARTERLY FINANCIA

SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited)	SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited) The following table summarizes quarterly financial data for 2017 and 2016 : First Second Third Fourth (In millions, except per share amounts) 2017 Oil and gas production revenues $ 1,512 $ 1,346 $ 1,389 $ 1,640 Gain (loss) on divestitures 341 (21 ) 296 11 Net income including noncontrolling interest (1) 267 613 105 518 Net income attributable to common stock 213 572 63 456 Net income per common share (2) : Basic 0.56 1.50 0.16 1.20 Diluted 0.56 1.50 0.16 1.19 2016 Oil and gas production revenues $ 1,087 $ 1,386 $ 1,439 $ 1,455 Gain (loss) on divestitures (1 ) 17 5 — Net loss including noncontrolling interest (1) (371 ) (200 ) (559 ) (143 ) Net loss attributable to common stock (372 ) (244 ) (607 ) (182 ) Basic and diluted net loss per common share (2) (0.98 ) (0.65 ) (1.60 ) (0.48 ) (1) Operating expenses for 2017 include asset and leasehold impairments totaling $23 million , $39 million , $160 million , and $32 million in the first, second, third, and fourth quarters of 2017 , respectively. Continuing operating expenses for 2016 include asset and leasehold impairments totaling $42 million , $238 million , $951 million , and $144 million in the first, second, third, and fourth quarters of 2016 , respectively. (2) The sum of the individual quarterly net income (loss) per common share amounts may not agree with full-year net income (loss) per common share as each quarterly computation is based on the weighted-average number of common shares outstanding during that period.

SUMMARY OF SIGNIFICANT ACCOUN26

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2017
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, Apache 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 Apache subsidiary 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 Apache’s consolidated balance sheet. Investments in which Apache holds less than 50 percent of the voting interest are typically accounted for under the equity method of accounting, with the balance recorded as a component of “Deferred charges and other” in Apache’s consolidated balance sheet and results of operations recorded as a component of “Other” under “Revenues and Other” in the Company’s statement of consolidated operations.
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 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. Apache evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of its financial statements and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the fair value determination of acquired assets and liabilities (see Note 2—Acquisitions and Divestitures), the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (see Note 15—Supplemental Oil and Gas Disclosures), the assessment of asset retirement obligations (see Note 6—Asset Retirement Obligation), the estimates of fair value for long-lived assets and goodwill (see “Fair Value Measurements,” “Property and Equipment,” and “Goodwill” sections in this Note 1 below), and the estimate of income taxes (see Note 8—Income Taxes).
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 7—Debt, and Note 10—Retirement and Deferred Compensation Plans. Apache also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. For the year ended December 31, 2017, the Company recorded asset impairments totaling $8 million in connection with fair value assessments. In 2016, the U.K. government enacted Finance Bill 2016, providing tax relief to exploration and production (E&P) companies operating in the U.K. North Sea. Under the enacted legislation, the U.K. Petroleum Revenue Tax (PRT) rate was reduced to zero from the previously enacted 35 percent rate in effect from January 1, 2016. PRT expense ceased prospectively from that date. During 2017, the Company fully impaired the aggregate remaining value of the recoverable PRT decommissioning asset of $8 million that would have been realized from future abandonment activities. The recoverable value of the PRT decommissioning asset was estimated using the income approach. The expected future cash flows used in the determination were based on anticipated spending and timing of planned future abandonment activities for applicable fields, considering all available information at the date of review. Apache has classified this fair value measurement as Level 3 in the fair value hierarchy. For the year ended December 31, 2016, the Company recorded asset impairments totaling $1.1 billion in connection with fair value assessments in the current low commodity price environment. Impairments totaling $427 million and $135 million were recorded for proved properties and gathering, transmission, and processing (GTP) facilities, respectively, which were written down to their fair values. These impairments are discussed in further detail below in “Property and Equipment.” Also in 2016, the Company recorded $486 million for the impairment of the recoverable value of the PRT decommissioning asset and $55 million for inventory write-downs. For the year ended December 31, 2015, the Company recorded asset impairments totaling $9.5 billion in connection with fair value assessments. Impairments totaling $7.4 billion and $1.7 billion were recorded for proved properties and GTP facilities, respectively, which were written down to their fair values. These impairments are discussed in further detail below in “Property and Equipment.” Also in 2015, the Company recorded $163 million for the impairment of goodwill, $148 million for the impairment of an equity method investment sold in the fourth quarter, and $55 million for inventory write-downs.
Restricted Cash and Cash Equivalents	Restricted Cash and Cash Equivalents In November 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash.” ASU 2016-18 requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. The guidance is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The Company adopted ASU 2016-18 in the third quarter of 2017, and it did not have an impact on the Company’s consolidated financial statements. As of December 31, 2017 , and 2016 , the Company had no restricted cash. 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.
Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for doubtful accounts. The carrying amount of Apache’s accounts receivable approximates fair value because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables. Many of Apache’s receivables are from joint interest owners on properties Apache operates. The Company may have the ability to withhold future revenue disbursements to recover any non-payment of these joint interest billings. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated.
Inventories	Inventories Inventories consist principally of tubular goods and equipment, stated at weighted-average cost, and oil produced but not sold, stated at the lower of cost or market.
Property and Equipment	Property and Equipment The carrying value of Apache’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 those reserves. 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 costs for exploratory and development wells 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 proved oil and gas properties may be impaired, 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 the ASC 820. If applicable, the Company utilizes prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a discount rate believed to be consistent with those applied by market participants. Apache has classified these fair value measurements as Level 3 in the fair value hierarchy. The following table represents non-cash impairments of the carrying value of the Company’s proved and unproved property and equipment for 2017 , 2016 , and 2015 : For the Year Ended December 31, 2017 2016 2015 (In millions) Oil and Gas Property: Proved $ — $ 427 $ 7,389 Unproved 246 272 2,462 Proved properties impaired had aggregate fair values as of the most recent date of impairment of $306 million and $3.9 billion for 2016 and 2015 , respectively. On the statement of consolidated operations, unproved impairments are recorded in exploration expense, and proved impairments are recorded in impairments. Gains and losses on significant divestitures are recognized in the statement of consolidated operations.
Gathering, Transmission, and Processing Facilities	Gathering, Transmission, and Processing Facilities GTP facilities totaled $1.4 billion and $976 million at December 31, 2017 and 2016 , respectively, with accumulated depreciation for these assets totaling $194 million and $130 million for the respective periods. GTP 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 GTP assets, whether Apache-operated or third party, as well as potential development plans by Apache for undeveloped acreage within or in close proximity to those fields. The Company assesses the carrying amount of its GTP facilities whenever events or changes in circumstances indicate that their 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. During 2017, the Company recorded no impairments on GTP assets. During 2016, the Company recorded impairments of $135 million on certain GTP assets in the North Sea, which were written down to their fair values of $142 million . During 2015, the Company recorded impairments of $1.7 billion on certain GTP assets, including $1.1 billion in Egypt, $555 million in Canada, and $103 million in the U.S., which were written down to their fair values of $306 million in aggregate. The fair values of the impaired assets were determined using a combination of the income approach and the market approach. The income approach considers 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 a discount rate 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. The costs of GTP facilities retired 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. During 2017, Apache recorded a gain totaling $6 million associated with the Company’s divestiture of its 30.28 percent interest in the Scottish Area Gas Evacuation system (SAGE) and its 60.56 percent interest in the Beryl pipeline in the North Sea. For more information regarding this transaction, please refer to Note 2—Acquisitions and Divestitures. No gain or loss on the sales of GTP facilities was recognized during 2016. During 2015, Apache recorded a gain on the sale of GTP facilities totaling $59 million associated with the Company’s divestitures of certain Permian Basin assets.
Other Property and Equipment	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.
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 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 or impairment.
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. As of December 31, 2017 , 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 the implied fair value of the goodwill through a charge to expense. In order to determine the fair value of the reporting unit, the Company uses a combination of the income approach and the market approach. The income approach considers management views on current operating measures as well as assumptions pertaining to market forces in the oil and gas industry, such as future production, future commodity prices, and costs. These assumptions are applied to develop future cash flow projections that are then discounted to estimate fair value, using a discount rate similar to those used by the Company in the valuation of acquisitions and divestitures. To assess the reasonableness of its fair value estimate, the Company uses a market approach to compare the fair value to similar businesses whose securities are actively traded in the public market. This requires management to make certain judgments about the selection of comparable companies, recent comparable asset transactions, and transaction premiums. Associated market multiples are applied to various financial metrics of the reporting unit to estimate fair value. Apache has classified this reporting unit estimation as a non-recurring Level 3 fair value measurement. 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 2017 , 2016 , and 2015 : Egypt North Sea Total (In millions) Goodwill at December 31, 2014 $ 87 $ 163 $ 250 Impairments — (163 ) (163 ) Goodwill at December 31, 2015 87 — 87 Impairments — — — Goodwill at December 31, 2016 87 — 87 Impairments — — — Goodwill at December 31, 2017 $ 87 $ — $ 87 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 Apache’s North Sea reporting unit. This goodwill impairment has been recorded in “Impairments” in the Company’s statement of consolidated operations.
Accounts Payable	Accounts Payable Included in accounts payable at December 31, 2017 and 2016 , are liabilities of approximately $76 million and $86 million , respectively, representing the amount by which checks issued but not presented to the Company’s banks for collection exceeded balances in applicable bank accounts.
Commitments and Contingencies	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.
Revenue Recognition and Imbalances	Revenue Recognition and Imbalances Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met. Apache uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Apache is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to Apache will not be sufficient to enable the under-produced owner to recoup its entitled share through production. The Company’s recorded liability is generally reflected in other non-current liabilities. No receivables are recorded for those wells where Apache has taken less than its share of production. Gas imbalances are reflected as adjustments to estimates of proved gas reserves and future cash flows in the unaudited supplemental oil and gas disclosures. Apache markets its own North American natural gas production. Since the Company’s production fluctuates because of operational issues, it is occasionally necessary to purchase third-party oil and gas to fulfill sales obligations and commitments. The costs of third-party oil and gas purchases totaled $254 million , $159 million , and $105 million , for 2017 , 2016 , and 2015 , respectively, which offset the related sales proceeds recorded as “Other” under “Revenues and Other” in the statement of consolidated operations. The Company’s Egyptian operations are conducted pursuant to production sharing contracts under which contractor partners pay all operating and capital costs for exploring and developing the concessions. A percentage of the production, generally up to 40 percent , is available to contractor partners to recover these operating and capital costs over contractually defined periods. Cost recovery is reflected in revenue. The balance of the production is split among the contractor partners and the Egyptian General Petroleum Corporation on a contractually defined basis.
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities Apache periodically enters into derivative contracts to manage its exposure to commodity price risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options. The oil and gas reference prices upon which the commodity derivative contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and gas production. Apache records all derivative instruments, other than those that meet the normal purchases and sales exception, on the balance sheet as either an asset or liability measured at fair value. Changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting are reported in current-period income as “Derivative instrument gains (losses), net” under “Revenues and Other” in the statement of consolidated operations. Hedge accounting treatment allows unrealized gains and losses on cash flow hedges to be deferred in other comprehensive income.
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.
Foreign Currency Transaction Gains and Losses	Foreign Currency Transaction Gains and Losses The U.S. dollar is the functional currency for each of Apache’s international operations. The functional currency is determined country-by-country based on relevant facts and circumstances of the cash flows, commodity pricing environment and financing arrangements in each country. Foreign currency transaction gains and losses arise when monetary assets and liabilities denominated in foreign currencies are remeasured to their U.S. dollar equivalent at the exchange rate in effect at the end of each reporting period. Foreign currency gains and losses also arise when revenue and disbursement transactions denominated in a country’s local currency are converted to a U.S. dollar equivalent based on the average exchange rates during the reporting period. Foreign currency transaction gains and losses related to current taxes payable and deferred tax assets and liabilities are recorded as components of the provision for income taxes.
Insurance Coverage	Insurance Coverage The Company recognizes an insurance receivable when collection of the receivable is deemed probable. Any recognition of an insurance receivable is recorded by crediting and offsetting the original charge. Any differential arising between insurance recoveries and insurance receivables is recorded as a capitalized cost or as an expense, consistent with its original treatment.
Earnings Per Share	Earnings Per Share The Company’s basic earnings per share (EPS) amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was fully vested.
Stock-Based Compensation	Stock-Based Compensation The Company accounts for stock-based compensation under the fair value recognition provisions of ASC Topic 718, “Compensation—Stock Compensation.” The Company grants various types of stock-based awards including stock options, nonvested restricted stock units, and performance-based awards. Stock compensation awards granted are valued on the date of grant and are expensed over the required service period. These plans and related accounting policies are defined and described more fully in Note 11—Capital Stock. In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting.” ASU 2016-09 simplifies several aspects of accounting for share-based payment transactions including income tax consequences, classification of awards as either equity or liabilities, and the classification on the statement of cash flows. The guidance was effective for fiscal years beginning after December 15, 2016. The Company adopted ASU 2016-09 effective January 1, 2017. Upon adoption, the Company elected to account for forfeitures as they occur rather than estimate expected forfeitures using a modified retrospective transition method. As a result of this election, the Company recorded a cumulative-effect adjustment of $11 million , representing an increase in accumulated deficit, with the offset to paid-in capital. During the first quarter of 2017, the Company recorded a $4 million deferred tax asset related to this adjustment, with the offset to accumulated deficit. ASU 2016-09 requires excess tax benefits and deficiencies to be recognized prospectively as part of the provision for income taxes rather than paid-in capital. The adoption did not have a material impact on the Company’s accounting of provision for income taxes. ASU 2016-09 also requires excess tax benefits to be presented as a component of operating cash flows rather than financing cash flows. The Company has adopted this requirement prospectively and accordingly, prior periods have not been adjusted. Excess tax benefits were not material for all periods presented. Additionally, ASU 2016-09 requires that employee taxes paid when an employer withholds shares for tax-withholding purposes be reported as financing activities in the consolidated statements of cash flows, which is how the Company has historically classified these amounts.
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 June 2016, the FASB issued ASU 2016-13, “Financial Instruments—Credit Losses.” The standard changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowance for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. The Company does not expect to adopt the guidance early. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Company is evaluating the new guidance and does not believe this standard will have a material impact on its consolidated financial statements. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous GAAP. The guidance is effective for fiscal years beginning after December 15, 2018, and the Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. Early adoption is permitted; however, the Company does not intend to early adopt. In the normal course of business, the Company enters into various lease agreements for real estate, aircraft, and equipment related to its exploration and development activities that are currently accounted for as operating leases. At this time, the Company cannot reasonably estimate the financial impact this will have on its consolidated financial statements; however, the Company believes adoption and implementation of this ASU will significantly impact its balance sheet, resulting in an increase in both assets and liabilities relating to its leasing activities. As part of the assessment to date, the Company has formed an implementation work team, developed a project plan, educated departments affected by the standard, and continues to evaluate contracts to determine the impact this ASU will have on its consolidated financial statements. In May 2014, the FASB and the International Accounting Standards Board (IASB) issued a joint revenue recognition standard, ASU 2014-09, “Revenue from Contracts with Customers (Topic 606).” The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers, and increases disclosure requirements. The codification was amended through additional ASUs and, as amended, requires companies to recognize revenue to depict the transfer of goods or services to customers in amounts that reflect the consideration to which the company expects to be entitled in exchange for those goods or services. The guidance is effective for annual and interim periods beginning after December 15, 2017. The Company adopted the new standard on January 1, 2018, utilizing the modified retrospective approach. Adoption of this ASU is not expected to have a material impact on net earnings. Certain items netted in revenue prior to adoption are recorded to expense based on the requirements of the new ASU. The Company developed an accounting policy, implemented changes to the relevant business processes and the control activities within them, and continues to evaluate the disclosure requirements as a result of the provisions of this ASU.

SUMMARY OF SIGNIFICANT ACCOUN27

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Schedule of Allowance for Doubtful Accounts	The following table describes changes to the Company’s allowance for doubtful accounts for 2017 , 2016 , and 2015 : 2017 2016 2015 (In millions) Allowance for doubtful accounts at beginning of year $ 93 $ 103 $ 98 Additional provisions for the year 4 14 40 Uncollectible accounts written off net of recoveries (13 ) (24 ) (35 ) Allowance for doubtful accounts at end of year $ 84 $ 93 $ 103
Schedule of Non-cash Impairments of Proved and Unproved Property and Equipment	The following table represents non-cash impairments of the carrying value of the Company’s proved and unproved property and equipment for 2017 , 2016 , and 2015 : For the Year Ended December 31, 2017 2016 2015 (In millions) Oil and Gas Property: Proved $ — $ 427 $ 7,389 Unproved 246 272 2,462
Schedule of Goodwill	The following presents the changes to goodwill for the years ended 2017 , 2016 , and 2015 : Egypt North Sea Total (In millions) Goodwill at December 31, 2014 $ 87 $ 163 $ 250 Impairments — (163 ) (163 ) Goodwill at December 31, 2015 87 — 87 Impairments — — — Goodwill at December 31, 2016 87 — 87 Impairments — — — Goodwill at December 31, 2017 $ 87 $ — $ 87

ACQUISITIONS AND DIVESTITURES (

ACQUISITIONS AND DIVESTITURES (Tables)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Schedule of disposal groups, including discontinued operations	A summary of the Company’s Canadian assets and liabilities at the time of close is detailed below: (In millions) ASSETS Cash $ 46 Other current assets 64 Property, plant & equipment 1,132 Total Assets $ 1,242 LIABILITIES Current liabilities, excluding asset retirement obligation $ 120 Asset retirement obligation 780 Other long-term liabilities 46 Total Liabilities $ 946 The components of the Company’s loss from discontinued operations were as follows: For the Year Ended December 31, 2017 2016 2015 (In millions) Revenues and other from discontinued operations $ — $ — $ 288 Impairment on Woodside sale $ — $ — $ (49 ) Loss on Woodside sale — (23 ) — Loss on Consortium sale — — (139 ) Income from divested Australian operations — — 28 Loss from Argentina divestiture — (10 ) — Income tax benefit — — 652 Income (loss) from discontinued operations, net of tax $ — $ (33 ) $ 492

CAPITALIZED EXPLORATORY WELL 29

CAPITALIZED EXPLORATORY WELL COSTS (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Capitalized Exploratory Well Costs, Roll Forward	The following summarizes the changes in capitalized exploratory well costs for each of the last three years ended December 31, 2017 , 2016 , and 2015 . Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year. 2017 2016 2015 (In millions) Balance at January 1 $ 264 $ 245 $ 849 Additions pending determination of proved reserves 477 249 382 Divestitures and other (3 ) — (557 ) Reclassifications to proved properties (373 ) (211 ) (369 ) Charged to exploration expense (15 ) (19 ) (60 ) Balance at December 31 (1) $ 350 $ 264 $ 245 (1) Includes $2 million of assets related to the Canada divestiture at December 31, 2015.
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: 2017 2016 2015 (In millions) Exploratory well costs capitalized for a period of one year or less $ 160 $ 119 $ 184 Exploratory well costs capitalized for a period greater than one year 190 145 61 Balance at December 31 $ 350 $ 264 $ 245 Number of projects with exploratory well costs capitalized for a period greater than one year 4 3 2
Schedule of Projects with Exploratory Well Costs Capitalized for More than One Year	The following summarizes a further aging by geographic area of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling at December 31, 2017 : 2014 and Total 2016 2015 Prior North Sea $ 160 $ 47 $ 53 $ 60 Other International 30 — 28 2 $ 190 $ 47 $ 81 $ 62

DERIVATIVE INSTRUMENTS AND HE30

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of commodity derivative positions	As of December 31, 2017 , Apache had the following open crude oil derivative positions: Put Options (1)(2) Production Period Settlement Index Mbbls Weighted Average Strike Price January—December 2018 Dated Brent 3,650 $50.00 (1) The remaining unamortized premium paid as of December 31, 2017 , was $9 million . (2) Subsequent to December 31, 2017 , the Company entered into put option contracts settling against NYMEX WTI totaling 5,520 Mbbls with a strike price of $53.00 for the second half of 2018 and Dated Brent totaling 5,520 Mbbls with a strike price of $58.00 for the second half of 2018. Apache paid total premiums of $9 million and $11 million for the NYMEX WTI and Dated Brent put contracts, respectively. Fixed-Price Swaps Collars Call Options (3) Production Period Settlement Index Mbbls Weighted Average Fixed Price Mbbls Weighted Average Floor Price Weighted Average Ceiling Price Mbbls Strike Price January—June 2018 NYMEX WTI 2,715 $51.23 2,715 $45.00 $56.45 — — January—June 2018 Dated Brent 2,172 $54.57 2,172 $50.00 $58.77 — — January—December 2018 NYMEX WTI — — 6,753 $45.00 $57.00 6,753 $60.03 (3) The remaining unamortized premium paid as of December 31, 2017 , was $10 million . As of December 31, 2017 , Apache had the following open natural gas derivative positions: Fixed-Price Swaps Production Period Settlement Index MMBtu (in 000’s) Weighted Average Fixed Price January—March 2018 NYMEX Henry Hub 13,500 $3.39 January—June 2018 NYMEX Henry Hub 22,625 $3.17 April—June 2018 NYMEX Henry Hub 16,835 $2.92 July—December 2018 NYMEX Henry Hub 33,580 $2.96 As of December 31, 2017 , Apache had the following open natural gas financial basis swap contracts: Production Period Settlement Index MMBtu (in 000’s) Weighted Average Price Differential January—March 2018 NYMEX Henry Hub/Waha 9,450 $(0.43) July—December 2018 NYMEX Henry Hub/Waha 33,120 $(0.53) October—December 2018 NYMEX Henry Hub/Waha 1,380 $(0.51) January—March 2019 NYMEX Henry Hub/Waha 1,350 $(0.54) January—June 2019 NYMEX Henry Hub/Waha 32,580 $(0.53) January—December 2019 NYMEX Henry Hub/Waha 14,600 $(0.45)
Schedule of derivative assets measured at fair value	The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis: Fair Value Measurements Using Quoted Price in Active Markets (Level 1) Significant Other Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value Netting (1) Carrying Amount (In millions) December 31, 2017 Assets: Commodity Derivative Instruments $ — $ 67 $ — $ 67 $ (43 ) $ 24 Liabilities: Commodity Derivative Instruments — 107 — 107 (43 ) 64 December 31, 2016 Assets: Commodity Derivative Instruments $ — $ — $ — $ — $ — $ — Liabilities: Commodity Derivative Instruments — — — — — — (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 (Level 3) Total Fair Value Netting (1) Carrying Amount (In millions) December 31, 2017 Assets: Commodity Derivative Instruments $ — $ 67 $ — $ 67 $ (43 ) $ 24 Liabilities: Commodity Derivative Instruments — 107 — 107 (43 ) 64 December 31, 2016 Assets: Commodity Derivative Instruments $ — $ — $ — $ — $ — $ — Liabilities: Commodity Derivative Instruments — — — — — — (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 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: December 31, 2017 December 31, 2016 (In millions) Current Assets: Prepaid assets and other $ 8 $ — Other Assets: Deferred charges and other 16 — Total Assets $ 24 $ — Current Liabilities: Other current liabilities $ 64 $ — Total Liabilities $ 64 $ — 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, 2017 2016 2015 (In millions) Realized gain (loss): Derivative settlements, realized gain $ 24 $ — $ — Amortization of put premium, realized loss (100 ) — — Unrealized loss (59 ) — — Derivative instrument gain (losses), net $ (135 ) $ — $ —

OTHER CURRENT LIABILITIES (Tabl

OTHER CURRENT LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2017
Payables and Accruals [Abstract]
Detail of Other Current Liabilities	The following table provides detail of the Company’s other current liabilities at December 31, 2017 and 2016 : December 31, 2017 2016 (In millions) Accrued operating expenses $ 72 $ 110 Accrued exploration and development 802 463 Accrued compensation and benefits 115 201 Accrued interest 145 145 Accrued income taxes 55 22 Current asset retirement obligation 43 66 Refundable deposits — 174 Other 141 77 Total Other current liabilities $ 1,373 $ 1,258

ASSET RETIREMENT OBLIGATION (Ta

ASSET RETIREMENT OBLIGATION (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Changes to Asset Retirement Obligation	The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2017 and 2016 : 2017 2016 (In millions) Asset retirement obligation at beginning of year $ 2,498 $ 2,598 Liabilities incurred 58 41 Liabilities divested (818 ) (7 ) Liabilities settled (45 ) (57 ) Accretion expense 130 156 Revisions in estimated liabilities 12 (233 ) Asset retirement obligation at end of year 1,835 2,498 Less current portion (43 ) (66 ) Asset retirement obligation, long-term $ 1,792 $ 2,432

DEBT (Tables)

DEBT (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of debt	The following table presents the carrying value of the Company’s debt at December 31, 2017 and 2016 : December 31, 2017 2016 (In millions) Commercial paper $ — $ — 6.9% notes due 2018 (1) 400 400 7.0% notes due 2018 (2) 150 150 7.625% notes due 2019 150 150 3.625% notes due 2021 (1) 493 493 3.25% notes due 2022 (1) 814 857 2.625% notes due 2023 (1) 528 528 7.7% notes due 2026 100 100 7.95% notes due 2026 180 180 7.75% notes due 2029 (3) 300 300 6.0% notes due 2037 (1) 1,000 1,000 5.1% notes due 2040 (1) 1,499 1,499 5.25% notes due 2042 (1) 500 500 4.75% notes due 2043 (1) 1,413 1,413 4.25% notes due 2044 (1) 753 780 7.375% debentures due 2047 150 150 7.625% debentures due 2096 150 150 Debt before unamortized discount and deferred loan costs 8,580 8,650 Unamortized discount (47 ) (50 ) Deferred loan costs (49 ) (56 ) Total debt 8,484 8,544 Current maturities (550 ) — Long-term debt $ 7,934 $ 8,544 (1) These notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The remaining notes and debentures are not redeemable. (2) On February 1, 2018, Apache’s 7.0% notes due 2018 in original principal amount of $150 million matured and were repaid. (3) Assumed in August 2017 as permitted by terms of these notes originally issued by a subsidiary and guaranteed by Apache. Since these notes historically have been included in Apache’s long-term debt, the assumption did not change Apache’s long-term debt or total debt.
Schedule of Long Term Debt by Maturity	Debt maturities as of December 31, 2017 , excluding discounts and deferred loan costs, are as follows: (In millions) 2018 $ 550 2019 150 2020 — 2021 493 2022 814 Thereafter 6,573 Total Debt, excluding discounts and deferred loan costs $ 8,580
Summary of Carrying Amounts and Estimated Fair Values	December 31, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value (In millions) Commercial paper $ — $ — $ — $ — Notes and debentures 8,484 9,244 8,544 9,183 Total Debt $ 8,484 $ 9,244 $ 8,544 $ 9,183
Components of Financing Costs, Net	The following table presents the components of Apache’s financing costs, net: For the Year Ended December 31, 2017 2016 2015 (In millions) Interest expense $ 457 $ 464 $ 486 Amortization of deferred loan costs 9 8 11 Capitalized interest (51 ) (48 ) (15 ) Loss on extinguishment of debt 1 1 39 Interest income (19 ) (8 ) (10 ) Financing costs, net $ 397 $ 417 $ 511

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income (Loss) Before Income Taxes	Income (loss) from continuing operations before income taxes is composed of the following: For the Year Ended December 31, 2017 2016 2015 (In millions) U.S. $ (3,620 ) $ (997 ) $ (9,386 ) Foreign 4,538 (685 ) (2,783 ) Total $ 918 $ (1,682 ) $ (12,169 )
Total Provision for Income Taxes	The total income tax provision (benefit) from continuing operations consists of the following: For the Year Ended December 31, 2017 2016 2015 (In millions) Current income taxes: Federal $ (38 ) $ (14 ) $ 363 State (8 ) (30 ) 41 Foreign 641 435 31 595 391 435 Deferred income taxes: Federal (1,010 ) (257 ) (1,123 ) State — — (51 ) Foreign (170 ) (576 ) (271 ) (1,180 ) (833 ) (1,445 ) Total $ (585 ) $ (442 ) $ (1,010 )
Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense	A reconciliation of the tax on the Company’s income (loss) from continuing operations before income taxes and total tax expense is shown below: For the Year Ended December 31, 2017 2016 2015 (In millions) Income tax expense (benefit) at U.S. statutory rate $ 321 $ (589 ) $ (4,259 ) State income tax, less federal effect (1) (6 ) (19 ) (7 ) Taxes related to foreign operations (105 ) 303 (662 ) Tax credits (33 ) (1 ) (6 ) Tax on distributed foreign earnings — 80 726 Tax on deemed repatriation of foreign earnings 419 — — Foreign tax credits (201 ) (136 ) (2,090 ) Deferred tax on undistributed foreign earnings (1,872 ) (31 ) 1,903 Tax impact of goodwill adjustments — — 82 Change in U.K. tax rate — (238 ) (414 ) Change in U.S. tax rate 516 — — Net change in tax contingencies (1 ) (19 ) 20 Canadian USD functional currency election — 158 — Sale of Canadian assets 279 — — Sale of North Sea GTP assets (48 ) — — Valuation allowances (1) 161 10 3,746 All other, net (15 ) 40 (49 ) $ (585 ) $ (442 ) $ (1,010 ) (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: December 31, 2017 2016 (In millions) Deferred tax assets: Deferred income $ 13 $ 105 U.S. and state net operating losses 1,230 1,095 Capital losses 620 — Foreign net operating losses 6 1,424 Tax credits and other tax incentives 28 62 Foreign tax credits 2,427 2,226 Accrued expenses and liabilities 110 153 Asset retirement obligation 629 875 Property and equipment — 1,189 Other 42 — Total deferred tax assets 5,105 7,129 Valuation allowance (3,816 ) (5,401 ) Net deferred tax assets 1,289 1,728 Deferred tax liabilities: Investment in foreign subsidiaries — 1,872 Equity investments 18 23 Property and equipment 1,798 1,533 Other — 5 Total deferred tax liabilities 1,816 3,433 Net deferred income tax liability $ 527 $ 1,705 Net deferred tax assets and liabilities are included in the consolidated balance sheet as follows: December 31, 2017 2016 (In millions) Assets: Deferred charges and other $ 18 $ 5 Liabilities: Deferred income taxes 545 1,710 Net deferred income tax liability $ 527 $ 1,705
Summary of Valuation Allowance Against Certain Foreign Net Deferred Tax Assets and State Net Operating Losses	In 2017 , 2016 , and 2015 , the Company’s valuation allowance decreased by $1.6 billion , decreased by $33 million , and increased by $3.9 billion , respectively, as detailed in the table below: 2017 2016 2015 (In millions) Balance at beginning of year $ 5,401 $ 5,434 $ 1,564 State (1) 139 (43 ) 151 U.S. 905 139 2,159 Foreign (2) (2,629 ) (129 ) 1,560 Balance at end of year $ 3,816 $ 5,401 $ 5,434 (1) Reported as a component of state income taxes. (2) In 2017, the Company completed the sale of its Canadian assets. As such, except for capital losses incurred on the sale, the deferred tax assets, liabilities, and valuation allowance related to these assets were removed for 2017. In 2015, Apache's subsidiaries completed the sale of its interest in the Kitimat LNG project. As such, the deferred tax assets, liabilities, and valuation allowance related to the project were removed for 2015
Net Operating Losses	On December 31, 2017 , the Company had net operating losses as follows: Amount Expiration (In millions) Net operating losses: U.S. $ 4,037 2018 - 2038 State 5,301 Various
Schedule of Foreign Tax Credit Carryforward	On December 31, 2017 , the Company had foreign tax credits as follows: Amount Expiration (In millions) Foreign tax credits $ 2,427 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: 2017 2016 2015 (In millions) Balance at beginning of year $ 15 $ 19 $ — Additions based on tax positions related to the current year 12 15 19 Reductions for tax positions of prior years (1 ) (19 ) — Balance at end of year $ 26 $ 15 $ 19
Key Jurisdictions of Company's Earliest Open Tax Years	U.S. 2012 Egypt 1998 U.K. 2016

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Contractual Obligations	At December 31, 2017 , contractual obligations for long-term operating leases, capital leases, and purchase obligations are as follows: Net Minimum Commitments Total 2018 2019-2020 2021-2022 2023 & Beyond (In millions) Drilling rigs (1) $ 85 $ 20 $ 65 $ — $ — Purchase obligations (2) 1,275 183 296 214 582 Operating lease obligations (3) 233 54 81 57 41 Capital lease obligations (4) $ 41 $ 1 $ 3 $ 3 $ 34 Total Net Minimum Commitments (5) $ 1,634 $ 258 $ 445 $ 274 $ 657 (1) Payments associated with the drilling of exploratory wells and development wells net of amounts billed to partners will be capitalized as a component of oil and gas properties, and either depreciated, impaired, or written off as exploration expense. (2) Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Includes amounts related to firm transportation capacity on the Gulf Coast Express Pipeline Project (GCX Project), expected to be in service in October 2019. 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. (3) Amounts include long-term lease payments for office space, aircraft, supply and standby vessels, land leases, and equipment related to exploration, development, and production activities. The Company expects to receive $1 million in sublease income associated with these leases. (4) This represents our capital lease obligation related to our 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 $18 million as of December 31, 2017. (5) Excludes purchase commitments for jointly owned fields and facilities for which the Company is not the operator.

RETIREMENT AND DEFERRED COMPE36

RETIREMENT AND DEFERRED COMPENSATION PLANS (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 , 2016 , and 2015 , 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. 2017 2016 2015 Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits (In millions) Change in Projected Benefit Obligation Projected benefit obligation beginning of year $ 202 $ 26 $ 202 $ 26 $ 216 $ 22 Service cost 4 2 4 2 5 2 Interest cost 6 1 7 1 8 1 Foreign currency exchange rate changes 20 — (39 ) — (10 ) — Actuarial losses (gains) (4 ) 1 32 (2 ) (10 ) — Effect of curtailment and settlements — — — — — 2 Benefits paid (12 ) (4 ) (4 ) (3 ) (7 ) (2 ) Retiree contributions — 1 — 2 — 1 Projected benefit obligation at end of year 216 27 202 26 202 26 Change in Plan Assets Fair value of plan assets at beginning of year 206 — 197 — 206 — Actual return on plan assets 17 — 46 — 1 — Foreign currency exchange rates 22 — (39 ) — (10 ) — Employer contributions 5 3 6 1 7 1 Benefits paid (12 ) (4 ) (4 ) (3 ) (7 ) (2 ) Retiree contributions — 1 — 2 — 1 Fair value of plan assets at end of year 238 — 206 — 197 — Funded status at end of year $ 22 $ (27 ) $ 4 $ (26 ) $ (5 ) $ (26 ) Amounts recognized in Consolidated Balance Sheet Current liability $ — $ (2 ) $ — $ (2 ) $ — $ (2 ) Non-current asset (liability) 22 (25 ) 4 (24 ) (5 ) (24 ) $ 22 $ (27 ) $ 4 $ (26 ) $ (5 ) $ (26 ) Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss) Accumulated gain (loss) $ (11 ) $ 8 $ (25 ) $ 9 $ (32 ) $ 9 Weighted Average Assumptions used as of December 31 Discount rate 2.60 % 3.44 % 2.70 % 3.76 % 3.90 % 3.95 % Salary increases 4.70 % N/A 4.80 % N/A 4.60 % N/A Expected return on assets 2.90 % N/A 3.40 % N/A 4.10 % N/A Healthcare cost trend Initial N/A 6.75 % N/A 7.00 % N/A 7.00 % 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 Allocation Percentage of Plan Assets at Year-End 2017 2017 2016 Asset Category Equity securities: U.K. quoted equities — — 14 % Overseas quoted equities 26 % 26 % 26 % Total equity securities 26 % 26 % 40 % Debt securities: U.K. Government bonds 59 % 58 % 47 % U.K. corporate bonds 15 % 14 % 12 % Debt securities 74 % 72 % 59 % Cash — 2 % 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, 2017 and December 31, 2016 : Fair Value Measurements Using: Quoted Price in Active Markets (Level 1) Significant Other Inputs (Level 2) Unobservable Inputs (Level 3) Total Fair Value (In millions) December 31, 2017 Equity securities: Overseas quoted equities (1) $ 61 $ — $ — $ 61 Total equity securities 61 — — 61 Debt securities: U.K. Government bonds (2) 138 — — 138 U.K. corporate bonds (3) 33 — — 33 Total debt securities 171 — — 171 Cash 6 — — 6 Fair value of plan assets $ 238 $ — $ — $ 238 December 31, 2016 Equity securities: U.K. quoted equities (4) $ 28 $ — $ — $ 28 Overseas quoted equities (1) 54 — — 54 Total equity securities 82 — — 82 Debt securities: U.K. Government bonds (2) 97 — — 97 U.K. corporate bonds (3) 25 — — 25 Total debt securities 122 — — 122 Cash 2 — — 2 Fair value of plan assets $ 206 $ — $ — $ 206 (1) This category includes overseas equities, which comprises 20 percent passive global equities benchmarked against the MSCI World (NDR) Index, 25 percent passive global equities (hedged) benchmarked against the MSCI World (NDR) Hedged Index, 20 percent fundamental indexation global equities benchmarked against the FTSE RAFI Developed 1000 index, 25 percent fundamental indexation global equities (hedged) benchmarked against the FTSE RAFI Developed 1000 Hedge Index, and 10 percent emerging markets benchmarked against the MSCI Emerging Markets (NDR) Index, which has a performance target of 2 percent per annum over the benchmark over a rolling three -year period. (2) This category includes U.K. Government bonds, which comprises 47 percent index-linked gilts benchmarked against the FTSE Actuaries Government Securities Index-Linked Over 5 Years Index, 38 percent sterling nominal LDI bonds, and 15 percent sterling inflation linked LDI bonds, both benchmarked against ILIM Custom Benchmark index. (3) This category comprises U.K. corporate bonds benchmarked against the BofAML Sterling Corporate & Collaterlised (excluding Subordinated) Index. (4) This category comprises U.K. passive equities, which are benchmarked against the FTSE 350 Index.
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, 2017 , 2016 , and 2015 : 2017 2016 2015 Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits (In millions) Components of Net Periodic Benefit Cost Service cost $ 4 $ 2 $ 4 $ 2 $ 5 $ 2 Interest cost 6 1 7 1 8 1 Expected return on assets (8 ) — (7 ) — (8 ) — Amortization of actuarial (gain) loss — (1 ) 1 (1 ) 2 — Net periodic benefit cost $ 2 $ 2 $ 5 $ 2 $ 7 $ 3 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31 Discount rate 2.70 % 3.76 % 3.90 % 3.95 % 3.70 % 3.62 % Salary increases 4.80 % N/A 4.60 % N/A 4.60 % N/A Expected return on assets 3.40 % N/A 4.10 % N/A 3.90 % N/A Healthcare cost trend Initial N/A 7.00 % N/A 7.00 % N/A 7.00 % Ultimate in 2025 N/A 5.00 % N/A 5.00 % N/A 5.00 %
Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates	A one-percentage-point change in assumed health care cost trend rates would have the following effects: Postretirement Benefits 1% Increase 1% Decrease (In millions) Effect on service and interest cost components $ 1 $ (1 ) Effect on postretirement benefit obligation 5 (4 )
Expected Future Benefit Payment	The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: Pension Benefits Postretirement Benefits (In millions) 2018 $ 3 $ 2 2019 3 2 2020 4 2 2021 4 2 2022 4 2 Years 2023-2027 21 8

CAPITAL STOCK (Tables)

CAPITAL STOCK (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Common Stock Outstanding	A summary of the shares issued and outstanding for the years ended December 31, 2017 , 2016 , and 2015 is presented in the table below. 2017 2016 2015 Balance, beginning of year 379,439,676 378,034,175 376,504,892 Shares issued for stock-based compensation plans: Treasury shares issued 1,411 11,504 17,525 Common shares issued 1,513,777 1,393,997 1,511,758 Balance, end of year 380,954,864 379,439,676 378,034,175
Net Income Per Common Share	A reconciliation of the components of basic and diluted net income (loss) per common share for the years ended December 31, 2017 , 2016 , and 2015 is presented in the table below. 2017 2016 2015 Income Shares Per Share Loss Shares Per Share Income (Loss) Shares Per Share (In millions, except per share amounts) Basic: Income (loss) from continuing operations $ 1,304 381 $ 3.42 $ (1,372 ) 379 $ (3.62 ) $ (10,844 ) 378 $ (28.70 ) Income (loss) from discontinued operations — 381 — (33 ) 379 (0.09 ) 492 378 1.30 Income (loss) attributable to common stock $ 1,304 381 $ 3.42 $ (1,405 ) 379 $ (3.71 ) $ (10,352 ) 378 $ (27.40 ) Effect of Dilutive Securities: Stock options and other $ — 2 $ (0.01 ) $ — — $ — $ — — $ — Diluted: Income (loss) from continuing operations $ 1,304 383 $ 3.41 $ (1,372 ) 379 $ (3.62 ) $ (10,844 ) 378 $ (28.70 ) Income (loss) from discontinued operations — 383 — (33 ) 379 (0.09 ) 492 378 1.30 Income (loss) attributable to common stock $ 1,304 383 $ 3.41 $ (1,405 ) 379 $ (3.71 ) $ (10,352 ) 378 $ (27.40 )
Description of Stock Based Compensation Plans and Related Costs	A description of the Company’s stock-based compensation plans and related costs follows: 2017 2016 2015 (In millions) Stock-based compensation expensed $ 142 $ 131 $ 100 Stock-based compensation capitalized 41 40 53 Total stock-based compensation costs $ 183 $ 171 $ 153
Summary of Stock Options Activities	A summary of stock options issued and outstanding under the Omnibus Plans is presented in the table and narrative below: 2017 Shares Under Option Weighted Average Exercise Price (In thousands) Outstanding, beginning of year 5,113 $ 84.89 Granted 490 63.25 Exercised (15 ) 41.24 Forfeited or expired (995 ) 82.03 Outstanding, end of year (1) 4,593 83.37 Expected to vest (2) 947 51.83 Exercisable, end of year (3) 3,646 91.56 (1) As of December 31, 2017 , options outstanding had a weighted average remaining contractual life of 4.7 years and aggregate intrinsic value of $0.7 million . (2) As of December 31, 2017 , options expected to vest had a weighted average remaining contractual life of 8.5 years and aggregate intrinsic value of $0.5 million . (3) As of December 31, 2017 , options exercisable had a weighted average remaining contractual life of 3.7 years and aggregate intrinsic value of $0.2 million .
Schedule of Assumptions Used	2017 2016 2015 Expected volatility 34.58 % 32.72 % N/A Expected dividend yields 1.58 % 2.42 % N/A Expected term (in years) 6 6 N/A Risk-free rate 2.02 % 1.44 % N/A Weighted-average grant-date fair value $ 19.38 $ 10.38 N/A
Schedule of Restricted Stock and Restricted Stock Units Activity	Shares Weighted Average Grant- Date Fair Value (1) (In thousands) Non-vested at January 1, 2017 1,225 $ 45.62 Granted 621 66.97 Forfeited (152 ) 52.90 Non-vested at December 31, 2017 1,694 52.39 (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. A summary of restricted stock unit activity for the year ended December 31, 2017 , is presented below. Shares Weighted- Average Grant- Date Fair Value (In thousands) Non-vested at January 1, 2017 6,062 $ 55.11 Granted 1,948 62.74 Vested (2,288 ) 58.77 Forfeited (802 ) 55.54 Non-vested at December 31, 2017 4,920 56.34

ACCUMULATED OTHER COMPREHENSI38

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Components of Accumulated Other Comprehensive Income (Loss)	Components of accumulated other comprehensive income (loss) include the following: For the Year Ended December 31, 2017 2016 2015 (In millions) Currency translation adjustment (1) $ — $ (109 ) $ (109 ) Pension and postretirement benefit plan (Note 10) 4 (3 ) (10 ) Accumulated other comprehensive income (loss) $ 4 $ (112 ) $ (119 ) (1) Currency translation adjustments resulting from translating Apache’s Canadian subsidiaries’ financial statements into U.S. dollar equivalents, prior to adoption of the U.S. dollar as their functional currency, were reported separately and accumulated in other comprehensive loss. This currency translation loss was recognized as a reduction of the net gain on divestiture during the third quarter of 2017 in connection with the Canada divestitures. For more information regarding these divestitures, please refer to Note 2—Acquisitions and Divestitures.

BUSINESS SEGMENT INFORMATION (T

BUSINESS SEGMENT INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Financial Segment Information	Financial information for each area is presented below: United Canada (1) Egypt (2) North Sea Other Total (2) (In millions) 2017 Oil and gas production revenues $ 2,271 $ 231 $ 2,307 $ 1,078 $ — $ 5,887 Operating Expenses: Lease operating expenses 600 103 362 335 — 1,400 Gathering and transportation 71 34 44 30 — 179 Taxes other than income 153 12 — (14 ) — 151 Depreciation, depletion, and amortization 1,000 76 758 446 — 2,280 Exploration 363 11 62 86 27 549 Asset retirement obligation accretion 31 27 — 72 — 130 Impairments — — — 8 — 8 Operating Income (Loss) $ 53 $ (32 ) $ 1,081 $ 115 $ (27 ) 1,190 Other Income (Expense): Gain on divestitures, net 627 Derivative instrument gains (losses), net (135 ) Other 44 General and administrative (395 ) Transaction, reorganization, and separation (16 ) Financing costs, net (397 ) Income Before Income Taxes $ 918 Net Property and Equipment $ 12,070 $ — $ 3,099 $ 2,553 $ 37 $ 17,759 Total Assets $ 14,228 $ — $ 4,658 $ 2,977 $ 59 $ 21,922 Additions to Net Property and Equipment $ 2,397 $ — $ 517 $ 374 $ 14 $ 3,302 United Canada Egypt (2) North Sea Other Total (2) (In millions) 2016 Oil and gas production revenues $ 1,997 $ 343 $ 2,057 $ 970 $ — $ 5,367 Operating Expenses: Lease operating expenses 553 181 446 314 — 1,494 Gathering and transportation 80 68 44 8 — 200 Taxes other than income 139 20 — (33 ) — 126 Depreciation, depletion, and amortization 1,138 183 778 519 — 2,618 Exploration 285 88 48 37 15 473 Asset retirement obligation accretion 34 47 — 75 — 156 Impairments 80 367 1 655 — 1,103 Operating Income (Loss) $ (312 ) $ (611 ) $ 740 $ (605 ) $ (15 ) (803 ) Other Income (Expense): Gain on divestitures, net 21 Other (34 ) General and administrative (410 ) Transaction, reorganization, and separation (39 ) Financing costs, net (417 ) Net Loss From Continuing Operations Before Income Taxes $ (1,682 ) Net Property and Equipment $ 11,168 $ 1,464 $ 3,362 $ 2,834 $ 39 $ 18,867 Total Assets $ 12,403 $ 1,591 $ 4,893 $ 3,584 $ 48 $ 22,519 Additions to Net Property and Equipment $ 926 $ 34 $ 459 $ 260 $ 2 $ 1,681 2015 Oil and gas production revenues $ 2,637 $ 498 $ 2,095 $ 1,280 $ — $ 6,510 Operating Expenses: Lease operating expenses 739 244 522 349 — 1,854 Gathering and transportation 68 89 45 9 — 211 Taxes other than income 184 26 9 63 — 282 Depreciation, depletion, and amortization 1,558 301 927 514 — 3,300 Exploration 2,145 231 154 237 4 2,771 Asset retirement obligation accretion 28 43 — 74 — 145 Impairments 6,266 1,593 1,255 211 147 9,472 Operating Loss $ (8,351 ) $ (2,029 ) $ (817 ) $ (177 ) $ (151 ) (11,525 ) Other Income (Expense): Gain on divestitures, net 281 Other 98 General and administrative (380 ) Transaction, reorganization, and separation (132 ) Financing costs, net (511 ) Net Loss From Continuing Operations Before Income Taxes $ (12,169 ) Net Property and Equipment $ 11,753 $ 2,074 $ 3,712 $ 3,263 $ 36 $ 20,838 Total Assets $ 12,782 $ 2,225 $ 6,165 $ 4,280 $ 48 $ 25,500 Additions to Net Property and Equipment $ 2,099 $ 403 $ 862 $ 715 $ 27 $ 4,106 (1) During the third quarter of 2017, Apache completed the sale of its Canadian operations. For more information regarding this divestiture, please refer to Note 2—Acquisitions and Divestitures. (2) Includes a noncontrolling interest in Egypt.

SUPPLEMENTAL OIL AND GAS DISC40

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities	Apache completed the sale of its Australian LNG business and oil and gas assets, and as such the results of Australia oil and gas assets have been classified as discontinued operations. United States Canada (3) Egypt (4) North Sea Other International Total (4)(5) (In millions, except per boe) 2017 Oil and gas production revenues $ 2,271 $ 231 $ 2,307 $ 1,078 $ — $ 5,887 Operating cost: Depreciation, depletion, and amortization (1) 924 72 707 433 — 2,136 Asset retirement obligation accretion 31 27 — 72 — 130 Lease operating expenses 600 103 362 335 — 1,400 Gathering and transportation 71 34 44 30 — 179 Exploration expenses 363 11 62 86 27 549 Production taxes (2) 153 11 — (14 ) — 150 Income tax 45 (7 ) 509 54 — 601 2,187 251 1,684 996 27 5,145 Results of operation $ 84 $ (20 ) $ 623 $ 82 $ (27 ) $ 742 2016 Oil and gas production revenues $ 1,997 $ 343 $ 2,057 $ 970 $ — $ 5,367 Operating cost: Depreciation, depletion, and amortization (1) 1,055 174 733 498 — 2,460 Asset retirement obligation accretion 34 47 — 75 — 156 Lease operating expenses 553 181 446 314 — 1,494 Gathering and transportation 80 68 44 8 — 200 Exploration expenses 285 88 48 37 15 473 Impairments related to oil and gas properties 61 366 — — — 427 Production taxes (2) 135 18 — (33 ) — 120 Income tax (72 ) (162 ) 354 28 — 148 2,131 780 1,625 927 15 5,478 Results of operation $ (134 ) $ (437 ) $ 432 $ 43 $ (15 ) $ (111 ) 2015 Oil and gas production revenues $ 2,637 $ 498 $ 2,095 $ 1,280 $ — $ 6,510 Operating cost: Depreciation, depletion, and amortization (1) 1,455 251 780 490 — 2,976 Asset retirement obligation accretion 28 43 — 74 — 145 Lease operating expenses 739 244 522 349 — 1,854 Gathering and transportation 68 89 45 9 — 211 Exploration expenses 2,145 231 154 237 4 2,771 Impairments related to oil and gas properties 6,154 1,031 193 11 — 7,389 Production taxes (2) 178 23 — 58 — 259 Income tax (2,886 ) (369 ) 180 26 — (3,049 ) 7,881 1,543 1,874 1,254 4 12,556 Results of operation $ (5,244 ) $ (1,045 ) $ 221 $ 26 $ (4 ) $ (6,046 ) (1) This amount only reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 14—Business Segment Information. (2) Only reflects amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 14—Business Segment Information. (3) During the third quarter of 2017, Apache completed the sale of its Canadian operations. For more information regarding this divestiture, please refer to Note 2—Acquisitions and Divestitures (4) Includes noncontrolling interest in Egypt. (5) Prior year amounts have been recast to exclude discontinued operations.
Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities	Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities United States Canada Egypt (2) Australia North Sea Other International Total (2) (In millions) 2017 Acquisitions: Proved $ 3 $ — $ 4 $ — $ — $ — $ 7 Unproved 136 5 40 — — — 181 Exploration 602 11 122 — 131 25 891 Development 1,118 52 387 — 250 — 1,807 Costs incurred (1) $ 1,859 $ 68 $ 553 $ — $ 381 $ 25 $ 2,886 (1) Includes capitalized interest and asset retirement costs as follows: Capitalized interest $ 23 $ 2 $ — $ — $ 17 $ 2 $ 44 Asset retirement costs 15 — — — 55 — 70 2016 Acquisitions: Proved $ — $ 1 $ 6 $ — $ 38 $ — $ 45 Unproved 110 7 49 — 4 — 170 Exploration 278 23 67 — 84 18 470 Development 420 27 353 — 150 — 950 Costs incurred (1) $ 808 $ 58 $ 475 $ — $ 276 $ 18 $ 1,635 (1) Includes capitalized interest and asset retirement costs as follows: Capitalized interest $ 21 $ 6 $ — $ — $ 21 $ — $ 48 Asset retirement costs (51 ) (13 ) — — (128 ) — (192 ) 2015 Acquisitions: Proved $ 1 $ 8 $ 29 $ — $ — $ — $ 38 Unproved 313 23 — — — — 336 Exploration 194 51 125 32 246 29 677 Development 1,729 151 741 98 479 — 3,198 Costs incurred (1) $ 2,237 $ 233 $ 895 $ 130 $ 725 $ 29 $ 4,249 (1) Includes capitalized interest and asset retirement costs as follows: Capitalized interest $ — $ — $ 8 $ 6 $ 7 $ — $ 21 Asset retirement costs 123 8 — — (66 ) — 65 (2) Includes a noncontrolling interest in Egypt. United States Canada Egypt (1) North Sea Other International Total (1) (In millions) 2017 Proved properties $ 20,408 $ — $ 10,590 $ 8,199 $ — $ 39,197 Unproved properties 1,312 — 137 297 37 1,783 21,720 — 10,727 8,496 37 40,980 Accumulated DD&A (10,766 ) — (7,985 ) (5,960 ) — (24,711 ) $ 10,954 $ — $ 2,742 $ 2,536 $ 37 $ 16,269 2016 Proved properties $ 19,170 $ 5,434 $ 10,169 $ 7,920 $ — $ 42,693 Unproved properties 1,465 109 76 280 39 1,969 20,635 5,543 10,245 8,200 39 44,662 Accumulated DD&A (10,034 ) (4,120 ) (7,287 ) (5,531 ) — (26,972 ) $ 10,601 $ 1,423 $ 2,958 $ 2,669 $ 39 $ 17,690 (1) Includes a noncontrolling interest in Egypt.
Proved Reserve Data	Crude Oil and Condensate (Thousands of barrels) United States Canada Egypt (1) Australia North Sea Total (1) Proved developed reserves: December 31, 2014 444,440 75,876 128,712 29,996 105,746 784,770 December 31, 2015 348,797 67,847 144,164 — 104,255 665,063 December 31, 2016 300,900 51,508 138,771 — 91,138 582,317 December 31, 2017 304,279 — 124,568 — 92,598 521,445 Proved undeveloped reserves: December 31, 2014 170,125 59,923 14,617 25,775 19,059 289,499 December 31, 2015 60,505 38,326 17,856 — 11,309 127,996 December 31, 2016 21,088 7,906 20,187 — 10,784 59,965 December 31, 2017 31,904 — 16,198 — 14,013 62,115 Total proved reserves: Balance December 31, 2014 614,565 135,799 143,329 55,771 124,805 1,074,269 Extensions, discoveries and other additions 13,903 4,550 24,524 — 16,579 59,556 Purchases of minerals in-place — 1,763 — — — 1,763 Revisions of previous estimates (173,907 ) (27,966 ) 27,330 11,189 (2,255 ) (165,609 ) Production (45,138 ) (5,755 ) (33,163 ) (2,778 ) (21,657 ) (108,491 ) Sales of minerals in-place (121 ) (2,218 ) — (64,182 ) (1,908 ) (68,429 ) Balance December 31, 2015 409,302 106,173 162,020 — 115,564 793,059 Extensions, discoveries and other additions 9,614 3,372 17,599 — 9,766 40,351 Purchases of minerals in-place 21 — — — 438 459 Revisions of previous estimates (58,882 ) (43,282 ) 17,301 — (3,851 ) (88,714 ) Production (38,000 ) (4,787 ) (37,962 ) — (19,995 ) (100,744 ) Sales of minerals in-place (67 ) (2,062 ) — — — (2,129 ) Balance December 31, 2016 321,988 59,414 158,958 — 101,922 642,282 Extensions, discoveries and other additions 48,391 14,025 27,140 — 16,023 105,579 Purchases of minerals in-place 46 375 — — — 421 Revisions of previous estimates 825 1,829 (9,839 ) — 6,510 (675 ) Production (33,394 ) (2,425 ) (35,493 ) — (17,844 ) (89,156 ) Sales of minerals in-place (1,673 ) (73,218 ) — — — (74,891 ) Balance December 31, 2017 336,183 — 140,766 — 106,611 583,560 (1) 2017 , 2016 , 2015 , and 2014 includes proved reserves of 47 MMbbls, 53 MMbbls, 54 MMbbls, and 48 MMbbls, respectively, attributable to a noncontrolling interest in Egypt. Natural Gas Liquids (Thousands of barrels) United States Canada Egypt (1) North Sea Total (1) Proved developed reserves: December 31, 2014 183,565 17,947 1,346 1,770 204,628 December 31, 2015 150,265 15,246 1,491 1,784 168,786 December 31, 2016 155,124 13,866 1,266 1,627 171,883 December 31, 2017 171,005 — 685 2,025 173,715 Proved undeveloped reserves: December 31, 2014 69,828 7,168 212 371 77,579 December 31, 2015 24,939 4,839 78 295 30,151 December 31, 2016 17,311 2,473 131 646 20,561 December 31, 2017 29,559 — 39 353 29,951 Total proved reserves: Balance December 31, 2014 253,393 25,115 1,558 2,141 282,207 Extensions, discoveries and other additions 5,768 1,473 144 689 8,074 Purchases of minerals in-place — 976 — — 976 Revisions of previous estimates (64,226 ) (4,886 ) 255 (321 ) (69,178 ) Production (19,684 ) (2,236 ) (388 ) (413 ) (22,721 ) Sales of minerals in-place (47 ) (357 ) — (17 ) (421 ) Balance December 31, 2015 175,204 20,085 1,569 2,079 198,937 Extensions, discoveries and other additions 10,238 755 208 671 11,872 Purchases of minerals in-place 2 — — 5 7 Revisions of previous estimates 6,824 (1,355 ) 17 141 5,627 Production (19,824 ) (2,098 ) (397 ) (623 ) (22,942 ) Sales of minerals in-place (9 ) (1,048 ) — — (1,057 ) Balance December 31, 2016 172,435 16,339 1,397 2,273 192,444 Extensions, discoveries and other additions 33,806 1,794 50 845 36,495 Purchases of minerals in-place 206 199 — — 405 Revisions of previous estimates 12,982 (1,060 ) (425 ) (321 ) 11,176 Production (17,766 ) (1,032 ) (298 ) (419 ) (19,515 ) Sales of minerals in-place (1,099 ) (16,240 ) — — (17,339 ) Balance December 31, 2017 200,564 — 724 2,378 203,666 (1) 2017 , 2016 , 2015 , and 2014 includes proved reserves of 241 Mbbls, 466 Mbbls, 523 Mbbls, and 519 Mbbls, respectively, attributable to a noncontrolling interest in Egypt. Natural Gas (Millions of cubic feet) United States Canada Egypt (1) Australia North Sea Total (1) Proved developed reserves: December 31, 2014 1,616,504 990,145 637,187 640,265 87,259 3,971,360 December 31, 2015 1,364,174 759,321 776,263 — 85,532 2,985,290 December 31, 2016 1,200,379 553,724 675,559 — 86,948 2,516,610 December 31, 2017 1,347,009 — 540,667 — 83,342 1,971,018 Proved undeveloped reserves: December 31, 2014 580,299 527,623 171,696 964,554 23,228 2,267,400 December 31, 2015 208,594 162,809 53,969 — 19,760 445,132 December 31, 2016 231,304 45,312 42,109 — 23,813 342,538 December 31, 2017 297,226 — 47,255 — 11,063 355,544 Total proved reserves: Balance December 31, 2014 2,196,803 1,517,768 808,883 1,604,819 110,487 6,238,760 Extensions, discoveries and other additions 40,901 121,216 94,777 — 41,755 298,649 Purchases of minerals in-place — 24,727 — — — 24,727 Revisions of previous estimates (503,939 ) (325,375 ) 61,442 8,162 (22,373 ) (782,083 ) Production (160,614 ) (100,289 ) (134,870 ) (34,352 ) (23,647 ) (453,772 ) Sales of minerals in-place (383 ) (315,917 ) — (1,578,629 ) (930 ) (1,895,859 ) Balance December 31, 2015 1,572,768 922,130 830,232 — 105,292 3,430,422 Extensions, discoveries and other additions 219,633 30,234 35,202 — 20,814 305,883 Purchases of minerals in-place 7 — — — 6,677 6,684 Revisions of previous estimates (215,378 ) (242,080 ) (4,305 ) — 4,239 (457,524 ) Production (145,019 ) (88,792 ) (143,461 ) — (26,261 ) (403,533 ) Sales of minerals in-place (328 ) (22,456 ) — — — (22,784 ) Balance December 31, 2016 1,431,683 599,036 717,668 — 110,761 2,859,148 Extensions, discoveries and other additions 378,747 49,780 81,245 — 17,646 527,418 Purchases of minerals in-place 4,434 4,319 — — — 8,753 Revisions of previous estimates (5,431 ) 92,207 (70,030 ) — (17,387 ) (641 ) Production (143,943 ) (47,990 ) (140,961 ) — (16,615 ) (349,509 ) Sales of minerals in-place (21,255 ) (697,352 ) — — — (718,607 ) Balance December 31, 2017 1,644,235 — 587,922 — 94,405 2,326,562 (1) 2017 , 2016 , 2015 , and 2014 include proved reserves of 196 Bcf, 239 Bcf, 277 Bcf, and 270 Bcf, respectively, attributable to a noncontrolling interest in Egypt. Total Equivalent Reserves (Thousands barrels of oil equivalent) United States Canada Egypt (1) Australia North Sea Total (1) Proved developed reserves: December 31, 2014 897,422 258,848 236,256 136,707 122,058 1,651,291 December 31, 2015 726,424 209,647 275,033 — 120,293 1,331,397 December 31, 2016 656,087 157,662 252,630 — 107,256 1,173,635 December 31, 2017 699,786 — 215,364 — 108,513 1,023,663 Proved undeveloped reserves: December 31, 2014 336,670 155,028 43,446 186,534 23,301 744,979 December 31, 2015 120,210 70,300 26,929 — 14,897 232,336 December 31, 2016 76,950 17,931 27,336 — 15,399 137,616 December 31, 2017 111,001 — 24,112 — 16,210 151,323 Total proved reserves: Balance December 31, 2014 1,234,092 413,876 279,702 323,241 145,359 2,396,270 Extensions, discoveries and other additions 26,488 26,226 40,464 — 24,227 117,405 Purchases of minerals in-place — 6,860 — — — 6,860 Revisions of previous estimates (322,123 ) (87,081 ) 37,825 12,549 (6,305 ) (365,135 ) Production (91,591 ) (24,706 ) (56,029 ) (8,503 ) (26,011 ) (206,840 ) Sales of minerals in-place (232 ) (55,228 ) — (327,287 ) (2,080 ) (384,827 ) Balance December 31, 2015 846,634 279,947 301,962 — 135,190 1,563,733 Extensions, discoveries and other additions 56,458 9,166 23,674 — 13,906 103,204 Purchases of minerals in-place 24 — — — 1,556 1,580 Revisions of previous estimates (87,954 ) (84,984 ) 16,599 — (3,002 ) (159,341 ) Production (81,994 ) (21,684 ) (62,269 ) — (24,995 ) (190,942 ) Sales of minerals in-place (131 ) (6,852 ) — — — (6,983 ) Balance December 31, 2016 733,037 175,593 279,966 — 122,655 1,311,251 Extensions, discoveries and other additions 145,322 24,115 40,731 — 19,809 229,977 Purchases of minerals in-place 991 1,294 — — — 2,285 Revisions of previous estimates 12,903 16,136 (21,936 ) — 3,291 10,394 Production (75,151 ) (11,455 ) (59,285 ) — (21,032 ) (166,923 ) Sales of minerals in-place (6,315 ) (205,683 ) — — — (211,998 ) Balance December 31, 2017 810,787 — 239,476 — 124,723 1,174,986 (1) 2017 , 2016 , 2015 , and 2014 include total proved reserves of 80 MMboe, 93 MMboe, 101 MMboe, and 93 MMboe, 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	United States Canada Egypt (2) North Sea Total (2) (In millions) 2017 Cash inflows $ 24,271 $ — $ 9,254 $ 6,230 $ 39,755 Production costs (10,618 ) — (1,749 ) (2,459 ) (14,826 ) Development costs (1,659 ) — (1,052 ) (2,795 ) (5,506 ) Income tax expense (42 ) — (2,078 ) (353 ) (2,473 ) Net cash flows 11,952 — 4,375 623 16,950 10 percent discount rate (6,080 ) — (1,034 ) 247 (6,867 ) Discounted future net cash flows (1) $ 5,872 $ — $ 3,341 $ 870 $ 10,083 2016 Cash inflows $ 20,067 $ 3,625 $ 8,778 $ 4,734 $ 37,204 Production costs (8,858 ) (2,582 ) (1,967 ) (2,255 ) (15,662 ) Development costs (1,653 ) (1,565 ) (1,111 ) (2,410 ) (6,739 ) Income tax expense (32 ) — (1,775 ) (8 ) (1,815 ) Net cash flows 9,524 (522 ) 3,925 61 12,988 10 percent discount rate (5,319 ) 549 (956 ) 798 (4,928 ) Discounted future net cash flows (1) $ 4,205 $ 27 $ 2,969 $ 859 $ 8,060 (1) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $12.2 billion and $9.5 billion as of December 31, 2017 and 2016 , respectively. (2) Includes discounted future net cash flows of approximately $1.1 billion and $1.0 billion in 2017 and 2016 , respectively, attributable to a noncontrolling interest in Egypt.
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, 2017 2016 2015 (In millions) Sales, net of production costs $ (4,158 ) $ (3,479 ) $ (4,056 ) Net change in prices and production costs 3,651 (3,835 ) (21,710 ) Discoveries and improved recovery, net of related costs 2,273 1,153 1,953 Change in future development costs (279 ) 309 705 Previously estimated development costs incurred during the period 719 986 1,991 Revision of quantities (344 ) (574 ) (2,292 ) Purchases of minerals in-place 9 8 22 Accretion of discount 952 1,313 3,642 Change in income taxes (617 ) 1,070 7,264 Sales of minerals in-place (809 ) (52 ) (5,240 ) Change in production rates and other 626 567 (3,343 ) $ 2,023 $ (2,534 ) $ (21,064 )

SUPPLEMENTAL QUARTERLY FINANC41

SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Supplemental Quarterly Financial Data	The following table summarizes quarterly financial data for 2017 and 2016 : First Second Third Fourth (In millions, except per share amounts) 2017 Oil and gas production revenues $ 1,512 $ 1,346 $ 1,389 $ 1,640 Gain (loss) on divestitures 341 (21 ) 296 11 Net income including noncontrolling interest (1) 267 613 105 518 Net income attributable to common stock 213 572 63 456 Net income per common share (2) : Basic 0.56 1.50 0.16 1.20 Diluted 0.56 1.50 0.16 1.19 2016 Oil and gas production revenues $ 1,087 $ 1,386 $ 1,439 $ 1,455 Gain (loss) on divestitures (1 ) 17 5 — Net loss including noncontrolling interest (1) (371 ) (200 ) (559 ) (143 ) Net loss attributable to common stock (372 ) (244 ) (607 ) (182 ) Basic and diluted net loss per common share (2) (0.98 ) (0.65 ) (1.60 ) (0.48 ) (1) Operating expenses for 2017 include asset and leasehold impairments totaling $23 million , $39 million , $160 million , and $32 million in the first, second, third, and fourth quarters of 2017 , respectively. Continuing operating expenses for 2016 include asset and leasehold impairments totaling $42 million , $238 million , $951 million , and $144 million in the first, second, third, and fourth quarters of 2016 , respectively. (2) The sum of the individual quarterly net income (loss) per common share amounts may not agree with full-year net income (loss) per common share as each quarterly computation is based on the weighted-average number of common shares outstanding during that period.

Nature of Operations (Details)

Nature of Operations (Details)	12 Months Ended
	Dec. 31, 2017Area
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of geographical areas	3

SUMMARY OF SIGNIFICANT ACCOUN43

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Allowance for Doubtful Accounts Roll-forward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Allowance for doubtful accounts at beginning of year	$ 93	$ 103	$ 98
Additional provisions for the year	4	14	40
Uncollectible accounts written off net of recoveries	(13)	(24)	(35)
Allowance for doubtful accounts at end of year	$ 84	$ 93	$ 103

SUMMARY OF SIGNIFICANT ACCOUN44

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Non-Cash Impairments of Proved and Unproved Property and Equipment (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil and Gas Properties, Proved
Schedule Of Significant Accounting Policies [Line Items]
Impairment of Oil and Gas properties	$ 0	$ 427	$ 7,389
Oil And Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Impairment of Oil and Gas properties	$ 246	$ 272	$ 2,462

SUMMARY OF SIGNIFICANT ACCOUN45

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Schedule of Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Goodwill [Roll Forward]
Goodwill, Beginning Balance	$ 87	$ 87	$ 250
Impairments	0	0	(163)
Goodwill, Ending Balance	87	87	87
Egypt
Goodwill [Roll Forward]
Goodwill, Beginning Balance	87	87	87
Impairments	0	0	0
Goodwill, Ending Balance	87	87	87
North Sea
Goodwill [Roll Forward]
Goodwill, Beginning Balance	0	0	163
Impairments	0	0	(163)
Goodwill, Ending Balance	$ 0	$ 0	$ 0

SUMMARY OF SIGNIFICANT ACCOUN46

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Detail) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments	$ 32,000,000	$ 160,000,000	$ 39,000,000	$ 23,000,000	$ 144,000,000	$ 951,000,000	$ 238,000,000	$ 42,000,000	$ 8,000,000	$ 1,103,000,000	$ 9,472,000,000
UK Petroleum Revenue Tax (PRT) rate										0.00%	35.00%
Total asset impairment charges										$ 1,100,000,000	$ 9,500,000,000
Impairment charge of Petroleum Revenue Tax benefits, before tax										486,000,000
Inventory write-downs										55,000,000	55,000,000
Goodwill impairment charges									0	0	163,000,000
Impairment of equity method investment											148,000,000
Restricted cash	0				0				0	0
Cash and cash equivalents	1,668,000,000				1,377,000,000				1,668,000,000	1,377,000,000	1,467,000,000	$ 679,000,000
Allowance for doubtful accounts	84,000,000				93,000,000				84,000,000	93,000,000	103,000,000	$ 98,000,000
Oil and gas property, fair value					306,000,000					306,000,000	3,900,000,000
Gathering, transmission and processing facilities	1,376,000,000				976,000,000				1,376,000,000	976,000,000
Accumulated depreciation	25,643,000,000				27,882,000,000				25,643,000,000	27,882,000,000
Impairment of GTP assets									0	135,000,000	1,700,000,000
Fair value of GTP assets					142,000,000					142,000,000	306,000,000
Gain (loss) on sale of oil and gas properties										21,000,000	135,000,000
Accounts payable									76,000,000	86,000,000
Net cost of third party gas									$ 254,000,000	159,000,000	105,000,000
Maximum percentage of production available to contract partners									40.00%
Other foreign currency gains (losses)									$ (11,000,000)	(25,000,000)	(11,000,000)
Egypt
Schedule Of Significant Accounting Policies [Line Items]
Goodwill impairment charges									0	0	0
Impairment of GTP assets											1,100,000,000
Canada
Schedule Of Significant Accounting Policies [Line Items]
Impairment of GTP assets											555,000,000
United States
Schedule Of Significant Accounting Policies [Line Items]
Impairment of GTP assets											103,000,000
North Sea
Schedule Of Significant Accounting Policies [Line Items]
Goodwill impairment charges									0	0	163,000,000
Gain (loss) on sale of oil and gas properties									6,000,000
Accounting Standards Update 2016-09, Excess Tax Benefit Component
Schedule Of Significant Accounting Policies [Line Items]
Deferred tax asset				$ 4,000,000
Retained Earnings (Accumulated Deficit) | Accounting Standards Update 2016-09
Schedule Of Significant Accounting Policies [Line Items]
Cumulative effect of new accounting principle adopted					$ (11,000,000)					$ (11,000,000)
Scottish Area Gas Evacuation System | North Sea
Schedule Of Significant Accounting Policies [Line Items]
Equity ownership percentage					30.28%					30.28%
Beryl Pipeline | North Sea
Schedule Of Significant Accounting Policies [Line Items]
Equity ownership percentage					60.56%					60.56%
Oil and Gas Properties, Proved
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment									0	$ 427,000,000	7,389,000,000
GTC facilities
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment										135,000,000	1,700,000,000
Gathering, transmission and processing facilities	1,400,000,000				$ 976,000,000				1,400,000,000	976,000,000
Accumulated depreciation	194,000,000				130,000,000				194,000,000	130,000,000
Gain (loss) on sale of oil and gas properties										0	$ 59,000,000
Other Property and Equipment
Schedule Of Significant Accounting Policies [Line Items]
Accumulated depreciation	$ 739,000,000				$ 780,000,000				$ 739,000,000	$ 780,000,000
Maximum
Schedule Of Significant Accounting Policies [Line Items]
Voting interest required for consolidation of investments	50.00%								50.00%
Maximum | Other Property and Equipment
Schedule Of Significant Accounting Policies [Line Items]
Useful lives of gas gathering, transmission and processing facilities									20 years
Minimum
Schedule Of Significant Accounting Policies [Line Items]
Voting interest required for consolidation of investments	50.00%								50.00%
Minimum | Other Property and Equipment
Schedule Of Significant Accounting Policies [Line Items]
Useful lives of gas gathering, transmission and processing facilities									3 years

ACQUISITIONS AND DIVESTITURES -

ACQUISITIONS AND DIVESTITURES - 2017 Activity (Detail) - USD ($) $ in Millions	Jun. 30, 2017	Aug. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Currency translation losses recorded in Accumulated Other Comprehensive Loss					$ 0	$ 109	$ 109
Refundable deposits					0	174
Proceeds from sale of oil and gas properties					758	134	268
Gain (loss) on sale of oil and gas properties						21	135
Leasehold and property acquisitions amount					178	181	367
Transaction, reorganization, and separation					16	39	132
Permian And Midcontinent/Gulf Coast Regions
Business Acquisition [Line Items]
Proceeds from sale of certain non-core assets					798
Refundable deposits for sale of non-core assets						$ 40
Gain on sale of non-core assets					599
North Sea
Business Acquisition [Line Items]
Gain (loss) on sale of oil and gas properties					6
North Sea | Scottish Area Gas Evacuation System
Business Acquisition [Line Items]
Equity ownership percentage						30.28%
Refundable deposits						$ 134
North Sea | Beryl Pipeline
Business Acquisition [Line Items]
Equity ownership percentage						60.56%
North America Onshore Regions
Business Acquisition [Line Items]
Leasehold and property acquisitions amount					188	$ 181	367
Disposed of by sale | Apache Canada Ltd. (ACL)
Business Acquisition [Line Items]
Proceeds from divestiture	$ 228	$ 478
Gain (loss) recognized on sale			$ 74	$ (52)
Currency translation losses recorded in Accumulated Other Comprehensive Loss						109
Pretax losses from discontinued operations					$ 141	$ 684	$ 2,000

ACQUISITIONS AND DIVESTITURES48

ACQUISITIONS AND DIVESTITURES - Summary of Assets and Liabilities of August Canada Divestitures (Details) - Disposed of by sale - Apache Canada Ltd. (ACL) $ in Millions	Aug. 31, 2017USD ($)
ASSETS
Cash	$ 46
Other current assets	64
Property, plant & equipment	1,132
Total Assets	1,242
LIABILITIES
Current liabilities, excluding asset retirement obligation	120
Asset retirement obligation	780
Other long-term liabilities	46
Total Liabilities	$ 946

ACQUISITIONS AND DIVESTITURES49

ACQUISITIONS AND DIVESTITURES - 2016 Activity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Leasehold and property acquisitions amount	$ 178	$ 181	$ 367
Proceeds from sale of oil and gas properties	758	134	268
Gain (loss) on sale of oil and gas properties		21	135
North America Onshore Regions
Business Acquisition [Line Items]
Leasehold and property acquisitions amount	$ 188	$ 181	$ 367

ACQUISITIONS AND DIVESTITURES50

ACQUISITIONS AND DIVESTITURES - 2015 Activity (Detail) - USD ($) $ in Millions	1 Months Ended			3 Months Ended										9 Months Ended	12 Months Ended
	Oct. 31, 2015	Jun. 30, 2015	Apr. 30, 2015	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceed from sale of equity method investments															$ 0	$ 0	$ 391
Proceeds form sale of operations															0	0	854
Proceeds from sale of oil and gas properties															758	134	268
Asset impairments				$ 32	$ 160	$ 39	$ 23	$ 144	$ 951	$ 238	$ 42				8	1,103	9,472
Leasehold and property acquisitions amount															178	181	367
Gain (loss) on sale of oil and gas properties																21	135
Transaction, reorganization, and separation															16	39	132
Canada
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds form sale of operations			$ 854
Australia | Woodside Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas properties			$ 2,800
Australia | Consortium Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on sale of upstream assets		$ (139)
Proceeds from sale of oil and gas properties		$ 1,900
North America Onshore Regions
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Leasehold and property acquisitions amount															188	$ 181	367
Yara Pilbara Holdings Pty Limited
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity ownership percentage	49.00%
Proceed from sale of equity method investments	$ 391
Impairment on equity method investment														$ 148
Kitimat LNG | Canada
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity ownership percentage			50.00%
Proceeds form sale of operations			$ 344
Upstream Assets | Canada
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds form sale of operations			510
Gain (loss) on sale of upstream assets																	$ 146
Upstream Assets | Australia | Woodside Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas properties			1,400
LNG Assets | Australia | Woodside Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas properties			$ 1,400
Wheatstone LNG | Australia
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on sale of upstream assets									$ (23)
Asset impairments												$ 49	$ 833
Consulting fees
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Transaction, reorganization, and separation															11
Employee separation, consolidation of office space, and other reorganization efforts
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Transaction, reorganization, and separation															$ 5

ACQUISITIONS AND DIVESTITURES51

ACQUISITIONS AND DIVESTITURES - Components of Company's Loss From Discontinued Operation (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset impairments	$ (32)	$ (160)	$ (39)	$ (23)	$ (144)	$ (951)	$ (238)	$ (42)	$ (8)	$ (1,103)	$ (9,472)
Income (loss) from discontinued operations, net of tax									0	(33)	492
Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues and other from discontinued operations									0	0	288
Income (loss) from divested operations									0	0	28
Income tax benefit									0	0	652
Income (loss) from discontinued operations, net of tax									0	(33)	492
Apache Australia Operation | Discontinued Operations | Woodside Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset impairments									0	0	(49)
Gain (loss) on disposal									0	(23)	0
Apache Australia Operation | Discontinued Operations | Consortium Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal									0	0	(139)
Apache Argentina Operation | Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (loss) from divested operations									$ 0	$ (10)	$ 0

CAPITALIZED EXPLORATORY WELL 52

CAPITALIZED EXPLORATORY WELL COSTS - Capitalized Exploratory Well Costs Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Capitalized exploratory well costs, Beginning Balance	$ 264	$ 245	$ 849
Additions pending determination of proved reserves	477	249	382
Divestitures and other	(3)	0	(557)
Reclassifications to proved properties	(373)	(211)	(369)
Charged to exploration expense	(15)	(19)	(60)
Capitalized exploratory well costs, Ending Balance	$ 350	264	245
Canada
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Capitalized exploratory well costs, Beginning Balance		$ 2
Capitalized exploratory well costs, Ending Balance			$ 2

CAPITALIZED EXPLORATORY WELL 53

CAPITALIZED EXPLORATORY WELL COSTS - Aging of Suspended Well Balances (Details) $ in Millions	Dec. 31, 2017USD ($)Project	Dec. 31, 2016USD ($)Project	Dec. 31, 2015USD ($)Project	Dec. 31, 2014USD ($)
Extractive Industries [Abstract]
Exploratory well costs capitalized for a period of one year or less	$ 160	$ 119	$ 184
Exploratory well costs capitalized for a period greater than one year	190	145	61
Capitalized exploratory well costs	$ 350	$ 264	$ 245	$ 849
Number of projects with exploratory well costs capitalized for a period greater than one year | Project	4,000,000	3,000,000	2,000,000

CAPITALIZED EXPLORATORY WELL 54

CAPITALIZED EXPLORATORY WELL COSTS - Aging by Geographic Area of Exploratory Well Costs Capitalized Greater than One Year (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 190	$ 145	$ 61
2,016
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	47
2,015
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	81
2014 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	62
North Sea
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	160
North Sea | 2016
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	47
North Sea | 2015
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	53
North Sea | 2014 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	60
Other International
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	30
Other International | 2016
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
Other International | 2015
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
Other International | 2014 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	$ 2

DERIVATIVE INSTRUMENTS AND HE55

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Instruments (Detail) bbl in Thousands, MMBTU in Thousands, $ in Millions	Jan. 01, 2018$ / bblbbl	Dec. 31, 2017USD ($)MMBTUCounterparty$ / MMBTU$ / bblbbl
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of derivative counterparties | Counterparty		14
Put Options | NYMEX WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative remaining unamortized premium paid | $		$ 9
Put Options | Dated Brent
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative remaining unamortized premium paid | $		11
Put Options | Crude Oil
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative remaining unamortized premium paid | $		$ 9
Put Options | July - December 2018 | Crude Oil | NYMEX WTI | Subsequent Event
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume (bbl) | bbl	5,520
Derivative, weighted average strike price (USD per bbl) | $ / bbl	53
Put Options | July - December 2018 | Crude Oil | Dated Brent | Subsequent Event
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume (bbl) | bbl	5,520
Derivative, weighted average strike price (USD per bbl) | $ / bbl	58
Put Options | January—December 2018 | Crude Oil | Dated Brent
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume (bbl) | bbl		3,650
Derivative, weighted average strike price (USD per bbl) | $ / bbl		50
Fixed-Price Swaps | January—June 2018 | Crude Oil | NYMEX WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume (bbl) | bbl		2,715
Derivative, weighted average fixed price (USD per MMBtu)		51.23
Fixed-Price Swaps | January—June 2018 | Crude Oil | Dated Brent
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume (bbl) | bbl		2,172
Derivative, weighted average fixed price (USD per MMBtu)		54.57
Fixed-Price Swaps | January—June 2018 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, weighted average fixed price (USD per MMBtu)		3.17
Derivative, nonmonetary notional amount, energy measure | MMBTU		22,625
Fixed-Price Swaps | January - March 2018 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, weighted average fixed price (USD per MMBtu)		3.39
Derivative, nonmonetary notional amount, energy measure | MMBTU		13,500
Fixed-Price Swaps | April—June 2018 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, weighted average fixed price (USD per MMBtu)		2.92
Derivative, nonmonetary notional amount, energy measure | MMBTU		16,835
Fixed-Price Swaps | July - December 2018 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, weighted average fixed price (USD per MMBtu)		2.96
Derivative, nonmonetary notional amount, energy measure | MMBTU		33,580
Collars | January—June 2018 | Crude Oil | NYMEX WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume (bbl) | bbl		2,715
Derivative, weighted average floor price (USD per bbl)		45
Derivative, weighted average ceiling price (USD per bbl)		56.45
Collars | January—June 2018 | Crude Oil | Dated Brent
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume (bbl) | bbl		2,172
Derivative, weighted average floor price (USD per bbl)		50
Derivative, weighted average ceiling price (USD per bbl)		58.77
Collars | January—December 2018 | Crude Oil | NYMEX WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume (bbl) | bbl		6,753
Derivative, weighted average floor price (USD per bbl)		45
Derivative, weighted average ceiling price (USD per bbl)		57
Call Options | Crude Oil
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative remaining unamortized premium paid | $		$ 10
Call Options | January—December 2018 | Crude Oil | NYMEX WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume (bbl) | bbl		6,753
Derivative, weighted average strike price (USD per bbl) | $ / bbl		60.03
Finanical Basis Swaps | January - March 2018 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU		9,450
Weighted Average Price Differential		(0.43)
Finanical Basis Swaps | October - December 2018 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU		1,380
Weighted Average Price Differential		(0.51)
Finanical Basis Swaps | July - December 2018 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU		33,120
Weighted Average Price Differential		(0.53)
Finanical Basis Swaps | January—March 2019 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU		1,350
Weighted Average Price Differential		(0.54)
Finanical Basis Swaps | January—June 2019 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU		32,580
Weighted Average Price Differential		(0.53)
Finanical Basis Swaps | January - December 2019 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU		14,600
Weighted Average Price Differential		(0.45)

DERIVATIVE INSTRUMENTS AND HE56

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities Measured at Fair Value (Details) - Commodity Derivative Instruments - Recurring - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative asset, fair value	$ 67	$ 0
Derivative asset, netting	(43)	0
Derivative asset	24	0
Derivative liability, fair value	107	0
Derivative liability, netting	(43)	0
Derivative liability	64	0
Quoted Price in Active Markets (Level 1)
Derivative [Line Items]
Derivative asset, fair value	0	0
Derivative liability, fair value	0	0
Significant Other Inputs (Level 2)
Derivative [Line Items]
Derivative asset, fair value	67	0
Derivative liability, fair value	107	0
Significant Unobservable Inputs (Level 3)
Derivative [Line Items]
Derivative asset, fair value	0	0
Derivative liability, fair value	$ 0	$ 0

DERIVATIVE INSTRUMENTS AND HE57

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities and Locations on Consolidated Balance Sheet (Details) - Recurring - Commodity Derivative Instruments - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative asset	$ 24	$ 0
Derivative liability	64	0
Current Assets: Prepaid assets and other
Derivatives, Fair Value [Line Items]
Derivative asset	8	0
Other Assets: Deferred charges and other
Derivatives, Fair Value [Line Items]
Derivative asset	16	0
Current Liabilities: Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability	$ 64	$ 0

DERIVATIVE INSTRUMENTS AND HE58

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Activities Recorded in the Statement of Consolidated Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Realized gain (loss):
Unrealized loss	$ (59)	$ 0	$ 0
Not Designated as Hedging Instrument
Realized gain (loss):
Derivative settlements, realized gain	24	0	0
Amortization of put premium, realized loss	(100)	0	0
Unrealized loss	(59)	0	0
Derivative instrument gain (losses), net	$ (135)	$ 0	$ 0

OTHER CURRENT LIABILITIES (Deta

OTHER CURRENT LIABILITIES (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Payables and Accruals [Abstract]
Accrued operating expenses	$ 72	$ 110
Accrued exploration and development	802	463
Accrued compensation and benefits	115	201
Accrued interest	145	145
Accrued income taxes	55	22
Current asset retirement obligation	43	66
Refundable deposits	0	174
Other	141	77
Total Other current liabilities	$ 1,373	$ 1,258

ASSET RETIREMENT OBLIGATION - S

ASSET RETIREMENT OBLIGATION - Schedule of changes to Asset Retirement Obligation (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of year	$ 2,498	$ 2,598
Liabilities incurred	58	41
Liabilities divested	(818)	(7)
Liabilities settled	(45)	(57)
Accretion expense	130	156
Revisions in estimated liabilities	12	(233)
Asset retirement obligation at end of year	1,835	2,498
Less current portion	(43)	(66)
Asset retirement obligation, long-term	$ 1,792	$ 2,432

ASSET RETIREMENT OBLIGATION - A

ASSET RETIREMENT OBLIGATION - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Additional abandonment liabilities associated with its drilling and development program	$ 58	$ 41
Revisions in estimated liabilities	$ 12	$ (233)

DEBT - Additional Information (

DEBT - Additional Information (Detail)	1 Months Ended		3 Months Ended	12 Months Ended
	Jan. 31, 2017USD ($)	Jun. 30, 2015USD ($)Contract	Dec. 31, 2016USD ($)	Dec. 31, 2017USD ($)Contract	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2017GBP (£)	Aug. 31, 2017USD ($)	Nov. 30, 2016USD ($)	Feb. 29, 2016GBP (£)
Debt Instrument [Line Items]
Loss on extinguishment of debt	$ 1,000,000			$ 1,000,000	$ 1,000,000	$ 39,000,000
Debt before unamortized discount and deferred loan costs				8,580,000,000
Repayments of debt principal after year five				6,573,000,000
Line of credit outstanding				0
Commercial paper program				3,500,000,000
Discount of debt amortization				3,000,000	3,000,000	$ 3,000,000
Senior Notes
Debt Instrument [Line Items]
Debt repurchased principle amount	69,000,000		$ 181,000,000		181,000,000
Early repayment of senior notes	71,000,000		182,000,000
Debt premium	$ 1,000,000								$ 500,000
Loss on extinguishment of debt			1,000,000
Unsecured Debt
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs			8,650,000,000	8,580,000,000	8,650,000,000
Deferred loan costs			56,000,000	49,000,000	56,000,000
Unamortized discount			50,000,000	47,000,000	50,000,000
Maximum | Senior Notes
Debt Instrument [Line Items]
Debt repurchased principle amount									$ 250,000,000
Revolving Credit Facility
Debt Instrument [Line Items]
Maximum potential lien on assets located in specified regions				$ 1,100,000,000
Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Percentage of liens of companies consolidated asset				5.00%			5.00%
Commercial Paper
Debt Instrument [Line Items]
Period for borrowing funds				270 days
Short-term debt outstanding			0	$ 0	0
7.75% notes due in 2029 | Senior Notes
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs								$ 300,000,000
Debt interest rate								7.75%
7.75% notes due in 2029 | Unsecured Debt
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs			$ 300,000,000	$ 300,000,000	$ 300,000,000
Debt interest rate				7.75%			7.75%
2015 Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility term		5 years
Line of credit facility, number of extension options | Contract		2
Credit facility, extension period for maturity		1 year
Line of credit facility maximum borrowing capacity		$ 3,500,000,000
Line of credit facility, available borrowing capacity				$ 3,500,000,000
Quarterly facility fees at per annum rate				0.175%
2015 Credit Facility | Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Line of credit facility, commitment amount		4,500,000,000
Debt-to-capital ratio				0.60			0.60
2015 Credit Facility | Revolving Credit Facility | Base Rate
Debt Instrument [Line Items]
Margin percentage				0.075%
2015 Credit Facility | Revolving Credit Facility | LIBOR
Debt Instrument [Line Items]
Margin percentage				1.075%
2015 Credit Facility | Letter of Credit
Debt Instrument [Line Items]
Letter of credit subfacility		$ 750,000,000
2016 Credit Facility | Letter of Credit
Debt Instrument [Line Items]
Line of credit facility maximum borrowing capacity | £										£ 1,075,000,000
Quarterly facility fees at per annum rate				0.175%
Letter of credit facility | £										£ 900,000,000
Number of debt instrument | Contract				3
Letters of credit outstanding, amount | £							£ 129,100,000
2016 Credit Facility | Letter of Credit | Base Rate
Debt Instrument [Line Items]
Margin percentage				0.075%
2016 Credit Facility | Letter of Credit | LIBOR
Debt Instrument [Line Items]
Margin percentage				1.075%

DEBT - Schedule of Debt (Detail

DEBT - Schedule of Debt (Detail) - USD ($)	Feb. 01, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 8,580,000,000
Total debt		8,484,000,000	$ 8,544,000,000
Long-term debt		7,934,000,000	8,544,000,000
Commercial Paper
Debt Instrument [Line Items]
Total debt		0	0
Unsecured Debt
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		8,580,000,000	8,650,000,000
Unamortized discount		(47,000,000)	(50,000,000)
Deferred loan costs		(49,000,000)	(56,000,000)
Total debt		8,484,000,000	8,544,000,000
Current maturities		(550,000,000)	0
Long-term debt		7,934,000,000	8,544,000,000
Unsecured Debt | 6.9% notes due 2018
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 400,000,000	400,000,000
Debt interest rate		6.90%
Unsecured Debt | 7.0% notes due 2018
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 150,000,000	150,000,000
Debt interest rate		7.00%
Unsecured Debt | 7.625% notes due 2019
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 150,000,000	150,000,000
Debt interest rate		7.625%
Unsecured Debt | 3.625% notes due 2021
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 493,000,000	493,000,000
Debt interest rate		3.625%
Unsecured Debt | 3.25% notes due 2022
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 814,000,000	857,000,000
Debt interest rate		3.25%
Unsecured Debt | 2.625% notes due 2023
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 528,000,000	528,000,000
Debt interest rate		2.625%
Unsecured Debt | 7.7% notes due 2026
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 100,000,000	100,000,000
Debt interest rate		7.70%
Unsecured Debt | 7.95% notes due 2026
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 180,000,000	180,000,000
Debt interest rate		7.95%
Unsecured Debt | 7.75% notes due in 2029
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 300,000,000	300,000,000
Debt interest rate		7.75%
Unsecured Debt | 6.0% notes due 2037
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 1,000,000,000	1,000,000,000
Debt interest rate		6.00%
Unsecured Debt | 5.1% notes due 2040
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 1,499,000,000	1,499,000,000
Debt interest rate		5.10%
Unsecured Debt | 5.25% notes due 2042
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 500,000,000	500,000,000
Debt interest rate		5.25%
Unsecured Debt | 4.75% notes due 2043
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 1,413,000,000	1,413,000,000
Debt interest rate		4.75%
Unsecured Debt | 4.25% notes due 2044
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 753,000,000	780,000,000
Debt interest rate		4.25%
Unsecured Debt | 7.375% debentures due 2047
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 150,000,000	150,000,000
Debt interest rate		7.375%
Unsecured Debt | 7.625% debentures due 2096
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 150,000,000	150,000,000
Debt interest rate		7.625%
Unsecured Debt | Commercial Paper
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs		$ 0	$ 0
Subsequent Event | Unsecured Debt | 7.0% notes due 2018
Debt Instrument [Line Items]
Debt before unamortized discount and deferred loan costs	$ 150,000,000
Debt interest rate	7.00%

DEBT - Schedule of Long Term De

DEBT - Schedule of Long Term Debt by Maturity (Detail) $ in Millions	Dec. 31, 2017USD ($)
Debt Disclosure [Abstract]
2,018	$ 550
2,019	150
2,020	0
2,021	493
2,022	814
Thereafter	6,573
Total Debt, excluding discounts and deferred loan costs	$ 8,580

DEBT - Summary of Carrying Amou

DEBT - Summary of Carrying Amounts and Estimated Fair Values (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Carrying Amount	$ 8,484	$ 8,544
Fair Value	9,244	9,183
Commercial Paper
Debt Instrument [Line Items]
Carrying Amount	0	0
Fair Value	0	0
Notes and debentures
Debt Instrument [Line Items]
Carrying Amount	8,484	8,544
Fair Value	$ 9,244	$ 9,183

DEBT - Components of Financing

DEBT - Components of Financing Costs, Net (Detail) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Interest expense		$ 457	$ 464	$ 486
Amortization of deferred loan costs		9	8	11
Capitalized interest		(51)	(48)	(15)
Loss on extinguishment of debt	$ 1	1	1	39
Interest income		(19)	(8)	(10)
Financing costs, net		$ 397	$ 417	$ 511

INCOME TAXES - Income (Loss) Be

INCOME TAXES - Income (Loss) Before Income Taxes (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
U.S.	$ (3,620)	$ (997)	$ (9,386)
Foreign	4,538	(685)	(2,783)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	$ 918	$ (1,682)	$ (12,169)

INCOME TAXES - Total Provision

INCOME TAXES - Total Provision for Income Taxes (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current income taxes:
Federal	$ (38)	$ (14)	$ 363
State	(8)	(30)	41
Foreign	641	435	31
Total current income taxes	595	391	435
Deferred income taxes:
Federal	(1,010)	(257)	(1,123)
State	0	0	(51)
Foreign	(170)	(576)	(271)
Total deferred income taxes	(1,180)	(833)	(1,445)
Total	$ (585)	$ (442)	$ (1,010)

INCOME TAXES - Reconciliation o

INCOME TAXES - Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income tax expense (benefit) at U.S. statutory rate	$ 321	$ (589)	$ (4,259)
State income tax, less federal effect	(6)	(19)	(7)
Taxes related to foreign operations	(105)	303	(662)
Tax credits	(33)	(1)	(6)
Tax on distributed foreign earnings	0	80	726
Tax on deemed repatriation of foreign earnings	419	0	0
Foreign tax credits	(201)	(136)	(2,090)
Deferred tax on undistributed foreign earnings	(1,872)	(31)	1,903
Tax impact of goodwill adjustments	0	0	82
Change in U.K. tax rate	0	(238)	(414)
Change in U.S. tax rate	516	0	0
Net change in tax contingencies	(1)	(19)	20
Canadian USD functional currency election	0	158	0
Sale of Canadian assets	279	0	0
Sale of North Sea GTP assets	(48)	0	0
Valuation allowances	161	10	3,746
All other, net	(15)	40	(49)
Total	$ (585)	$ (442)	$ (1,010)

INCOME TAXES - Net Deferred Tax

INCOME TAXES - Net Deferred Tax Liability (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Deferred tax assets:
Deferred income	$ 13	$ 105
U.S. and state net operating losses	1,230	1,095
Capital losses	620	0
Foreign net operating losses	6	1,424
Tax credits and other tax incentives	28	62
Foreign tax credits	2,427	2,226
Accrued expenses and liabilities	110	153
Asset retirement obligation	629	875
Property and equipment	0	1,189
Other	42	0
Total deferred tax assets	5,105	7,129
Valuation allowance	(3,816)	(5,401)	$ (5,434)	$ (1,564)
Net deferred tax assets	1,289	1,728
Deferred tax liabilities:
Investment in foreign subsidiaries	0	1,872
Equity investments	18	23
Property and equipment	1,798	1,533
Other	0	5
Total deferred tax liabilities	1,816	3,433
Net deferred income tax liability	$ 527	$ 1,705

INCOME TAXES - Net Deferred T71

INCOME TAXES - Net Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Assets:
Deferred charges and other	$ 18	$ 5
Liabilities:
Deferred income taxes	545	1,710
Net deferred income tax liability	$ 527	$ 1,705

INCOME TAXES - Additional Infor

INCOME TAXES - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax [Line Items]
Net deferred tax benefit to reverse previously recorded deferred tax liability for unrepatriated earnings and to account for transition rule under the new law	$ 822,000,000
Provisional deferred tax expense reltaed to remeasurement of deferred tax asset	516,000,000
Deferred tax benefit	170,000,000	$ 576,000,000	$ 271,000,000
Current income tax liability		560,000,000
Increase (decrease) of valuation allowances	(1,600,000,000)	(33,000,000)	3,900,000,000
Capital losses	620,000,000	0
Foreign tax credit carryforward, amount	2,427,000,000	2,226,000,000
Tax expense (benefit) recorded for interest and penalties	0	0	1,000,000
Accrued for payment of interest and penalties	0	0	1,000,000
Reserve for uncertain tax positions related to the current year	11,000,000	$ (4,000,000)	$ 19,000,000
U.S.
Income Tax [Line Items]
Operating loss carryforwards	4,037,000,000
Operating loss carryforwards subject to annual limitation	197,000,000
Capital losses	$ 1,800,000,000
Capital loss carryforward carryover period	5 years
Canada
Income Tax [Line Items]
Capital losses	$ 836,000,000
Her Majesty's Revenue and Customs (HMRC)
Income Tax [Line Items]
Supplementary charge, percent	10.00%	20.00%	32.00%
Deferred tax benefit	$ 238,000,000	$ 414,000,000

INCOME TAXES - Summary of Valua

INCOME TAXES - Summary of Valuation Allowance Against Certain Foreign Net Deferred Tax Assets and State Net Operating Losses (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Balance at beginning of year	$ 5,401	$ 5,434	$ 1,564
State	139	(43)	151
U.S.	905	139	2,159
Foreign	(2,629)	(129)	1,560
Balance at end of year	$ 3,816	$ 5,401	$ 5,434

INCOME TAXES - Net Operating Lo

INCOME TAXES - Net Operating Losses (Detail) $ in Millions	Dec. 31, 2017USD ($)
U.S.
Schedule Of Income Tax [Line Items]
Net operating losses	$ 4,037
State
Schedule Of Income Tax [Line Items]
Net operating losses	$ 5,301

INCOME TAXES - Schedule of Fore

INCOME TAXES - Schedule of Foreign Tax Credit Carryforward (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Foreign tax credits	$ 2,427	$ 2,226

INCOME TAXES - Reconciliation76

INCOME TAXES - Reconciliation of Beginning and Ending Amount of Unrecognized Tax Benefits (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of year	$ 26	$ 15	$ 19	$ 0
Additions based on tax positions related to the current year	12	15	19
Reductions for tax positions of prior years	(1)	(19)	0
Balance at end of year	$ 26	$ 15	$ 19	$ 0

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Additional Information (Detail) AUD in Millions	Mar. 21, 2016USD ($)	Mar. 20, 2016USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Apr. 30, 2017AUD	Mar. 12, 2014USD ($)
Commitment And Contingencies [Line Items]
Accrued liability for legal contingencies			$ 37,000,000
Environmental tax and royalty obligations							$ 100,000,000
Retain right of obligations			67,500,000
Maximum cost considered to be recognized for additional reserve			300,000
Undiscounted reserve for environmental remediation			4,000,000
Net rental expenses			82,000,000	$ 59,000,000	$ 57,000,000
Contractual obligation cost incurred			134,000,000	$ 86,000,000	$ 92,000,000
Apollo Exploration Lawsuit
Commitment And Contingencies [Line Items]
Loss contingency damages sought value	$ 200,000,000
Minimum | Apollo Exploration Lawsuit
Commitment And Contingencies [Line Items]
Loss contingency damages sought value		$ 1,100,000,000
Apache Australia Operation | Australian Operations Divestiture Dispute
Commitment And Contingencies [Line Items]
Gain contingency, unrecorded amount | AUD						AUD 80
Loss contingency estimate of possible loss			$ 200,000,000

COMMITMENTS AND CONTINGENCIES78

COMMITMENTS AND CONTINGENCIES - Contractual Obligations (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	$ 1,634
2,018	258
2019-2020	445
2021-2022	274
2023 & Beyond	657
Sublease income	$ 1
Capital leases imputed interest rate	4.40%
Capital leases future minimum payments due	$ 18
Drilling rigs
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	85
2,018	20
2019-2020	65
2021-2022	0
2023 & Beyond	0
Purchase obligations
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	1,275
2,018	183
2019-2020	296
2021-2022	214
2023 & Beyond	582
Operating lease obligations
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	233
2,018	54
2019-2020	81
2021-2022	57
2023 & Beyond	41
Capital lease obligations
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	41
2,018	1
2019-2020	3
2021-2022	3
2023 & Beyond	$ 34

RETIREMENT AND DEFERRED COMPE79

RETIREMENT AND DEFERRED COMPENSATION PLANS - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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	$ 55	$ 52	$ 59
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	$ 193	$ 181	$ 169
Expected contribution towards pension and postretirement plan	6
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected contribution towards pension and postretirement plan	$ 2

RETIREMENT AND DEFERRED COMPE80

RETIREMENT AND DEFERRED COMPENSATION PLANS - Changes in Benefit Obligation, Fair Value of Plan Assets and Funded Status of Pension and Postretirement Benefit Plans (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Change in Plan Assets
Fair value of plan assets at beginning of year	$ 206
Fair value of plan assets at end of year	238	$ 206
Pension Benefits
Change in Projected Benefit Obligation
Projected benefit obligation beginning of year	202	202	$ 216
Service cost	4	4	5
Interest cost	6	7	8
Foreign currency exchange rate changes	20	(39)	(10)
Actuarial losses (gains)	(4)	32	(10)
Effect of curtailment and settlements	0	0	0
Benefits paid	(12)	(4)	(7)
Retiree contributions	0	0	0
Projected benefit obligation at end of year	216	202	202
Change in Plan Assets
Fair value of plan assets at beginning of year	206	197	206
Actual return on plan assets	17	46	1
Foreign currency exchange rates	22	(39)	(10)
Employer contributions	5	6	7
Benefits paid	(12)	(4)	(7)
Retiree contributions	0	0	0
Fair value of plan assets at end of year	238	206	197
Funded status at end of year	22	4	(5)
Amounts recognized in Consolidated Balance Sheet
Current liability	0	0	0
Non-current asset (liability)	22	4	(5)
Total defined benefit plans liabilities	22	4	(5)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$ (11)	$ (25)	$ (32)
Weighted Average Assumptions used as of December 31
Discount rate	2.60%	2.70%	3.90%
Salary increases	4.70%	4.80%	4.60%
Expected return on assets	2.90%	3.40%	4.10%
Postretirement Benefits
Change in Projected Benefit Obligation
Projected benefit obligation beginning of year	$ 26	$ 26	$ 22
Service cost	2	2	2
Interest cost	1	1	1
Foreign currency exchange rate changes	0	0	0
Actuarial losses (gains)	1	(2)	0
Effect of curtailment and settlements	0	0	2
Benefits paid	(4)	(3)	(2)
Retiree contributions	1	2	1
Projected benefit obligation at end of year	27	26	26
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	3	1	1
Benefits paid	(4)	(3)	(2)
Retiree contributions	1	2	1
Fair value of plan assets at end of year	0	0	0
Funded status at end of year	(27)	(26)	(26)
Amounts recognized in Consolidated Balance Sheet
Current liability	(2)	(2)	(2)
Non-current asset (liability)	(25)	(24)	(24)
Total defined benefit plans liabilities	(27)	(26)	(26)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$ 8	$ 9	$ 9
Weighted Average Assumptions used as of December 31
Discount rate	3.44%	3.76%	3.95%
Healthcare cost trend
Initial	6.75%	7.00%	7.00%
Ultimate in 2025	5.00%	5.00%	5.00%

RETIREMENT AND DEFERRED COMPE81

RETIREMENT AND DEFERRED COMPENSATION PLANS - Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset (Detail)	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	100.00%
Percentage of Plan Assets at Year-End	100.00%	100.00%
Cash
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	0.00%
Percentage of Plan Assets at Year-End	2.00%	1.00%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	26.00%
Percentage of Plan Assets at Year-End	26.00%	40.00%
Equity securities | U.K. quoted equities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	0.00%
Percentage of Plan Assets at Year-End	0.00%	14.00%
Equity securities | Overseas quoted equities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	26.00%
Percentage of Plan Assets at Year-End	26.00%	26.00%
Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	74.00%
Percentage of Plan Assets at Year-End	72.00%	59.00%
Debt securities | U.K. Government bonds
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	59.00%
Percentage of Plan Assets at Year-End	58.00%	47.00%
Debt securities | U.K. corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	15.00%
Percentage of Plan Assets at Year-End	14.00%	12.00%

RETIREMENT AND DEFERRED COMPE82

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 (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 238	$ 206
Portion of overseas equities	100.00%	100.00%
U.K. Government Bonds
Defined Benefit Plan Disclosure [Line Items]
Period for the portion of UK Equities, overseas equities, government bonds and corporate bonds, benchmarked against FTSE	5 years
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 61	$ 82
Portion of overseas equities	26.00%	40.00%
Debt securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 171	$ 122
Portion of overseas equities	72.00%	59.00%
Quoted Price in Active Markets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 238	$ 206
Quoted Price in Active Markets (Level 1) | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	61	82
Quoted Price in Active Markets (Level 1) | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	171	122
Significant Other Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Other Inputs (Level 2) | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Significant Other Inputs (Level 2) | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Unobservable Inputs (Level 3) | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Unobservable Inputs (Level 3) | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 0	0
U.K. quoted equities | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		$ 28
Portion of overseas equities	0.00%	14.00%
U.K. quoted equities | Quoted Price in Active Markets (Level 1) | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		$ 28
U.K. quoted equities | Significant Other Inputs (Level 2) | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
U.K. quoted equities | Unobservable Inputs (Level 3) | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Overseas quoted equities
Defined Benefit Plan Disclosure [Line Items]
Performance target over the benchmark	2.00%
Period for the portion of UK Equities, overseas equities, government bonds and corporate bonds, benchmarked against FTSE	3 years
Overseas quoted equities | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 61	$ 54
Portion of overseas equities	26.00%	26.00%
Overseas quoted equities | Quoted Price in Active Markets (Level 1) | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 61	$ 54
Overseas quoted equities | Significant Other Inputs (Level 2) | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Overseas quoted equities | Unobservable Inputs (Level 3) | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
U.K. Government bonds | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 138	$ 97
Portion of overseas equities	58.00%	47.00%
U.K. Government bonds | Quoted Price in Active Markets (Level 1) | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 138	$ 97
U.K. Government bonds | Significant Other Inputs (Level 2) | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
U.K. Government bonds | Unobservable Inputs (Level 3) | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
U.K. corporate bonds | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 33	$ 25
Portion of overseas equities	14.00%	12.00%
U.K. corporate bonds | Quoted Price in Active Markets (Level 1) | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 33	$ 25
U.K. corporate bonds | Significant Other Inputs (Level 2) | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
U.K. corporate bonds | Unobservable Inputs (Level 3) | Debt securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 6	$ 2
Portion of overseas equities	2.00%	1.00%
Cash | Quoted Price in Active Markets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 6	$ 2
Cash | Significant Other Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash | Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 0	$ 0
MSCI World Index | Passive Global Equities
Defined Benefit Plan Disclosure [Line Items]
Portion of overseas equities	20.00%
MSCI World Index | Passive Global Equities Hedged
Defined Benefit Plan Disclosure [Line Items]
Portion of overseas equities	25.00%
MSCI World Index | Emerging Markets
Defined Benefit Plan Disclosure [Line Items]
Portion of overseas equities	10.00%
FTSE RAFI Developed 1000 Index | Fundamental Indexation Global Equities
Defined Benefit Plan Disclosure [Line Items]
Portion of overseas equities	20.00%
FTSE RAFI Developed 1000 Index | Fundamental Indexation Global Equities Hedged
Defined Benefit Plan Disclosure [Line Items]
Portion of overseas equities	25.00%
Index - Linked Index | U.K. Government Bonds
Defined Benefit Plan Disclosure [Line Items]
Portion of debt securities government bonds and corporate bonds benchmarked against FTSE	47.00%
Sterling Nominal LDI Bonds | Nominal LDI Bonds
Defined Benefit Plan Disclosure [Line Items]
Benchmarked against ILIM Custom Benchmark index	38.00%
Sterling Inflation Linked LDI Bonds | Inflation Linked LDI Bonds
Defined Benefit Plan Disclosure [Line Items]
Benchmarked against ILIM Custom Benchmark index	15.00%

RETIREMENT AND DEFERRED COMPE83

RETIREMENT AND DEFERRED COMPENSATION PLANS - Components of Net Periodic Cost and Underlying Weighted Average Actuarial Assumptions Used for Pension and Postretirement Benefit Plans (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 4	$ 4	$ 5
Interest cost	6	7	8
Expected return on assets	(8)	(7)	(8)
Amortization of actuarial (gain) loss	0	1	2
Net periodic benefit cost	$ 2	$ 5	$ 7
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	2.70%	3.90%	3.70%
Salary increases	4.80%	4.60%	4.60%
Expected return on assets	3.40%	4.10%	3.90%
Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 2	$ 2	$ 2
Interest cost	1	1	1
Expected return on assets	0
Amortization of actuarial (gain) loss	(1)	(1)	0
Net periodic benefit cost	$ 2	$ 2	$ 3
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	3.76%	3.95%	3.62%
Healthcare cost trend
Initial	7.00%	7.00%	7.00%
Ultimate in 2025	5.00%	5.00%	5.00%

RETIREMENT AND DEFERRED COMPE84

RETIREMENT AND DEFERRED COMPENSATION PLANS - Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates (Detail) - Postretirement Benefits $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Defined Benefit Plan Disclosure [Line Items]
Effect on service and interest cost components, 1% Increase	$ 1
Effect on postretirement benefit obligation, 1% Increase	5
Effect on service and interest cost components, 1% Decrease	(1)
Effect on postretirement benefit obligation, 1% Decrease	$ (4)

RETIREMENT AND DEFERRED COMPE85

RETIREMENT AND DEFERRED COMPENSATION PLANS - Expected Future Benefit Payment (Detail) $ in Millions	Dec. 31, 2017USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2,018	$ 3
2,019	3
2,020	4
2,021	4
2,022	4
Years 2023-2027	21
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2,018	2
2,019	2
2,020	2
2,021	2
2,022	2
Years 2023-2027	$ 8

CAPITAL STOCK - Common Stock Ou

CAPITAL STOCK - Common Stock Outstanding (Detail) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Movement In Common Stock Outstanding [Roll Forward]
Balance, beginning of year (in shares)	379,439,676	378,034,175	376,504,892
Shares issued for stock-based compensation plans:
Treasury shares issued	1,411	11,504	17,525
Common shares issued	1,513,777	1,393,997	1,511,758
Balance, end of year (in shares)	380,954,864	379,439,676	378,034,175

CAPITAL STOCK - Net Income Per

CAPITAL STOCK - Net Income Per Common Share (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Basic:
Income (loss) from continuing operations									$ 1,304	$ (1,372)	$ (10,844)
Income (loss) from discontinued operations									0	(33)	492
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$ 456	$ 63	$ 572	$ 213	$ (182)	$ (607)	$ (244)	$ (372)	$ 1,304	$ (1,405)	$ (10,352)
Weighted average number of shares outstanding, continuing operations, basic (in shares)									381	379	378
Weighted average number of shares outstanding, discontinued operations, basic (in shares)									381	379	378
Weighted average number of shares outstanding, basic (in shares)									381	379	378
Basic net income (loss) from continuing operations per share (in USD per share)									$ 3.42	$ (3.62)	$ (28.70)
Basic net income (loss) from discontinued operations per share (in USD per share)									0	(0.09)	1.30
Basic net income (loss) per share (in USD per share)	$ 1.20	$ 0.16	$ 1.50	$ 0.56					$ 3.42	$ (3.71)	$ (27.40)
Effect of Dilutive Securities:
Stock options and other, shares									2
Stock options and other, per share (in USD per share)									$ (0.01)
Diluted:
Income (loss) from continuing operations									$ 1,304	$ (1,372)	$ (10,844)
Income (loss) from discontinued operations									0	(33)	492
Income (loss) attributable to common stock									$ 1,304	$ (1,405)	$ (10,352)
Weighted average number of shares outstanding, continuing operations, diluted (in shares)									383	379	378
Weighted average number of shares outstanding, discontinued operations, diluted (in shares)									383	379	378
Weighted average number of shares outstanding, diluted (in shares)									383	379	378
Diluted net income (loss) from continuing operations per share (in USD per share)									$ 3.41	$ (3.62)	$ (28.70)
Diluted net income (loss) from discontinued operations per share (in USD per share)									0	(0.09)	1.30
Diluted net income (loss) per share (in USD per share)	$ 1.19	$ 0.16	$ 1.50	$ 0.56					$ 3.41	$ (3.71)	$ (27.40)

CAPITAL STOCK - Additional Info

CAPITAL STOCK - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended			19 Months Ended
	Jan. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options and restricted stock, anti-dilutive		7,300,000	4,700,000	7,000,000
Common stock share purchase, shares		40,000,000
Common stock share repurchase, shares					32,200,000
Common stock share repurchase price (in USD per share)					$ 88.96
Common stock dividends (in USD per share)		$ 1	$ 1	$ 1
Shares authorized and available for grant		16,900,000
Compensation expense		$ 142	$ 131	$ 100
Exercised, Shares		(15,000)	0
Intrinsic value of options exercised		$ 0.2		3
Stock-based compensation capitalized		41	$ 40	53
Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation cost related to non-vested awards not yet recognized		8
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense		108	$ 113	$ 90
Total compensation cost related to non-vested awards not yet recognized		$ 158
Awards granted during period (in shares)		1,947,506	4,049,023	2,976,562
Weighted average grant date fair value per share (in USD per share)		$ 62.74	$ 47.37	$ 61.65
Stock-based compensation capitalized		$ 35	$ 35	$ 48
Weighted-average remaining life of unvested restricted stock units		1 year 6 days
Unvested restricted stock units		4,919,681
Total fair value of restricted stock awards vested		$ 135	$ 151	$ 149
Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options Issued (in shares)	760,904
Share price (usd per share)	$ 13.15
Subsequent Event | Stock Option
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	$ 10
Subsequent Event | Restricted Stock
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	$ 23
Awards granted during period (in shares)	507,042
Weighted average grant date fair value per share (in USD per share)	$ 46.27
Subsequent Event | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation cost related to non-vested awards not yet recognized	$ 90
Options Issued (in shares)	1,954,474
Prior to 2016 | Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period in which stock options become exercisable		4 years
Period in which stock options expires after grant date		10 years
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 (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity [Abstract]
Stock-based compensation expensed	$ 142	$ 131	$ 100
Stock-based compensation capitalized	41	40	53
Total stock-based compensation costs	$ 183	$ 171	$ 153

CAPITAL STOCK - Summary of Stoc

CAPITAL STOCK - Summary of Stock Options Activities (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding, beginning of year, Shares	5,113,000
Granted, Shares	490,000
Exercised, Shares	(15,000)	0
Forfeited or expired, Shares	(995,000)
Outstanding, end of year, Shares	4,593,000	5,113,000
Expected to vest, Shares	947,000
Exercisable, end of year, Shares	3,646,000
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)	$ 84.89
Granted, Weighted Average Exercise Price (in USD per share)	63.25
Exercised, Weighted Average Exercise Price (in USD per share)	41.24
Forfeited or expired, Weighted Average Exercise Price (in USD per share)	82.03
Outstanding, end of year, Weighted Average Exercise Price (in USD per share)	83.37	$ 84.89
Expected to vest, Weighted Average Exercise Price (in USD per share)	51.83
Exercisable, end of year, Weighted Average Exercise Price (in USD per share)	$ 91.56
Weighted average remaining contractual life for options outstanding	4 years 8 months
Weighted average remaining contractual life for expected to vest	8 years 6 months
Weighted average remaining contractual life for exercisable	3 years 8 months
Aggregate intrinsic value for options outstanding	$ 0.7
Aggregate intrinsic value for expected to vest	0.5
Aggregate intrinsic value for exercisable	$ 0.2

CAPITAL STOCK - Schedule of Ass

CAPITAL STOCK - Schedule of Assumptions Used (Details) - Stock Option - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected volatility	34.58%	32.72%
Expected dividend yields	1.58%	2.42%
Expected term (in years)	6 years	6 years
Risk-free rate	2.02%	1.44%
Weighted-average grant-date fair value (in USD per share)	$ 19.38	$ 10.38

CAPITAL STOCK - Schedule of Res

CAPITAL STOCK - Schedule of Restricted Stock Activities (Detail) - Restricted Stock - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Restricted Shares, nonvested, Beginning Balance, Shares	6,062,000
Granted, Shares	1,947,506	4,049,023	2,976,562
Vested, Shares	(2,288,000)
Forfeited, Shares	(802,000)
Restricted Shares, nonvested, Ending Balance, Shares	4,920,000	6,062,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested Beginning Balance, Weighted Average Grant Date Fair Value (in USD per share)	$ 55.11
Granted, Weighted Average Grant-Date Fair Value (in USD per share)	62.74	$ 47.37	$ 61.65
Vested, Weighted Average Grant-Date Fair Value (in USD per share)	58.77
Forfeited, Weighted Average Grant-Date Fair Value (in USD per share)	55.54
Non-vested Ending Balance, Weighted Average Grant Date Fair Value (in USD per share)	$ 56.34	$ 55.11

CAPITAL STOCK - Performance Pro

CAPITAL STOCK - Performance Program Narrative (Detail) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended				12 Months Ended
	Jan. 31, 2018	Jan. 31, 2017	Jan. 31, 2016	Feb. 28, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant					16,900,000
Compensation expense					$ 142	$ 131	$ 100
Stock-based compensation capitalized					41	40	53
Conditional Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense					23	14	3
Stock-based compensation capitalized					4	$ 2	$ 1
Total compensation cost related to non-vested awards not yet recognized					$ 38
Nonvested shares outstanding					1,693,637
Weighted-average remaining life of unvested restricted stock units					1 year 6 months 24 days
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	$ 90
Performance Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares allocation percentage					50.00%
Shares vesting period					3 years
Performance Program | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares vesting percentage					50.00%
Remaining shares vesting percentage					50.00%
Performance Program | Conditional Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)					621,000
Nonvested shares outstanding					1,694,000	1,225,000
Weighted average grant date fair value per share (in USD per share)					$ 66.97
2015 Performance Program | Conditional Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)				602,304
Shares paid out as percentage of target					100.00%
Total awards, outstanding					384,967
2016 Performance Program | Conditional Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)			871,369
Total awards, outstanding					749,334
2016 Performance Program | Conditional Restricted Stock | 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					0
2016 Performance Program | Conditional Restricted Stock | 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					1,498,668
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
Total awards, outstanding					559,336
2017 Performance Program | Conditional Restricted Stock | 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					0
2017 Performance Program | Conditional Restricted Stock | 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					1,118,672
2018 Performance Program | Phantom Units | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	872,030
2018 Performance Program | Phantom Units | Subsequent Event | Monte Carlo Simulation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value per share (in USD per share)	$ 54.70
2018 Performance Program | Phantom Units | Subsequent Event | Fair Market Value at Grant Date
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)	$ 46.27
2018 Performance Program | Phantom Units | Subsequent Event | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant	0
2018 Performance Program | Phantom Units | Subsequent Event | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant	1,744,060

CAPITAL STOCK - Schedule of Per

CAPITAL STOCK - Schedule of Performance Program Activities (Detail) - Conditional Restricted Stock	12 Months Ended
	Dec. 31, 2017$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Restricted Shares, nonvested, Beginning Balance, Shares
Restricted Shares, nonvested, Ending Balance, Shares	1,693,637
Performance Program
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Restricted Shares, nonvested, Beginning Balance, Shares	1,225,000
Granted, Shares	621,000
Forfeited, Shares	(152,000)
Restricted Shares, nonvested, Ending Balance, Shares	1,694,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested Beginning Balance, Weighted Average Grant Date Fair Value (in USD per share) | $ / shares	$ 45.62
Granted, Weighted Average Grant-Date Fair Value (in USD per share) | $ / shares	66.97
Forfeited, Weighted Average Grant-Date Fair Value (in USD per share) | $ / shares	52.90
Non-vested Ending Balance, Weighted Average Grant Date Fair Value (in USD per share) | $ / shares	$ 52.39

ACCUMULATED OTHER COMPREHENSI95

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Currency translation adjustment	$ 0	$ (109)	$ (109)
Pension and postretirement benefit plan (Note 10)	4	(3)	(10)
Accumulated other comprehensive income (loss)	$ 4	$ (112)	$ (119)

MAJOR CUSTOMERS (Detail)

MAJOR CUSTOMERS (Detail) - Customer Concentration Risk - Oil and Gas Production Revenues	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
BP plc
Revenue, Major Customer [Line Items]
Concentration risk percentage	12.00%	9.00%	8.00%
China Petroleum & Chemical Corporation
Revenue, Major Customer [Line Items]
Concentration risk percentage	16.00%	21.00%	12.00%
Egyptian General Petroleum Corporation
Revenue, Major Customer [Line Items]
Concentration risk percentage	11.00%	12.00%	11.00%
Royal Dutch Shell plc
Revenue, Major Customer [Line Items]
Concentration risk percentage	6.00%	5.00%	11.00%

BUSINESS SEGMENT INFORMATION -

BUSINESS SEGMENT INFORMATION - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017Segment
Segment Reporting [Abstract]
Number of reporting segments	3

BUSINESS SEGMENT INFORMATION 98

BUSINESS SEGMENT INFORMATION - Financial Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Oil and gas production revenues									$ 5,887	$ 5,367	$ 6,510
Operating Expenses:
Lease operating expenses									1,400	1,494	1,854
Gathering and transportation									179	200	211
Taxes other than income									151	126	282
Depreciation, depletion, and amortization									2,280	2,618	3,300
Exploration									549	473	2,771
Asset retirement obligation accretion									130	156	145
Impairments									8	1,103	9,472
Operating Income (Loss)									1,190	(803)	(11,525)
Other Income (Expense):
Gain on divestiture	$ 11	$ 296	$ (21)	$ 341	$ 0	$ 5	$ 17	$ (1)	627	21	281
Derivative instrument gains (losses), net									(135)	0	0
Other									44	(34)	98
General and administrative									(395)	(410)	(380)
Transaction, reorganization, and separation									(16)	(39)	(132)
Financing costs, net									(397)	(417)	(511)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES									918	(1,682)	(12,169)
Net Property and Equipment	17,759				18,867				17,759	18,867	20,838
Total Assets	21,922				22,519				21,922	22,519	25,500
Additions to Net Property and Equipment	3,302				1,681				3,302	1,681	4,106
Operating Segments | United States
Segment Reporting Information [Line Items]
Oil and gas production revenues									2,271	1,997	2,637
Operating Expenses:
Lease operating expenses									600	553	739
Gathering and transportation									71	80	68
Taxes other than income									153	139	184
Depreciation, depletion, and amortization									1,000	1,138	1,558
Exploration									363	285	2,145
Asset retirement obligation accretion									31	34	28
Impairments									0	80	6,266
Operating Income (Loss)									53	(312)	(8,351)
Other Income (Expense):
Net Property and Equipment	12,070				11,168				12,070	11,168	11,753
Total Assets	14,228				12,403				14,228	12,403	12,782
Additions to Net Property and Equipment	2,397				926				2,397	926	2,099
Operating Segments | Canada
Segment Reporting Information [Line Items]
Oil and gas production revenues									231	343	498
Operating Expenses:
Lease operating expenses									103	181	244
Gathering and transportation									34	68	89
Taxes other than income									12	20	26
Depreciation, depletion, and amortization									76	183	301
Exploration									11	88	231
Asset retirement obligation accretion									27	47	43
Impairments									0	367	1,593
Operating Income (Loss)									(32)	(611)	(2,029)
Other Income (Expense):
Net Property and Equipment	0				1,464				0	1,464	2,074
Total Assets	0				1,591				0	1,591	2,225
Additions to Net Property and Equipment	0				34				0	34	403
Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil and gas production revenues									2,307	2,057	2,095
Operating Expenses:
Lease operating expenses									362	446	522
Gathering and transportation									44	44	45
Taxes other than income									0	0	9
Depreciation, depletion, and amortization									758	778	927
Exploration									62	48	154
Asset retirement obligation accretion									0	0	0
Impairments									0	1	1,255
Operating Income (Loss)									1,081	740	(817)
Other Income (Expense):
Net Property and Equipment	3,099				3,362				3,099	3,362	3,712
Total Assets	4,658				4,893				4,658	4,893	6,165
Additions to Net Property and Equipment	517				459				517	459	862
Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil and gas production revenues									1,078	970	1,280
Operating Expenses:
Lease operating expenses									335	314	349
Gathering and transportation									30	8	9
Taxes other than income									(14)	(33)	63
Depreciation, depletion, and amortization									446	519	514
Exploration									86	37	237
Asset retirement obligation accretion									72	75	74
Impairments									8	655	211
Operating Income (Loss)									115	(605)	(177)
Other Income (Expense):
Net Property and Equipment	2,553				2,834				2,553	2,834	3,263
Total Assets	2,977				3,584				2,977	3,584	4,280
Additions to Net Property and Equipment	374				260				374	260	715
Other International
Segment Reporting Information [Line Items]
Oil and gas production revenues									0	0	0
Operating Expenses:
Lease operating expenses									0	0	0
Gathering and transportation									0	0	0
Taxes other than income									0	0	0
Depreciation, depletion, and amortization									0	0	0
Exploration									27	15	4
Asset retirement obligation accretion									0	0	0
Impairments									0	0	147
Operating Income (Loss)									(27)	(15)	(151)
Other Income (Expense):
Net Property and Equipment	37				39				37	39	36
Total Assets	59				48				59	48	48
Additions to Net Property and Equipment	$ 14				$ 2				$ 14	$ 2	$ 27

SUPPLEMENTAL OIL AND GAS DISC99

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	$ 5,887	$ 5,367	$ 6,510
Depreciation, depletion, and amortization	2,136	2,460	2,976
Asset retirement obligation accretion	130	156	145
Lease operating expenses	1,400	1,494	1,854
Gathering and transportation	179	200	211
Exploration expenses	549	473	2,771
Impairments related to oil and gas properties		427	7,389
Production taxes	150	120	259
Income tax	601	148	(3,049)
Oil and gas properties production expense	5,145	5,478	12,556
Results of operation	742	(111)	(6,046)
United States
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	2,271	1,997	2,637
Depreciation, depletion, and amortization	924	1,055	1,455
Asset retirement obligation accretion	31	34	28
Lease operating expenses	600	553	739
Gathering and transportation	71	80	68
Exploration expenses	363	285	2,145
Impairments related to oil and gas properties		61	6,154
Production taxes	153	135	178
Income tax	45	(72)	(2,886)
Oil and gas properties production expense	2,187	2,131	7,881
Results of operation	84	(134)	(5,244)
Canada
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	231	343	498
Depreciation, depletion, and amortization	72	174	251
Asset retirement obligation accretion	27	47	43
Lease operating expenses	103	181	244
Gathering and transportation	34	68	89
Exploration expenses	11	88	231
Impairments related to oil and gas properties		366	1,031
Production taxes	11	18	23
Income tax	(7)	(162)	(369)
Oil and gas properties production expense	251	780	1,543
Results of operation	(20)	(437)	(1,045)
Egypt
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	2,307	2,057	2,095
Depreciation, depletion, and amortization	707	733	780
Asset retirement obligation accretion	0	0	0
Lease operating expenses	362	446	522
Gathering and transportation	44	44	45
Exploration expenses	62	48	154
Impairments related to oil and gas properties		0	193
Production taxes	0	0	0
Income tax	509	354	180
Oil and gas properties production expense	1,684	1,625	1,874
Results of operation	623	432	221
North Sea
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	1,078	970	1,280
Depreciation, depletion, and amortization	433	498	490
Asset retirement obligation accretion	72	75	74
Lease operating expenses	335	314	349
Gathering and transportation	30	8	9
Exploration expenses	86	37	237
Impairments related to oil and gas properties		0	11
Production taxes	(14)	(33)	58
Income tax	54	28	26
Oil and gas properties production expense	996	927	1,254
Results of operation	82	43	26
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 and transportation	0	0	0
Exploration expenses	27	15	4
Impairments related to oil and gas properties		0	0
Production taxes	0	0	0
Income tax	0	0	0
Oil and gas properties production expense	27	15	4
Results of operation	$ (27)	$ (15)	$ (4)

SUPPLEMENTAL OIL AND GAS DIS100

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	$ 7	$ 45	$ 38
Unproved	181	170	336
Exploration	891	470	677
Development	1,807	950	3,198
Costs incurred	2,886	1,635	4,249
Capitalized interest	44	48	21
Asset retirement costs	70	(192)	65
United States
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	3	0	1
Unproved	136	110	313
Exploration	602	278	194
Development	1,118	420	1,729
Costs incurred	1,859	808	2,237
Capitalized interest	23	21	0
Asset retirement costs	15	(51)	123
Canada
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	0	1	8
Unproved	5	7	23
Exploration	11	23	51
Development	52	27	151
Costs incurred	68	58	233
Capitalized interest	2	6	0
Asset retirement costs	0	(13)	8
Egypt
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	4	6	29
Unproved	40	49	0
Exploration	122	67	125
Development	387	353	741
Costs incurred	553	475	895
Capitalized interest	0	0	8
Asset retirement costs	0	0	0
Australia
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	0	0	0
Unproved	0	0	0
Exploration	0	0	32
Development	0	0	98
Costs incurred	0	0	130
Capitalized interest	0	0	6
Asset retirement costs	0	0	0
North Sea
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	0	38	0
Unproved	0	4	0
Exploration	131	84	246
Development	250	150	479
Costs incurred	381	276	725
Capitalized interest	17	21	7
Asset retirement costs	55	(128)	(66)
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	25	18	29
Development	0	0	0
Costs incurred	25	18	29
Capitalized interest	2	0	0
Asset retirement costs	$ 0	$ 0	$ 0

SUPPLEMENTAL OIL AND GAS DIS101

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Reserve Quantities [Line Items]
Proved properties	$ 39,197	$ 42,693
Unproved properties	1,783	1,969
Capitalized costs, gross	40,980	44,662
Accumulated DD&A	(24,711)	(26,972)
Capitalized costs, net	16,269	17,690
United States
Reserve Quantities [Line Items]
Proved properties	20,408	19,170
Unproved properties	1,312	1,465
Capitalized costs, gross	21,720	20,635
Accumulated DD&A	(10,766)	(10,034)
Capitalized costs, net	10,954	10,601
Canada
Reserve Quantities [Line Items]
Proved properties	0	5,434
Unproved properties	0	109
Capitalized costs, gross	0	5,543
Accumulated DD&A	0	(4,120)
Capitalized costs, net	0	1,423
Egypt
Reserve Quantities [Line Items]
Proved properties	10,590	10,169
Unproved properties	137	76
Capitalized costs, gross	10,727	10,245
Accumulated DD&A	(7,985)	(7,287)
Capitalized costs, net	2,742	2,958
North Sea
Reserve Quantities [Line Items]
Proved properties	8,199	7,920
Unproved properties	297	280
Capitalized costs, gross	8,496	8,200
Accumulated DD&A	(5,960)	(5,531)
Capitalized costs, net	2,536	2,669
Other International
Reserve Quantities [Line Items]
Proved properties	0	0
Unproved properties	37	39
Capitalized costs, gross	37	39
Accumulated DD&A	0	0
Capitalized costs, net	$ 37	$ 39

SUPPLEMENTAL OIL AND GAS DIS102

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Oil and Gas Reserve Information (Detail) MBoe in Thousands	12 Months Ended
	Dec. 31, 2017MBoeMMcfMBbls	Dec. 31, 2016MBoeMMcfMBbls	Dec. 31, 2015MBoeMMcfMBbls	Dec. 31, 2014MBoeMMcfMBbls
Reserve Quantities [Line Items]
Proved developed reserves	1,023,663	1,173,635	1,331,397	1,651,291
Proved undeveloped reserves	151,323	137,616	232,336	744,979
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	1,311,251	1,563,733	2,396,270
Extensions, discoveries and other additions	229,977	103,204	117,405
Purchases of minerals in-place	2,285	1,580	6,860
Revisions of previous estimates	10,394	(159,341)	(365,135)
Production	(166,923)	(190,942)	(206,840)
Sales of minerals in-place	(211,998)	(6,983)	(384,827)
Ending balance	1,174,986	1,311,251	1,563,733
United States
Reserve Quantities [Line Items]
Proved developed reserves	699,786	656,087	726,424	897,422
Proved undeveloped reserves	111,001	76,950	120,210	336,670
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	733,037	846,634	1,234,092
Extensions, discoveries and other additions	145,322	56,458	26,488
Purchases of minerals in-place	991	24	0
Revisions of previous estimates	12,903	(87,954)	(322,123)
Production	(75,151)	(81,994)	(91,591)
Sales of minerals in-place	(6,315)	(131)	(232)
Ending balance	810,787	733,037	846,634
Canada
Reserve Quantities [Line Items]
Proved developed reserves	0	157,662	209,647	258,848
Proved undeveloped reserves	0	17,931	70,300	155,028
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	175,593	279,947	413,876
Extensions, discoveries and other additions	24,115	9,166	26,226
Purchases of minerals in-place	1,294	0	6,860
Revisions of previous estimates	16,136	(84,984)	(87,081)
Production	(11,455)	(21,684)	(24,706)
Sales of minerals in-place	(205,683)	(6,852)	(55,228)
Ending balance	0	175,593	279,947
Egypt
Reserve Quantities [Line Items]
Proved developed reserves	215,364	252,630	275,033	236,256
Proved undeveloped reserves	24,112	27,336	26,929	43,446
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	279,966	301,962	279,702
Extensions, discoveries and other additions	40,731	23,674	40,464
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	(21,936)	16,599	37,825
Production	(59,285)	(62,269)	(56,029)
Sales of minerals in-place	0	0	0
Ending balance	239,476	279,966	301,962
Australia
Reserve Quantities [Line Items]
Proved developed reserves	0	0	0	136,707
Proved undeveloped reserves	0	0	0	186,534
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	0	0	323,241
Extensions, discoveries and other additions	0	0	0
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	0	0	12,549
Production	0	0	(8,503)
Sales of minerals in-place	0	0	(327,287)
Ending balance	0	0	0
North Sea
Reserve Quantities [Line Items]
Proved developed reserves	108,513	107,256	120,293	122,058
Proved undeveloped reserves	16,210	15,399	14,897	23,301
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	122,655	135,190	145,359
Extensions, discoveries and other additions	19,809	13,906	24,227
Purchases of minerals in-place	0	1,556	0
Revisions of previous estimates	3,291	(3,002)	(6,305)
Production	(21,032)	(24,995)	(26,011)
Sales of minerals in-place	0	0	(2,080)
Ending balance	124,723	122,655	135,190
Crude Oil and Condensate
Reserve Quantities [Line Items]
Proved developed reserves	521,445	582,317	665,063	784,770
Proved undeveloped reserves	62,115	59,965	127,996	289,499
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	642,282	793,059	1,074,269
Extensions, discoveries and other additions	105,579	40,351	59,556
Purchases of minerals in-place	421	459	1,763
Revisions of previous estimates	(675)	(88,714)	(165,609)
Production	(89,156)	(100,744)	(108,491)
Sales of minerals in-place	(74,891)	(2,129)	(68,429)
Ending balance	583,560	642,282	793,059
Crude Oil and Condensate | United States
Reserve Quantities [Line Items]
Proved developed reserves	304,279	300,900	348,797	444,440
Proved undeveloped reserves	31,904	21,088	60,505	170,125
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	321,988	409,302	614,565
Extensions, discoveries and other additions	48,391	9,614	13,903
Purchases of minerals in-place	46	21	0
Revisions of previous estimates	825	(58,882)	(173,907)
Production	(33,394)	(38,000)	(45,138)
Sales of minerals in-place	(1,673)	(67)	(121)
Ending balance	336,183	321,988	409,302
Crude Oil and Condensate | Canada
Reserve Quantities [Line Items]
Proved developed reserves	0	51,508	67,847	75,876
Proved undeveloped reserves	0	7,906	38,326	59,923
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	59,414	106,173	135,799
Extensions, discoveries and other additions	14,025	3,372	4,550
Purchases of minerals in-place	375	0	1,763
Revisions of previous estimates	1,829	(43,282)	(27,966)
Production	(2,425)	(4,787)	(5,755)
Sales of minerals in-place	(73,218)	(2,062)	(2,218)
Ending balance	0	59,414	106,173
Crude Oil and Condensate | Egypt
Reserve Quantities [Line Items]
Proved developed reserves	124,568	138,771	144,164	128,712
Proved undeveloped reserves	16,198	20,187	17,856	14,617
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	158,958	162,020	143,329
Extensions, discoveries and other additions	27,140	17,599	24,524
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	(9,839)	17,301	27,330
Production	(35,493)	(37,962)	(33,163)
Sales of minerals in-place	0	0	0
Ending balance	140,766	158,958	162,020
Crude Oil and Condensate | Australia
Reserve Quantities [Line Items]
Proved developed reserves	0	0	0	29,996
Proved undeveloped reserves	0	0	0	25,775
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	0	0	55,771
Extensions, discoveries and other additions	0	0	0
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	0	0	11,189
Production	0	0	(2,778)
Sales of minerals in-place	0	0	(64,182)
Ending balance	0	0	0
Crude Oil and Condensate | North Sea
Reserve Quantities [Line Items]
Proved developed reserves	92,598	91,138	104,255	105,746
Proved undeveloped reserves	14,013	10,784	11,309	19,059
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	101,922	115,564	124,805
Extensions, discoveries and other additions	16,023	9,766	16,579
Purchases of minerals in-place	0	438	0
Revisions of previous estimates	6,510	(3,851)	(2,255)
Production	(17,844)	(19,995)	(21,657)
Sales of minerals in-place	0	0	(1,908)
Ending balance	106,611	101,922	115,564
Natural Gas Liquids
Reserve Quantities [Line Items]
Proved developed reserves	173,715	171,883	168,786	204,628
Proved undeveloped reserves	29,951	20,561	30,151	77,579
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	192,444	198,937	282,207
Extensions, discoveries and other additions	36,495	11,872	8,074
Purchases of minerals in-place	405	7	976
Revisions of previous estimates	11,176	5,627	(69,178)
Production	(19,515)	(22,942)	(22,721)
Sales of minerals in-place	(17,339)	(1,057)	(421)
Ending balance	203,666	192,444	198,937
Natural Gas Liquids | United States
Reserve Quantities [Line Items]
Proved developed reserves	171,005	155,124	150,265	183,565
Proved undeveloped reserves	29,559	17,311	24,939	69,828
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	172,435	175,204	253,393
Extensions, discoveries and other additions	33,806	10,238	5,768
Purchases of minerals in-place	206	2	0
Revisions of previous estimates	12,982	6,824	(64,226)
Production	(17,766)	(19,824)	(19,684)
Sales of minerals in-place	(1,099)	(9)	(47)
Ending balance	200,564	172,435	175,204
Natural Gas Liquids | Canada
Reserve Quantities [Line Items]
Proved developed reserves	0	13,866	15,246	17,947
Proved undeveloped reserves	0	2,473	4,839	7,168
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	16,339	20,085	25,115
Extensions, discoveries and other additions	1,794	755	1,473
Purchases of minerals in-place	199	0	976
Revisions of previous estimates	(1,060)	(1,355)	(4,886)
Production	(1,032)	(2,098)	(2,236)
Sales of minerals in-place	(16,240)	(1,048)	(357)
Ending balance	0	16,339	20,085
Natural Gas Liquids | Egypt
Reserve Quantities [Line Items]
Proved developed reserves	685	1,266	1,491	1,346
Proved undeveloped reserves	39	131	78	212
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	1,397	1,569	1,558
Extensions, discoveries and other additions	50	208	144
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	(425)	17	255
Production	(298)	(397)	(388)
Sales of minerals in-place	0	0	0
Ending balance	724	1,397	1,569
Natural Gas Liquids | North Sea
Reserve Quantities [Line Items]
Proved developed reserves	2,025	1,627	1,784	1,770
Proved undeveloped reserves	353	646	295	371
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	2,273	2,079	2,141
Extensions, discoveries and other additions	845	671	689
Purchases of minerals in-place	0	5	0
Revisions of previous estimates	(321)	141	(321)
Production	(419)	(623)	(413)
Sales of minerals in-place	0	0	(17)
Ending balance	2,378	2,273	2,079
Natural Gas
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	1,971,018	2,516,610	2,985,290	3,971,360
Proved undeveloped reserves | MMcf	355,544	342,538	445,132	2,267,400
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	2,859,148	3,430,422	6,238,760
Extensions, discoveries and other additions | MMcf	527,418	305,883	298,649
Purchases of minerals in-place | MMcf	8,753	6,684	24,727
Revisions of previous estimates | MMcf	(641)	(457,524)	(782,083)
Production | MMcf	(349,509)	(403,533)	(453,772)
Sales of minerals in-place | MMcf	(718,607)	(22,784)	(1,895,859)
Ending balance | MMcf	2,326,562	2,859,148	3,430,422
Natural Gas | United States
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	1,347,009	1,200,379	1,364,174	1,616,504
Proved undeveloped reserves | MMcf	297,226	231,304	208,594	580,299
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	1,431,683	1,572,768	2,196,803
Extensions, discoveries and other additions | MMcf	378,747	219,633	40,901
Purchases of minerals in-place | MMcf	4,434	7	0
Revisions of previous estimates | MMcf	(5,431)	(215,378)	(503,939)
Production | MMcf	(143,943)	(145,019)	(160,614)
Sales of minerals in-place | MMcf	(21,255)	(328)	(383)
Ending balance | MMcf	1,644,235	1,431,683	1,572,768
Natural Gas | Canada
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	0	553,724	759,321	990,145
Proved undeveloped reserves | MMcf	0	45,312	162,809	527,623
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	599,036	922,130	1,517,768
Extensions, discoveries and other additions | MMcf	49,780	30,234	121,216
Purchases of minerals in-place	4,319	0	24,727
Revisions of previous estimates	92,207	(242,080)	(325,375)
Production	(47,990)	(88,792)	(100,289)
Sales of minerals in-place	(697,352)	(22,456)	(315,917)
Ending balance | MMcf	0	599,036	922,130
Natural Gas | Egypt
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	540,667	675,559	776,263	637,187
Proved undeveloped reserves | MMcf	47,255	42,109	53,969	171,696
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	717,668	830,232	808,883
Extensions, discoveries and other additions | MMcf	81,245	35,202	94,777
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	(70,030)	(4,305)	61,442
Production	(140,961)	(143,461)	(134,870)
Sales of minerals in-place	0	0	0
Ending balance | MMcf	587,922	717,668	830,232
Natural Gas | Australia
Reserve Quantities [Line Items]
Proved developed reserves	0	0	0	640,265
Proved undeveloped reserves	0	0	0	964,554
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	0	0	1,604,819
Extensions, discoveries and other additions | MMcf	0	0	0
Purchases of minerals in-place	0	0	0
Revisions of previous estimates	0	0	8,162
Production	0	0	(34,352)
Sales of minerals in-place	0	0	(1,578,629)
Ending balance | MMcf	0	0	0
Natural Gas | North Sea
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	83,342	86,948	85,532	87,259
Proved undeveloped reserves | MMcf	11,063	23,813	19,760	23,228
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	110,761	105,292	110,487
Extensions, discoveries and other additions | MMcf	17,646	20,814	41,755
Purchases of minerals in-place	0	6,677	0
Revisions of previous estimates	(17,387)	4,239	(22,373)
Production	(16,615)	(26,261)	(23,647)
Sales of minerals in-place	0	0	(930)
Ending balance | MMcf	94,405	110,761	105,292
Noncontrolling Interest | Egypt
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved developed reserves (Energy) | MBoe	80	93	101	93
Noncontrolling Interest | Crude Oil and Condensate | Egypt
Reserve Quantities [Line Items]
Proved developed reserves	47,000	53,000	54,000	48,000
Noncontrolling Interest | Natural Gas Liquids | Egypt
Reserve Quantities [Line Items]
Proved developed reserves	241	466	523	519
Noncontrolling Interest | Natural Gas | Egypt
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	196,000	239,000	277,000	270,000

SUPPLEMENTAL OIL AND GAS DIS103

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017MMBoeMBbls	Dec. 31, 2016MBbls	Dec. 31, 2015MBbls
Reserve Quantities [Line Items]
Sales of minerals in-place	211,998	6,983	384,827
Purchases of minerals in-place	2,285	1,580	6,860
Extensions, discoveries and other additions	229,977	103,204	117,405
Changes in reserves accounted	10,394	(159,341)	(365,135)
Percentage of estimated proved developed reserves classified as proved not producing	9.00%
North America
Reserve Quantities [Line Items]
Extensions, discoveries and other additions | MMBoe	169
Premian Basin
Reserve Quantities [Line Items]
Extensions, discoveries and other additions | MMBoe	128
Canada
Reserve Quantities [Line Items]
Sales of minerals in-place	205,683	6,852	55,228
Purchases of minerals in-place	1,294	0	6,860
Extensions, discoveries and other additions	24,115	9,166	26,226
Extensions, discoveries and other additions | MMBoe	24
Changes in reserves accounted	16,136	(84,984)	(87,081)
MidContinent Region
Reserve Quantities [Line Items]
Extensions, discoveries and other additions | MMBoe	17
Egypt
Reserve Quantities [Line Items]
Sales of minerals in-place	0	0	0
Purchases of minerals in-place	0	0	0
Extensions, discoveries and other additions	40,731	23,674	40,464
Extensions, discoveries and other additions | MMBoe	41
Changes in reserves accounted	(21,936)	16,599	37,825
North Sea
Reserve Quantities [Line Items]
Sales of minerals in-place	0	0	2,080
Purchases of minerals in-place	0	1,556	0
Extensions, discoveries and other additions	19,809	13,906	24,227
Extensions, discoveries and other additions | MMBoe	20
Changes in reserves accounted	3,291	(3,002)	(6,305)
International Regions
Reserve Quantities [Line Items]
Extensions, discoveries and other additions | MMBoe	61
Changes in Product Prices
Reserve Quantities [Line Items]
Changes in reserves accounted	32
Changes in Engineering and Performance
Reserve Quantities [Line Items]
Changes in reserves accounted	22

SUPPLEMENTAL OIL AND GAS DIS104

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Future Net Cash Flows (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	$ 39,755	$ 37,204
Production costs	(14,826)	(15,662)
Development costs	(5,506)	(6,739)
Income tax expense	(2,473)	(1,815)
Net cash flows	16,950	12,988
10 percent discount rate	(6,867)	(4,928)
Discounted future net cash flows	$ 10,083	8,060
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	$ 12,200	9,500
Egypt
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	9,254	8,778
Production costs	(1,749)	(1,967)
Development costs	(1,052)	(1,111)
Income tax expense	(2,078)	(1,775)
Net cash flows	4,375	3,925
10 percent discount rate	(1,034)	(956)
Discounted future net cash flows	3,341	2,969
Egypt | Noncontrolling Interest
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Discounted future net cash flows	1,100	1,000
United States
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	24,271	20,067
Production costs	(10,618)	(8,858)
Development costs	(1,659)	(1,653)
Income tax expense	(42)	(32)
Net cash flows	11,952	9,524
10 percent discount rate	(6,080)	(5,319)
Discounted future net cash flows	5,872	4,205
Canada
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	0	3,625
Production costs	0	(2,582)
Development costs	0	(1,565)
Income tax expense	0	0
Net cash flows	0	(522)
10 percent discount rate	0	549
Discounted future net cash flows	0	27
North Sea
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	6,230	4,734
Production costs	(2,459)	(2,255)
Development costs	(2,795)	(2,410)
Income tax expense	(353)	(8)
Net cash flows	623	61
10 percent discount rate	247	798
Discounted future net cash flows	$ 870	$ 859

SUPPLEMENTAL OIL AND GAS DIS105

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Principal Sources of Change In Discounted Future Net Cash Flows (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Sales, net of production costs	$ (4,158)	$ (3,479)	$ (4,056)
Net change in prices and production costs	3,651	(3,835)	(21,710)
Discoveries and improved recovery, net of related costs	2,273	1,153	1,953
Change in future development costs	(279)	309	705
Previously estimated development costs incurred during the period	719	986	1,991
Revision of quantities	(344)	(574)	(2,292)
Purchases of minerals in-place	9	8	22
Accretion of discount	952	1,313	3,642
Change in income taxes	(617)	1,070	7,264
Sales of minerals in-place	(809)	(52)	(5,240)
Change in production rates and other	626	567	(3,343)
Change in the discounted future net cash flows, Total	$ 2,023	$ (2,534)	$ (21,064)

SUPPLEMENTAL QUARTERLY FINAN106

SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited) (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Oil and gas production revenues	$ 1,640	$ 1,389	$ 1,346	$ 1,512	$ 1,455	$ 1,439	$ 1,386	$ 1,087
Gain (loss) on divestitures	11	296	(21)	341	0	5	17	(1)	$ 627	$ 21	$ 281
Net income (loss)	518	105	613	267	(143)	(559)	(200)	(371)	1,503	(1,273)	(10,667)
Net income (loss) attributable to common stock	$ 456	$ 63	$ 572	$ 213	$ (182)	$ (607)	$ (244)	$ (372)	$ 1,304	$ (1,405)	$ (10,352)
Basic and diluted net loss per common share:
Basic net income (loss) per share (in USD per share)	$ 1.20	$ 0.16	$ 1.50	$ 0.56					$ 3.42	$ (3.71)	$ (27.40)
Diluted net income (loss) per share (in USD per share)	$ 1.19	$ 0.16	$ 1.50	$ 0.56					$ 3.41	$ (3.71)	$ (27.40)
Basic and diluted net loss per share (in USD per share)					$ (0.48)	$ (1.60)	$ (0.65)	$ (0.98)
Asset impairments	$ 32	$ 160	$ 39	$ 23	$ 144	$ 951	$ 238	$ 42	$ 8	$ 1,103	$ 9,472