10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________________________________

FORM 10-Q

________________________________________________________________

(Mark One)

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2017

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-4300

APACHE CORPORATION

(exact name of registrant as specified in its charter)

    _______________________________________________________________________

Delaware	41-0747868
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400

(Address of principal executive offices)

Registrant’s Telephone Number, Including Area Code: (713) 296-6000

__________________________________________________________________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	ý	Accelerated filer	¨
Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨
		Emerging growth company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  ¨    No  ý

Number of shares of registrant’s common stock outstanding as of October 31, 2017 380,942,629

	TABLE OF CONTENTS
	DESCRIPTION
Item		Page
	PART I - FINANCIAL INFORMATION
1.	FINANCIAL STATEMENTS	1
	STATEMENT OF CONSOLIDATED OPERATIONS	1
	STATEMENT OF CONSOLIDATED CASH FLOWS	3
	CONSOLIDATED BALANCE SHEET	4
	STATEMENT OF CONSOLIDATED CHANGES IN EQUITY	5
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	6
2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	24
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	36
4.	CONTROLS AND PROCEDURES	37
	PART II - OTHER INFORMATION
1.	LEGAL PROCEEDINGS	38
1A.	RISK FACTORS	38
2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	38
3.	DEFAULTS UPON SENIOR SECURITIES	38
4.	MINE SAFETY DISCLOSURES	38
5.	OTHER INFORMATION	38
6.	EXHIBITS	39

Forward-Looking Statements and Risk

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs, and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information that was used to prepare our estimate of proved reserves as of December 31, 2016, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

• the market prices of oil, natural gas, natural gas liquids (NGLs), and other products or services;

• our commodity hedging arrangements;

• the supply and demand for oil, natural gas, NGLs, and other products or services;

• production and reserve levels;

• drilling risks;

• economic and competitive conditions;

• the availability of capital resources;

• capital expenditure and other contractual obligations;

• currency exchange rates;

• weather conditions;

• inflation rates;

• the availability of goods and services;

• legislative, regulatory, or policy changes;

• terrorism or cyber-attacks;

• occurrence of property acquisitions or divestitures;

• the integration of acquisitions;

• the securities or capital markets and related risks such as general credit, liquidity, market, and interest-rate risks; and

• other factors disclosed under Items 1 and 2—Business and Properties—Estimated Proved Reserves and Future Net Cash Flows, Item 1A—Risk Factors, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A—Quantitative and Qualitative Disclosures About Market Risk and elsewhere in our most recently filed Annual Report on Form 10-K, other risks and uncertainties in our third-quarter 2017 earnings release, other factors disclosed under Part II, Item 1A—Risk Factors of this Quarterly Report on Form 10-Q, and other filings that we make with the Securities and Exchange Commission.

All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.

PART I – FINANCIAL INFORMATION

ITEM 1 – FINANCIAL STATEMENTS

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

(Unaudited)

	For the Quarter Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(In millions, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues
Oil revenues	$	1,070		$	1,117		$	3,292		$	3,057
Gas revenues	238			263			726			695
Natural gas liquids revenues	81			59			229			160
	1,389			1,439			4,247			3,912
Derivative instrument losses, net	(110		)	—			(69		)	—
Gain on divestitures	296			5			616			21
Other	—			(6		)	43			(30		)
	1,575			1,438			4,837			3,903
OPERATING EXPENSES:
Lease operating expenses	358			382			1,066			1,119
Gathering and transportation	39			51			144			155
Taxes other than income	46			9			117			85
Exploration	231			161			431			347
General and administrative	98			102			307			298
Transaction, reorganization, and separation	20			12			14			36
Depreciation, depletion, and amortization:
Oil and gas property and equipment	524			610			1,598			1,875
Other assets	35			38			109			120
Asset retirement obligation accretion	30			40			103			116
Impairments	—			836			8			1,009
Financing costs, net	101			102			300			311
	1,482			2,343			4,197			5,471
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	93			(905		)	640			(1,568		)
Current income tax provision	99			150			413			284
Deferred income tax benefit	(111		)	(529		)	(758		)	(755		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	105			(526		)	985			(1,097		)
Net loss from discontinued operations, net of tax	—			(33		)	—			(33		)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	105			(559		)	985			(1,130		)
Net income attributable to noncontrolling interest	42			48			137			93
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	63		$	(607	)	$	848		$	(1,223	)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Net income (loss) from continuing operations attributable to common shareholders	$	63		$	(574	)	$	848		$	(1,190	)
Net loss from discontinued operations	—			(33		)	—			(33		)
Net income (loss) attributable to common shareholders	$	63		$	(607	)	$	848		$	(1,223	)
NET INCOME (LOSS) PER COMMON SHARE:
Basic net income (loss) from continuing operations per share	$	0.16		$	(1.51	)	$	2.23		$	(3.14	)
Basic net loss from discontinued operations per share	—			(0.09		)	—			(0.08		)
Basic net income (loss) per share	$	0.16		$	(1.60	)	$	2.23		$	(3.22	)
DILUTED NET INCOME (LOSS) PER COMMON SHARE:
Diluted net income (loss) from continuing operations per share	$	0.16		$	(1.51	)	$	2.22		$	(3.14	)
Diluted net loss from discontinued operations per share	—			(0.09		)	—			(0.08		)
Diluted net income (loss) per share	$	0.16		$	(1.60	)	$	2.22		$	(3.22	)
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	381			380			381			379
Diluted	383			380			383			379
DIVIDENDS DECLARED PER COMMON SHARE	$	0.25		$	0.25		$	0.75		$	0.75

The accompanying notes to consolidated financial statements

are an integral part of this statement.

1

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	For the Quarter Ended September 30,					For the Nine Months Ended September 30,
	2017		2016			2017		2016
	(In millions)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	$	105	$	(559	)	$	985	$	(1,130	)
OTHER COMPREHENSIVE INCOME:
Currency translation adjustment	109		—			109		—
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	214		(559		)	1,094		(1,130		)
Comprehensive income attributable to noncontrolling interest	42		48			137		93
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	172	$	(607	)	$	957	$	(1,223	)

The accompanying notes to consolidated financial statements

are an integral part of this statement.

2

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

(Unaudited)

	For the Nine Months Ended September 30,
	2017			2016
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) including noncontrolling interest	$	985		$	(1,130	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss from discontinued operations	—			33
Unrealized derivative instrument losses, net	42			—
Gain on divestitures	(616		)	(21		)
Exploratory dry hole expense and unproved leasehold impairments	350			260
Depreciation, depletion, and amortization	1,707			1,995
Asset retirement obligation accretion	103			116
Impairments	8			1,009
Deferred income tax benefit	(758		)	(755		)
Other	167			126
Changes in operating assets and liabilities:
Receivables	(70		)	192
Inventories	17			(2		)
Drilling advances	(72		)	(36		)
Deferred charges and other	(60		)	40
Accounts payable	2			(93		)
Accrued expenses	(65		)	(67		)
Deferred credits and noncurrent liabilities	20			(33		)
NET CASH PROVIDED BY OPERATING ACTIVITIES	1,760			1,634
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(1,471		)	(1,281		)
Leasehold and property acquisitions	(142		)	(169		)
Additions to gas gathering, transmission, and processing facilities	(384		)	(33		)
Proceeds from sale of Canadian assets, net of cash divested	661			—
Proceeds from sale of oil and gas properties	743			74
Other, net	(30		)	47
NET CASH USED IN INVESTING ACTIVITIES	(623		)	(1,362		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on fixed-rate debt	(70		)	(1		)
Distributions to noncontrolling interest	(212		)	(215		)
Dividends paid	(285		)	(284		)
Other	(5		)	(9		)
NET CASH USED IN FINANCING ACTIVITIES	(572		)	(509		)
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS, AND RESTRICTED CASH	565			(237		)
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF YEAR	1,377			1,467
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	$	1,942		$	1,230
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	341		$	345
Income taxes paid, net of refunds	315			256

The accompanying notes to consolidated financial statements

are an integral part of this statement.

3

APACHE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)

	September 30, 2017			December 31, 2016
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,846		$	1,377
Restricted cash	96			—
Receivables, net of allowance	1,145			1,128
Inventories	396			476
Drilling advances	151			81
Prepaid assets and other	135			179
	3,769			3,241
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of successful efforts accounting:
Proved properties	38,569			42,693
Unproved properties and properties under development	1,810			1,969
Gathering, transmission, and processing facilities	1,363			976
Other	1,012			1,111
	42,754			46,749
Less: Accumulated depreciation, depletion, and amortization	(25,099		)	(27,882		)
	17,655			18,867
OTHER ASSETS:
Deferred charges and other	411			411
	$	21,835		$	22,519
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	583		$	585
Current debt	550			—
Other current liabilities (Note 5)	1,332			1,258
	2,465			1,843
LONG-TERM DEBT	7,933			8,544
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	948			1,710
Asset retirement obligation	1,831			2,432
Other	281			311
	3,060			4,453
COMMITMENTS AND CONTINGENCIES (Note 9)
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 414,108,944 and 412,612,102 shares issued, respectively	259			258
Paid-in capital	12,186			12,364
Accumulated deficit	(2,544		)	(3,385		)
Treasury stock, at cost, 33,171,015 and 33,172,426 shares, respectively	(2,887		)	(2,887		)
Accumulated other comprehensive loss	(3		)	(112		)
APACHE SHAREHOLDERS’ EQUITY	7,011			6,238
Noncontrolling interest	1,366			1,441
TOTAL EQUITY	8,377			7,679
	$	21,835		$	22,519

The accompanying notes to consolidated financial statements

are an integral part of this statement.

4

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY

(Unaudited)

	Common Stock		Paid-In Capital			Accumulated Deficit			Treasury Stock			Accumulated Other Comprehensive Loss			APACHE SHAREHOLDERS’ EQUITY			Noncontrolling Interest			TOTAL EQUITY
	(In millions)
BALANCE AT DECEMBER 31, 2015	$	257	$	12,619		$	(1,980	)	$	(2,889	)	$	(119	)	$	7,888		$	1,602		$	9,490
Net income (loss)	—		—			(1,223		)	—			—			(1,223		)	93			(1,130		)
Distributions to noncontrolling interest	—		—			—			—			—			—			(215		)	(215		)
Common dividends ($0.75 per share)	—		(284		)	—			—			—			(284		)	—			(284		)
Other	1		86			—			1			—			88			—			88
BALANCE AT SEPTEMBER 30, 2016	$	258	$	12,421		$	(3,203	)	$	(2,888	)	$	(119	)	$	6,469		$	1,480		$	7,949
BALANCE AT DECEMBER 31, 2016	$	258	$	12,364		$	(3,385	)	$	(2,887	)	$	(112	)	$	6,238		$	1,441		$	7,679
Net income	—		—			848			—			—			848			137			985
Distributions to noncontrolling interest	—		—			—			—			—			—			(212		)	(212		)
Common dividends ($0.75 per share)	—		(286		)	—			—			—			(286		)	—			(286		)
Other	1		108			(7		)	—			109			211			—			211
BALANCE AT SEPTEMBER 30, 2017	$	259	$	12,186		$	(2,544	)	$	(2,887	)	$	(3	)	$	7,011		$	1,366		$	8,377

The accompanying notes to consolidated financial statements

are an integral part of this statement.

5

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

These consolidated financial statements have been prepared by Apache Corporation (Apache or the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016, which contains a summary of the Company’s significant accounting policies and other disclosures.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of September 30, 2017, Apache’s significant accounting policies are consistent with those discussed in Note 1—Summary of Significant Accounting Policies of its consolidated financial statements contained in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016, with the exception of Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) 2016-09, “Improvements to Employee Share-Based Payment Accounting” and ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash” (see “Recently Adopted Accounting Pronouncements” in this Note 1 below).

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates with regard to these financial statements include the fair value determination of acquired assets and liabilities, the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, the assessment of asset retirement obligations, the estimates of fair value for long-lived assets and goodwill, and the estimate of income taxes. Actual results could differ from those estimates.

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).

Apache also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. The Company recorded no asset impairments in connection with fair value assessments in the third quarter of 2017. For the nine-month period ended September 30, 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 the first quarter of 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.

6

For the quarter ended September 30, 2016, the Company recorded asset impairments totaling $836 million in connection with fair value assessments including $355 million for proved oil and gas properties in Canada and $481 million for the impairment of the recoverable value of the PRT decommissioning asset. For the nine-month period ended September 30, 2016, the Company recorded asset impairments totaling $1.0 billion in connection with fair value assessments including $423 million for proved oil and gas properties in the U.S. and Canada, $481 million for the impairment of the recoverable value of the PRT decommissioning asset, and $105 million for the impairment of certain gas gathering, transmission, and processing (GTP) assets, which were written down to their fair values of $175 million.

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 of exploratory wells and development costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.

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

When circumstances indicate that 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.

7

The following table represents non-cash impairments of the carrying value of the Company’s proved and unproved property and equipment for the third quarters and first nine months of 2017 and 2016:

	Quarter Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(In millions)
Oil and Gas Property:
Proved	$	—	$	355	$	—	$	423
Unproved	160		114		214		222

Proved properties impaired during the second and third quarters of 2016 had aggregate fair values of $143 million and $163 million, respectively.

On the statement of consolidated operations, unproved impairments are recorded in exploration expense, and proved impairments are recorded in impairments.

Recently Adopted Accounting Pronouncements

Stock Compensation

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.

Restricted Cash

In November 2016, the 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. Other than the change in presentation within the statement of consolidated cash flows, the adoption of ASU 2016-18 did not have an impact on the Company’s consolidated financial statements.

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The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheet to the amounts shown in the statement of consolidated cash flows:

	September 30, 2017		December 31, 2016
	(In millions)
Cash and cash equivalents	$	1,846	$	1,377
Restricted cash	96		—
Total cash, cash equivalents, and restricted cash shown in the statement of consolidated cash flows	$	1,942	$	1,377

For information regarding the restricted cash balance, please refer to Note 2—Acquisitions and Divestitures.

New Pronouncements Issued But Not Yet Adopted

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 U.S. 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. As part of the assessment to date, the Company has formed an implementation work team and is continuing to evaluate contracts to determine the impact this ASU will have on its consolidated financial statements. 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.

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 standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Company continues to make progress on evaluating the accounting implications of this ASU and its assessment of contracts with customers is largely complete. Based on the Company’s evaluation to date, it does not expect the adoption of this ASU to have a material impact on net earnings, however, the Company is analyzing whether the classification of certain items in revenue and expense will be impacted. The Company continues to evaluate the disclosure requirements, develop accounting policies, and assess changes to the relevant business processes and the control activities within them as a result of the provisions of this ASU. The Company will adopt the new standard on January 1, 2018, utilizing the modified retrospective approach.

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2. 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. The Company has classified $96 million of proceeds as “Restricted cash” on the Company’s consolidated balance sheet, pending the Alberta Energy Regulator’s clearance of the transfer of Provost area licenses from ACL to the buyer.

A summary of the assets and liabilities at closing of the August transactions is detailed below:

	(In millions)
ASSETS
Current assets	$	110
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 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 $12 million and $141 million for the third quarter and first nine months of 2017, respectively, compared to pretax losses of $483 million and $644 million, respectively, for the comparable periods in 2016.

U.S. Divestitures

During the first nine months of 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 $783 million, subject to customary closing adjustments. A refundable deposit of $40 million was received in the fourth quarter of 2016 in connection with certain of these transactions. The Company recognized gains of approximately $594 million during the first nine months of 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 Scottish Area Gas Evacuation system (SAGE) and its 60.56 percent interest in the Beryl pipeline in the North Sea to Ancala Midstream Acquisitions Limited (Ancala). The transaction is subject to regulatory and third-party approvals, which are ongoing in 2017. The Company received a refundable deposit in connection with this transaction, which is recorded in “Other current liabilities” on the consolidated balance sheet. The refundable deposit was $149 million as of September 30, 2017.

Leasehold and Property Acquisitions

During the third quarter and first nine months of 2017, Apache purchased $75 million and $142 million, respectively, of leasehold and property acquisitions primarily in its North America onshore regions.

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2016 Activity

Leasehold and Property Acquisitions

During the third quarter and first nine months of 2016, Apache purchased $51 million and $169 million, respectively, of leasehold and property acquisitions primarily in its North America onshore regions and Egypt.

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 Quarter Ended September 30,					For the Nine Months Ended September 30,
	2017		2016			2017		2016
	(In millions)
Loss from Australia divestiture	$	—	$	(23	)	$	—	$	(23	)
Loss from Argentina divestiture	—		(10		)	—		(10		)
Loss from discontinued operations, net of tax	$	—	$	(33	)	$	—	$	(33	)

Transaction, Reorganization, and Separation

During the third quarter and first nine months of 2017, Apache recorded $20 million and $14 million, respectively, in expense related to asset divestitures in the U.S. and Canada and employee separation. During the third quarter and first nine months of 2016, Apache recorded $12 million and $36 million, respectively, in expense related to various asset divestitures, company reorganization, and employee separation.

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3.   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. The Company’s derivatives are not designated as cash flow hedges, therefore, changes in fair value are recognized currently in earnings.

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 September 30, 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 September 30, 2017, Apache had the following open crude oil derivative positions:

		Put Options(1)(2)
Production Period	Settlement Index	Mbbls	Weighted Average Strike Price
October—December 2017	NYMEX WTI	8,464	$50.00
October—December 2017	Dated Brent	7,636	$51.00

(1) The remaining unamortized premium paid as of September 30, 2017, was $50 million.

(2) Subsequent to September 30, 2017, Apache entered into put option contracts settling against Dated Brent totaling 3,650 Mbbls with a strike price of $50 for the calendar year 2018.

		Fixed-Price Swaps		Collars(3)			Call Options(4)
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	—	—	6,023	$45.00	$57.02	6,023	$60.00

(3) Subsequent to September 30, 2017, Apache entered into crude oil contracts settling against NYMEX WTI totaling 730 Mbbls with a floor and ceiling of $45.00 and $56.90, respectively, for the calendar year 2018.

(4) The remaining unamortized premium paid as of September 30, 2017, was $9 million.

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As of September 30, 2017, Apache had the following open natural gas derivative positions:

		Fixed-Price Swaps(1)
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Fixed Price
October—December 2017	NYMEX Henry Hub	4,370	$3.32
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	18,400	$2.97

(1) Subsequent to September 30, 2017, Apache entered into fixed-price natural gas swaps settling against NYMEX Henry Hub totaling 15,180,000 MMBtu with a weighted average fixed-price of $2.95 for the second half of 2018.

As of September 30, 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)
September 30, 2017
Assets:
Commodity Derivative Instruments	$	—	$	24	$	—	$	24	$	(7	)	$	17
Liabilities:
Commodity Derivative Instruments	—		7		—		7		(7		)	—
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.

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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:

	September 30, 2017		December 31, 2016
	(In millions)
Current Assets: Prepaid assets and other	$	13	$	—
Other Assets: Deferred charges and other	4		—
Total Assets	$	17	$	—

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 Quarter Ended September 30,					For the Nine Months Ended September 30,
	2017			2016		2017			2016
	(In millions)
Realized gain (loss):
Derivative settlements, realized gain	$	23		$	—	$	23		$	—
Amortization of put premium, realized loss	(50		)	—		(50		)	—
Unrealized loss	(83		)	—		(42		)	—
Derivative instrument losses, net	$	(110	)	$	—	$	(69	)	$	—

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 a component of “Unrealized derivative instrument losses, net” in “Adjustments to reconcile net income (loss) to net cash provided by operating activities.”

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4.   CAPITALIZED EXPLORATORY WELL COSTS

The Company’s capitalized exploratory well costs were $369 million and $264 million at September 30, 2017 and December 31, 2016, respectively. The increase is primarily attributable to additional drilling activities in the U.S. during the period, partially offset by successful transfers and dry hole write-offs. No suspended exploratory well costs previously capitalized for greater than one year at December 31, 2016 were charged to dry hole expense during the nine months ended September 30, 2017. 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.

5. OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities as of September 30, 2017 and December 31, 2016:

	September 30, 2017		December 31, 2016
	(In millions)
Accrued operating expenses	$	73	$	110
Accrued exploration and development	691		463
Accrued compensation and benefits	99		201
Accrued interest	108		145
Accrued income taxes	68		22
Current asset retirement obligation	35		66
Refundable deposits	149		174
Other	109		77
Total other current liabilities	$	1,332	$	1,258

6. ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the nine-month period ended September 30, 2017:

	(In millions)
Asset retirement obligation at December 31, 2016	$	2,498
Liabilities incurred	39
Liabilities divested	(810		)
Liabilities settled	(30		)
Accretion expense	103
Revisions in estimated liabilities	66
Asset retirement obligation at September 30, 2017	1,866
Less current portion	35
Asset retirement obligation, long-term	$	1,831

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7. INCOME TAXES

The Company estimates its annual effective income tax rate for continuing operations in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments of the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur.

In August 2017, Apache completed the sale of ACL. For more information regarding this transaction, please refer to Note 2—Acquisitions and Divestitures. As a result of this transaction, Apache recorded a deferred tax asset associated with its realizable capital loss on the sale of ACL, and a decrease in the Company’s deferred tax liability associated with its investment in foreign subsidiaries. In the third and second quarters of 2017, the Company recorded a $2 million deferred income tax expense and a $674 million deferred income tax benefit, respectively, in connection with these transactions.

Apache’s third quarter of 2017 effective income tax rate was primarily impacted by gains on the sale of oil and gas properties and a $30 million current tax benefit associated with U.S. federal income tax credits. On September 15, 2016, U.K. Finance Act 2016 received Royal Assent. Under the enacted legislation, the corporate income tax rate on North Sea oil and gas profits was reduced from 50 percent to 40 percent effective January 1, 2016. As a result of the enacted legislation, in the third quarter of 2016 the Company recorded a deferred tax benefit of $235 million related to the remeasurement of the Company’s December 31, 2015 U.K. deferred income tax liability.

Apache’s 2017 year-to-date effective income tax rate is primarily impacted by the decrease in deferred taxes associated with its investments in foreign subsidiaries, gains on the sale of oil and gas properties, non-cash impairments of the Company’s PRT decommissioning asset, and the current tax benefit associated with U.S. federal income tax credits. Apache’s 2016 year-to-date effective income tax rate was primarily impacted by non-cash impairments of the carrying value of the Company’s oil and gas properties, non-cash impairments of the Company’s PRT decommissioning asset, the impact of the change in U.K. statutory income tax rate, and an increase in the amount of valuation allowances on U.S. and Canadian deferred tax assets.

Apache and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. In April 2017, the Internal Revenue Service (IRS) began their audit of the Company’s 2014 income tax year. The Company is also under audit in various states and in most of the Company’s foreign jurisdictions as part of its normal course of business.

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8. DEBT AND FINANCING COSTS

The following table presents the carrying amounts and estimated fair values of the Company’s outstanding debt as of September 30, 2017 and December 31, 2016:

	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Commercial paper and committed bank facilities	$	—	$	—	$	—	$	—
Notes and debentures	8,483		9,094		8,544		9,183
Total Debt	$	8,483	$	9,094	$	8,544	$	9,183

The Company’s debt is recorded at the carrying amount, net of related unamortized discount and debt issuance costs, on its consolidated balance sheet. When recorded, the carrying amount of the Company’s commercial paper, committed bank facilities, and uncommitted bank lines approximates 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 notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

The following table presents the carrying value of the Company’s debt as of September 30, 2017 and December 31, 2016:

	September 30, 2017			December 31, 2016
	(In millions)
Debt before unamortized discount and debt issuance costs	$	8,580		$	8,650
Unamortized discount	(48		)	(50		)
Debt issuance costs	(49		)	(56		)
Total debt	8,483			8,544
Current maturities	(550		)	—
Long-term debt	$	7,933		$	8,544

As of September 30, 2017, current debt included $150 million of 7.0% senior notes due February 1, 2018 and $400 million of 6.9% senior notes due September 15, 2018.

As of September 30, 2017, the Company had a revolving credit facility that matures in June 2020, subject to Apache’s twoone-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 $3.5 billion commercial paper program. The commercial paper program, which is subject to market availability, facilitates Apache borrowing funds for up to 270 days at competitive interest rates. As of September 30, 2017, the Company had no commercial paper or borrowings under committed bank facilities or uncommitted bank lines outstanding.

As of September 30, 2017, the Company had a letter of credit facility, which provides for £900 million in commitments and rights to increase commitments to £1.075 billion. This facility matures in February 2020. The facility is available for letters of credit and loans 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. As of September 30, 2017, three letters of credit aggregating approximately £147.5 million and no borrowings were outstanding under this facility.

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, the Company 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.

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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, the Company assumed the obligations of Apache Finance Canada Corporation (AFCC) in respect of $300 million7.75% 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 million7.75% 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.

Financing Costs, Net

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

	For the Quarter Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(In millions)
Interest expense	$	113		$	116		$	344		$	348
Amortization of deferred loan costs	3			2			7			5
Capitalized interest	(12		)	(13		)	(39		)	(36		)
Loss on extinguishment of debt	—			—			1			—
Interest income	(3		)	(3		)	(13		)	(6		)
Financing costs, net	$	101		$	102		$	300		$	311

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9. 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. As of September 30, 2017, 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.

For additional information on each of the Legal Matters described below, please see Note 10—Commitments and Contingencies to the consolidated financial statements contained in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

Argentine Environmental Claims and Argentina Tariff

No material change in the status of the YPF Sociedad Anónima and Pioneer Natural Resources Company indemnities matters has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

Louisiana Restoration

As more fully described in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016, numerous surface owners have filed claims or sent demand letters to various oil and gas companies, including Apache, claiming that, under either express or implied lease terms or Louisiana law, the companies are liable for damage measured by the cost of restoration of leased premises to their original condition as well as damages for contamination and cleanup.

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. On October 30, 2017, the United States Supreme Court denied review and declined to consider the plaintiff’s Petition of Certiorari.

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.

No other material change in the status of these matters has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

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Apollo Exploration Lawsuit

In a fourth amended petition filed on March 21, 2016, in a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs have reduced their alleged damages to approximately $500 million (having previously claimed in excess of $1.1 billion) relating to certain purchase and sale agreements, mineral leases, and areas of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The Court recently granted two of Apache’s motions for summary judgment further limiting the plaintiffs’ theories and potential damages. Apache believes that plaintiffs’ claims lack merit, and further that plaintiffs’ alleged damages, even as amended, are grossly inflated. Apache will vigorously oppose the claims. No other material change in the status of these matters has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

Escheat Audits

There has been no material change with respect to the review of the books and records of the Company and its subsidiaries and related entities by the State of Delaware, Department of Finance (Unclaimed Property), to determine compliance with the Delaware Escheat Laws, since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

Environmental Matters

As of September 30, 2017, the Company had an undiscounted reserve for environmental remediation of approximately $4 million. The Company is not aware of any environmental claims existing as of September 30, 2017, that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

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.

In addition to the matters for which the Company has already accrued, 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. Apache believes that the claims made against it are baseless and intends to vigorously defend these lawsuits.

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 Viraciti Energy Pty Ltd, which has since been renamed Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. By letter dated June 6, 2016, Quadrant provided the Company with a placeholder notice of claim under the SPA concerning tax and other issues totaling approximately $200 million in the aggregate. The Company believes that these claims lack merit and intends to vigorously defend against them. Moreover, on September 22, 2017, subsidiaries of the Company filed suit against Quadrant for breaching the SPA and wrongfully withholding tax refunds owed under the SPA. This claim totals approximately $80 million AUD.

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10. CAPITAL STOCK

Net Income (Loss) per Common Share

A reconciliation of the components of basic and diluted net income (loss) per common share for the quarters and nine months ended September 30, 2017 and 2016, is presented in the table below.

	For the Quarter Ended September 30,
	2017					2016
	Income		Shares	Per Share		Loss			Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) from continuing operations	$	63	381	$	0.16	$	(574	)	380	$	(1.51	)
Loss from discontinued operations	—		381	—		(33		)	380	(0.09		)
Income (loss) attributable to common stock	$	63	381	$	0.16	$	(607	)	380	$	(1.60	)
Effect of Dilutive Securities:
Stock options and other	$	—	2	$	—	$	—		—	$	—
Diluted:
Income (loss) from continuing operations	$	63	383	$	0.16	$	(574	)	380	$	(1.51	)
Loss from discontinued operations	—		383	—		(33		)	380	(0.09		)
Income (loss) attributable to common stock	$	63	383	$	0.16	$	(607	)	380	$	(1.60	)

	For the Nine Months Ended September 30,
	2017						2016
	Income		Shares	Per Share			Loss			Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) from continuing operations	$	848	381	$	2.23		$	(1,190	)	379	$	(3.14	)
Loss from discontinued operations	—		381	—			(33		)	379	(0.08		)
Income (loss) attributable to common stock	$	848	381	$	2.23		$	(1,223	)	379	$	(3.22	)
Effect of Dilutive Securities:
Stock options and other	$	—	2	$	(0.01	)	$	—		—	$	—
Diluted:
Income (loss) from continuing operations	$	848	383	$	2.22		$	(1,190	)	379	$	(3.14	)
Loss from discontinued operations	—		383	—			(33		)	379	(0.08		)
Income (loss) attributable to common stock	$	848	383	$	2.22		$	(1,223	)	379	$	(3.22	)

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 8.4 million and 4.7 million for the quarters ended September 30, 2017 and 2016, respectively, and 7.5 million and 6.5 million for the nine months ended September 30, 2017 and 2016, respectively.

Common Stock Dividends

For each of the quarters ended September 30, 2017, and 2016, Apache paid $95 million in dividends on its common stock. For the nine months ended September 30, 2017 and 2016, the Company paid $285 million and $284 million, 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 negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through September 30, 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.

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11. ACCUMULATED OTHER COMPREHENSIVE LOSS

The following table describes changes to the Company’s accumulated other comprehensive loss by component for the nine-month period ended September 30, 2017:

	Currency Translation Adjustment			Pension and Postretirement Benefit Plan			Total
	(In millions)
Accumulated other comprehensive loss at December 31, 2016	$	(109	)	$	(3	)	$	(112	)
Currency translation adjustment divested(1)	109			—			109
Accumulated other comprehensive loss at September 30, 2017	$	—		$	(3	)	$	(3	)

(1) Currency translation adjustments resulting from translating the 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.

12. 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 September 30, 2017, the Company had production in three reporting segments: the United States, Egypt, and offshore the United Kingdom 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. Financial information for each area is presented below:

	United States			Canada(1)			Egypt(2)		North Sea		Other International			Total
	(In millions)
For the Quarter Ended September 30, 2017
Oil and Gas Production Revenues	$	550		$	36		$	543	$	260	$	—		$	1,389
Operating Income (Loss)(3)	$	(114	)	$	(1	)	$	226	$	16	$	(1	)	$	126
Other Income (Expense):
Gain on divestitures, net														296
Derivative instrument losses, net														(110		)
General and administrative														(98		)
Transaction, reorganization, and separation														(20		)
Financing costs, net														(101		)
Income Before Income Taxes														$	93
For the Nine Months Ended September 30, 2017
Oil and Gas Production Revenues	$	1,593		$	231		$	1,655	$	768	$	—		$	4,247
Operating Income (Loss)(3)	$	(71	)	$	(33	)	$	740	$	59	$	(24	)	$	671
Other Income (Expense):
Gain on divestitures, net														616
Derivative instrument losses, net														(69		)
Other														43
General and administrative														(307		)
Transaction, reorganization, and separation														(14		)
Financing costs, net														(300		)
Income Before Income Taxes														$	640
Total Assets	$	13,105		$	—		$	4,906	$	3,770	$	54		$	21,835

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	United States			Canada(1)			Egypt(2)		North Sea			Other International			Total
	(In millions)
For the Quarter Ended September 30, 2016
Oil and Gas Production Revenues	$	524		$	87		$	581	$	247		$	—		$	1,439
Operating Income (Loss)(4)	$	(17	)	$	(466	)	$	263	$	(455	)	$	(13	)	$	(688	)
Other Income (Expense):
Gain on divestitures, net															5
Other															(6		)
General and administrative															(102		)
Transaction, reorganization, and separation															(12		)
Financing costs, net															(102		)
Loss From Continuing Operations Before Income Taxes															$	(905	)
For the Nine Months Ended September 30, 2016
Oil and Gas Production Revenues	$	1,453		$	243		$	1,515	$	701		$	—		$	3,912
Operating Income (Loss)(4)	$	(283	)	$	(586	)	$	525	$	(557	)	$	(13	)	$	(914	)
Other Income (Expense):
Gain on divestitures, net															21
Other															(30		)
General and administrative															(298		)
Transaction, reorganization, and separation															(36		)
Financing costs, net															(311		)
Loss From Continuing Operations Before Income Taxes															$	(1,568	)
Total Assets	$	12,299		$	1,630		$	5,320	$	3,851		$	49		$	23,149

(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.

(3) Operating income (loss) consists of oil and gas production revenues less lease operating expenses, gathering and transportation costs, taxes other than income, exploration costs, depreciation, depletion, and amortization, asset retirement obligation accretion, and impairments. The operating income (loss) of U.S. includes leasehold impairments totaling $160 million for the third quarter of 2017. The operating income (loss) of U.S., Canada, and North Sea includes leasehold and other asset impairments totaling $212 million, $2 million, and $8 million, respectively, for the first nine months of 2017.

(4) The operating income (loss) of U.S., Canada, and North Sea includes leasehold, property, and other asset impairments totaling $46 million, $423 million, and $481 million, respectively, for the third quarter of 2016. The operating income (loss) of U.S., Canada, and North Sea includes leasehold, property, and other asset impairments totaling $212 million, $433 million, and $586 million, respectively, for the first nine months of 2016.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion relates to Apache Corporation and its consolidated subsidiaries and should be read in conjunction with the Company’s consolidated financial statements and accompanying notes included under Part I, Item 1, “Financial Statements” of this Quarterly Report on Form 10-Q, as well as the Company’s consolidated financial statements, accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

Overview

Apache Corporation, a Delaware corporation formed in 1954, 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 United Kingdom (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.

During the quarter, Apache completed its strategic exit from Canada that was enabled by its Alpine High discovery. We believe this portfolio shift is a significant upgrade to the Company’s portfolio of assets, as the Alpine High discovery offers higher returns and significantly more long-term growth potential. Apache’s U.S. assets are complemented by its international assets in Egypt and the North Sea, each of which adds to the Company’s deep inventory of exploration and development opportunities and generate cash flows in excess of current capital investments, facilitating the Company’s ability to develop Alpine High while maintaining financial flexibility.

Apache reported third-quarter net income of $63 million, or $0.16 per common share, compared to a loss of $607 million, or $1.60 per common share, in the third quarter of 2016. The increase in net income compared to the prior-year quarter is primarily the result of gains on divestitures in the current-year quarter, as well as lower impairment charges in the current period. Revenue gains from significant increases in realized commodity prices partially mitigated the impact of production declines.

Daily production in the third quarter of 2017 averaged 448 thousand barrels of oil equivalent per day (Mboe/d), a decrease of 14 percent from the comparative prior-year quarter driven by the sale of the Company’s Canadian operations. Excluding production from Canada, Apache’s worldwide equivalent daily production decreased 8 percent due to natural decline. The production decline was driven by strategic decisions to curtail capital investments in the two preceding years in order to allow costs to re-align with the lower commodity price environment and to allocate a significant portion of this year’s capital investments to the development of the Alpine High field and infrastructure.

During the first nine months of 2017, the Company generated $1.8 billion in cash from operating activities, an 8 percent increase from the comparative prior-year period, and $1.4 billion of cash proceeds from non-core asset divestments. Apache exited the quarter with $1.9 billion of cash, cash equivalents, and restricted cash, an increase of $565 million from year-end 2016. In addition, the Company reduced debt from year-end levels and has $3.5 billion of available committed borrowing capacity. In response to continued commodity price volatility, the Company entered commodity derivatives to secure deployment of high priority investments without compromising its financial strength or flexibility. We continuously monitor changes in our operating environment and have the ability, due to our dynamic capital allocation process, to adjust our capital investment program to levels that maximize value for our shareholders over the long-term.

Operating Highlights

Significant operating activities for the quarter include the following:

North America

• North America equivalent production decreased 17 percent for the quarter relative to the 2016 period, reflecting Apache’s exit from Canada. Excluding Canada, Apache’s North America equivalent production decreased 6 percent, in line with the Company’s expectations given the significant reduction in capital investments over the preceding two years and the allocation of a significant portion of our 2017 capital investments to infrastructure at Alpine High.

• Third-quarter equivalent production from the Permian Basin region, which accounts for more than half of Apache’s total North American production, increased1 percent from the third quarter of 2016, which was driven by our Alpine High discovery and strong performance in the Midland Basin. Third-quarter production increased 11 percent from the prior sequential quarter, a reflection of increased activity and the startup of Alpine High production.

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• Drilling and infrastructure development activities continue at Alpine High; specifically:

◦ First production from the Alpine High play was achieved in early May 2017. Net production averaged approximately 13.3 Mboe/d during the third quarter, and we anticipate production of 25 Mboe/d by the end of the year.

◦ During the first nine months of 2017, Apache invested $389 million in midstream facilities at Alpine High, with development ongoing.

◦ Three processing facilities are currently operating with a combined gross inlet capacity of 200 million cubic feet of natural gas per day (MMcf/d). Infrastructure buildout for two additional central processing facilities has been slightly delayed by a quarter as a result of Hurricane Harvey-related damage to Houston-area manufacturing facilities that are providing key infrastructure equipment.

• In 2017, Apache announced three separate transactions to sell its subsidiary Apache Canada Ltd. (ACL) and exit its Canadian operations. The sale of assets at Midale and House Mountain, located in Saskatchewan and Alberta, closed on June 30, 2017 for approximately $228 million of cash proceeds. The two remaining transactions to sell ACL and Provost assets in Alberta closed in August 2017 for approximately $478 million of cash proceeds. The sale of Apache’s Canadian operations further streamlines its portfolio, enabling the Company to allocate a higher percentage of capital to the Permian Basin.

International

• The Egypt region net equivalent production decreased12 percent from the third quarter of 2016 despite a decline of only 3 percent in gross production, a function of the Company’s production-sharing contracts. In August 2017, the Company received final award of two new concessions totaling 1.6 million net acres. At the end of September 2017, the Company began acquiring high resolution 3D seismic in the West Kalabsha concession and plans to expand this seismic activity to cover the majority of its acreage.

• The North Sea region average daily production decreased5 percent from the third quarter of 2016, primarily the result of extended turnaround activities in the third quarter of 2017 and natural well decline. The Callater discovery, which came online in late May 2017, has two wells producing with a third offset well expected to commence production later in the fourth quarter of 2017.

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Results of Operations

Oil and Gas Revenues

The table below presents revenues by geographic region and each region’s percent contribution to revenues for 2017 and 2016.

	For the Quarter Ended September 30,								For the Nine Months Ended September 30,
	2017				2016				2017				2016
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution
	($ in millions)
Total Oil Revenues:
United States	$	381	36	%	$	377	34	%	$	1,133	35	%	$	1,099	36	%
Canada	14		1	%	47		4	%	110		3	%	132		4	%
North America	395		37	%	424		38	%	1,243		38	%	1,231		40	%
Egypt (1)	442		41	%	476		43	%	1,351		41	%	1,209		40	%
North Sea	233		22	%	217		19	%	698		21	%	617		20	%
International (1)	675		63	%	693		62	%	2,049		62	%	1,826		60	%
Total (1)	$	1,070	100	%	$	1,117	100	%	$	3,292	100	%	$	3,057	100	%
Total Natural Gas Revenues:
United States	$	97	41	%	$	98	37	%	$	266	37	%	$	222	32	%
Canada	19		8	%	36		14	%	104		14	%	100		14	%
North America	116		49	%	134		51	%	370		51	%	322		46	%
Egypt (1)	98		41	%	103		39	%	295		41	%	298		43	%
North Sea	24		10	%	26		10	%	61		8	%	75		11	%
International (1)	122		51	%	129		49	%	356		49	%	373		54	%
Total (1)	$	238	100	%	$	263	100	%	$	726	100	%	$	695	100	%
Total Natural Gas Liquids (NGL) Revenues:
United States	$	72	89	%	$	49	83	%	$	194	85	%	$	132	82	%
Canada	3		4	%	4		7	%	17		7	%	11		7	%
North America	75		93	%	53		90	%	211		92	%	143		89	%
Egypt (1)	3		4	%	2		3	%	9		4	%	8		5	%
North Sea	3		3	%	4		7	%	9		4	%	9		6	%
International (1)	6		7	%	6		10	%	18		8	%	17		11	%
Total (1)	$	81	100	%	$	59	100	%	$	229	100	%	$	160	100	%
Total Oil and Gas Revenues:
United States	$	550	40	%	$	524	36	%	$	1,593	38	%	$	1,453	37	%
Canada	36		2	%	87		6	%	231		5	%	243		6	%
North America	586		42	%	611		42	%	1,824		43	%	1,696		43	%
Egypt (1)	543		39	%	581		41	%	1,655		39	%	1,515		39	%
North Sea	260		19	%	247		17	%	768		18	%	701		18	%
International (1)	803		58	%	828		58	%	2,423		57	%	2,216		57	%
Total (1)	$	1,389	100	%	$	1,439	100	%	$	4,247	100	%	$	3,912	100	%

(1) Includes revenues attributable to a noncontrolling interest in Egypt.

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Production

The table below presents the third-quarter and year-to-date 2017 and 2016 production and the relative increase or decrease from the prior period.

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2017	Increase (Decrease)		2016	2017	Increase (Decrease)		2016
Oil Volume – b/d
United States	90,883	(8	)%	98,269	89,228	(17	)%	106,924
Canada	3,441	(73	)%	12,619	8,881	(33	)%	13,331
North America	94,324	(15	)%	110,888	98,109	(18	)%	120,255
Egypt(1)(2)	93,749	(15	)%	110,809	97,447	(7	)%	105,118
North Sea	49,945	2	%	49,192	49,274	(11	)%	55,071
International	143,694	(10	)%	160,001	146,721	(8	)%	160,189
Total	238,018	(12	)%	270,889	244,830	(13	)%	280,444
Natural Gas Volume – Mcf/d
United States	404,486	2	%	395,062	378,625	(6	)%	404,282
Canada	107,524	(54	)%	233,635	175,787	(29	)%	248,912
North America	512,010	(19	)%	628,697	554,412	(15	)%	653,194
Egypt(1)(2)	378,426	(7	)%	405,863	389,533	(4	)%	403,832
North Sea	50,057	(28	)%	69,509	42,800	(36	)%	66,884
International	428,483	(10	)%	475,372	432,333	(8	)%	470,716
Total	940,493	(15	)%	1,104,069	986,745	(12	)%	1,123,910
NGL Volume – b/d
United States	49,149	(13	)%	56,355	48,063	(14	)%	55,897
Canada	2,183	(64	)%	6,039	3,780	(36	)%	5,879
North America	51,332	(18	)%	62,394	51,843	(16	)%	61,776
Egypt(1)(2)	916	(19	)%	1,124	917	(18	)%	1,120
North Sea	1,219	(28	)%	1,697	1,044	(33	)%	1,557
International	2,135	(24	)%	2,821	1,961	(27	)%	2,677
Total	53,467	(18	)%	65,215	53,804	(17	)%	64,453
BOE per day(3)
United States	207,447	(6	)%	220,468	200,396	(13	)%	230,202
Canada	23,544	(59	)%	57,597	41,959	(31	)%	60,695
North America	230,991	(17	)%	278,065	242,355	(17	)%	290,897
Egypt(2)	157,737	(12	)%	179,575	163,286	(6	)%	173,544
North Sea(4)	59,507	(5	)%	62,475	57,451	(15	)%	67,775
International	217,244	(10	)%	242,050	220,737	(9	)%	241,319
Total	448,235	(14	)%	520,115	463,092	(13	)%	532,216

(1) Gross oil, natural gas, and NGL production in Egypt for the third quarter and nine-month period of 2017 and 2016 were as follows:

	For the Quarter Ended September 30,		For the Nine Months Ended September 30,
	2017	2016	2017	2016
Oil (b/d)	201,151	210,755	196,781	210,939
Natural Gas (Mcf/d)	818,350	826,548	813,880	828,950
NGL (b/d)	1,526	1,853	1,514	1,918

(2) Includes production volumes per day attributable to a noncontrolling interest in Egypt for the third quarter and nine-month period of 2017 and 2016 of:

	For the Quarter Ended September 30,		For the Nine Months Ended September 30,
	2017	2016	2017	2016
Oil (b/d)	31,275	36,839	32,573	34,964
Natural Gas (Mcf/d)	126,459	135,233	130,263	134,591
NGL (b/d)	305	374	306	373

(3) The table shows production on a barrel of oil equivalent basis (boe) in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the price ratio between the two products.

(4) Average sales volumes from the North Sea were 57,207 boe/d and 65,171 boe/d for the third quarter of 2017 and 2016, respectively, and 57,963 boe/d and 67,222 boe/d for the first nine months of 2017 and 2016, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

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Pricing

The table below presents third-quarter and year-to-date 2017 and 2016 pricing and the relative increase or decrease from the prior period.

	For the Quarter Ended September 30,						For the Nine Months Ended September 30,
	2017		Increase (Decrease)		2016		2017		Increase (Decrease)		2016
Average Oil Price - Per barrel
United States	$	45.68	9	%	$	41.83	$	46.54	24	%	$	37.53
Canada	42.23		5	%	40.17		45.25		26	%	36.04
North America	45.56		9	%	41.65		46.42		24	%	37.36
Egypt	51.23		10	%	46.54		50.78		21	%	41.97
North Sea	53.11		17	%	45.47		51.35		24	%	41.28
International	51.87		12	%	46.20		50.97		22	%	41.74
Total	49.34		11	%	44.35		49.15		23	%	39.86
Average Natural Gas Price - Per Mcf
United States	$	2.62	(2	)%	$	2.66	$	2.58	29	%	$	2.00
Canada	1.90		11	%	1.71		2.17		48	%	1.47
North America	2.47		7	%	2.31		2.45		36	%	1.80
Egypt	2.81		2	%	2.75		2.77		3	%	2.69
North Sea	5.27		27	%	4.14		5.27		28	%	4.12
International	3.10		5	%	2.96		3.02		4	%	2.89
Total	2.75		6	%	2.59		2.70		19	%	2.26
Average NGL Price - Per barrel
United States	$	15.77	64	%	$	9.59	$	14.75	71	%	$	8.65
Canada	15.80		159	%	6.10		16.39		148	%	6.61
North America	15.77		70	%	9.25		14.87		76	%	8.46
Egypt	36.47		30	%	28.12		35.98		31	%	27.54
North Sea	26.92		10	%	24.45		30.51		40	%	21.82
International	31.02		20	%	25.91		33.07		37	%	24.21
Total	16.38		64	%	9.97		15.53		70	%	9.11

Third-Quarter 2017 compared to Third-Quarter 2016

Crude Oil Revenues Crude oil revenues for the third quarter of 2017 totaled $1.1 billion, a $47 milliondecrease from the comparative 2016 quarter. A 12 percentdecrease in average daily production reducedthird-quarter 2017 revenues by $172 million compared to the prior-year quarter, while 11 percenthigher average realized prices increased revenues by $125 million. Crude oil accounted for 77 percent of Apache’s oil and gas production revenues and 53 percent of its equivalent production in the third quarter of 2017. Crude oil prices realized in the third quarter of 2017 averaged $49.34 per barrel, compared with $44.35 per barrel in the comparative prior-year quarter.

Worldwide oil production decreased32.9 Mb/d to 238.0 Mb/d in the third quarter of 2017 from the comparative prior-year period, primarily the result of the Canada divestitures and natural decline. Decreases were slightly offset by a 2 percent increase in the North Sea region, a result of the Callater field coming online in late May 2017.

Natural Gas Revenues Gas revenues for the third quarter of 2017 totaled $238 million, a $25 milliondecrease from the comparative 2016 quarter. A 15 percentdecrease in average daily production reducedthird-quarter revenues by $42 million compared to the prior-year quarter, while 6 percenthigher average realized prices increased revenues by $17 million. Natural gas accounted for 17 percent of Apache’s oil and gas production revenues and 35 percent of its equivalent production during the third quarter of 2017.

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Worldwide natural gas production decreased164 MMcf/d to 940 MMcf/d in the third quarter of 2017 from the comparative prior-year period, primarily the result of the Canada divestitures and maintenance activity in the North Sea. Decreases were slightly offset by a 2 percent increase in the U.S., primarily on drilling activity at Alpine High.

NGL Revenues NGL revenues for the third quarter of 2017 totaled $81 million, a $22 millionincrease from the comparative 2016 quarter. An 18 percentdecrease in average daily production reducedthird-quarter 2017 revenues by approximately $17 million, while 64 percenthigher average realized prices increased revenues by $39 million. NGLs accounted for 6 percent of Apache’s oil and gas production revenues and 12 percent of its equivalent production during the third quarter of 2017.

Worldwide production of NGLs decreased11.7 Mb/d to 53.5 Mb/d in the third quarter of 2017 from the comparative prior-year period, primarily the result of the Canada divestitures and natural decline in all regions.

Year-to-Date 2017 compared to Year-to-Date 2016

Crude Oil Revenues Crude oil revenues for the first nine months of 2017 totaled $3.3 billion, a $235 millionincrease from the comparative 2016 period. A 13 percentdecrease in average daily production reduced2017 oil revenues by $478 million compared to the prior-year period, while 23 percenthigher average realized prices increased revenues by $713 million. Crude oil accounted for 78 percent of Apache’s oil and gas production revenues and 53 percent of its equivalent production for the first nine months of 2017. Crude oil prices realized in the first nine months of 2017 averaged $49.15 per barrel, compared with $39.86 per barrel in the comparative prior-year period.

Worldwide production decreased35.6 Mb/d to 244.8 Mb/d in the first nine months of 2017 from the comparative prior-year period, primarily the result of the Canada divestitures and natural decline in all regions.

Natural Gas Revenues Gas revenues for the first nine months of 2017 totaled $726 million, a $31 millionincrease from the comparative 2016 period. A 12 percentdecrease in average daily production reduced2017 natural gas revenues by $104 million compared to the prior-year period, while 19 percenthigher average realized prices increased revenues by $135 million. Natural gas accounted for 17 percent of Apache’s oil and gas production revenues and 36 percent of its equivalent production during the first nine months of 2017.

Worldwide natural gas production decreased137 MMcf/d to 987 MMcf/d in the first nine months of 2017 from the comparative prior-year period, primarily the result of the Canada divestitures, maintenance activities in the North Sea, and natural decline in all regions.

NGL Revenues NGL revenues for the first nine months of 2017 totaled $229 million, a $69 millionincrease from the comparative 2016 period. A 17 percentdecrease in average production reduced2017 NGL revenues by $45 million compared to the prior-year period, while 70 percenthigher average realized prices increased revenues by $114 million. NGLs accounted for 5 percent of Apache’s oil and gas production revenues and 11 percent of its equivalent production for the first nine months of 2017.

Worldwide production of NGLs decreased10.6 Mb/d to 53.8 Mb/d in the first nine months of 2017 from the comparative prior-year period, primarily the result of the Canada divestitures and natural decline in all regions.

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Operating Expenses

The table below presents a comparison of Apache’s expenses on an absolute dollar basis and a boe basis. Apache’s discussion may reference expenses on a boe basis, on an absolute dollar basis or both, depending on their relevance. Operating expenses include costs attributable to a noncontrolling interest in Egypt.

	For the Quarter Ended September 30,								For the Nine Months Ended September 30,
	2017		2016		2017		2016		2017		2016		2017		2016
	(In millions)				(Per boe)				(In millions)				(Per boe)
Lease operating expenses(1)	$	358	$	382	$	8.74	$	7.94	$	1,066	$	1,119	$	8.42	$	7.68
Gathering and transportation(1)	39		51		0.91		1.08		144		155		1.13		1.06
Taxes other than income	46		9		1.12		0.19		117		85		0.93		0.58
Exploration	231		161		5.60		3.36		431		347		3.41		2.38
General and administrative	98		102		2.39		2.13		307		298		2.43		2.04
Transaction, reorganization, and separation	20		12		0.48		0.25		14		36		0.11		0.24
Depreciation, depletion, and amortization:
Oil and gas property and equipment(1)	524		610		12.76		12.67		1,598		1,875		12.63		12.87
Other assets	35		38		0.83		0.79		109		120		0.86		0.82
Asset retirement obligation accretion	30		40		0.75		0.83		103		116		0.82		0.79
Impairments	—		836		—		17.47		8		1,009		0.06		6.92
Financing costs, net	101		102		2.45		2.13		300		311		2.38		2.13

(1) For expenses impacted by the timing of 2017 liftings in the North Sea, per-boe calculations are based on sales volumes rather than production volumes.

Lease Operating Expenses (LOE) LOE decreased$24 million, or 6 percent, for the third quarter of 2017, and decreased$53 million, or 5 percent for the first nine months of 2017, on an absolute dollar basis relative to the comparable periods of 2016. On a per-unit basis, LOE increased10 percent to $8.74 per boe for the third quarter of 2017, and 10 percent to $8.42 per boe for the first nine months of 2017, as compared to the prior-year periods. The per-barrel increase for both comparative periods is primarily the result of a decline in production in all regions and generally rising costs commensurate with higher commodity prices.

Gathering and Transportation Gathering and transportation costs totaled $39 million and $144 million in the third quarter and first nine months of 2017, respectively, a decrease of $12 million from the third quarter of 2016 and a decrease of $11 million from the first nine months of 2016. The decrease was directly related to the Canadian divestitures.

Taxes other than Income Taxes other than income totaled $46 million and $117 million for the third quarter and first nine months of 2017, respectively, an increase of $37 million and $32 million from the third quarter and first nine months of 2016, respectively. Third-quarter 2017 expense consists primarily of severance and ad valorem taxes, which combined increased $4 million on higher commodity prices during the third quarter compared to the prior year quarter. For the first nine months of 2017, severance tax expense and ad valorem tax expense increased $12 million and $5 million, respectively, compared to the first nine months of 2016. In addition, in the third quarter and first nine months of 2016, Apache recognized a $33 million benefit related to the U.K. Petroleum Revenue Tax (PRT). The U.K. PRT rate, historically assessed on qualifying fields in the U.K. North Sea, was reduced to zero during 2016.

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Exploration Expense Exploration expense includes unproved leasehold impairments, exploration dry hole expense, geological and geophysical expenses, and the costs of maintaining and retaining unproved leasehold properties. Exploration expenses in the third quarter and first nine months of 2017increased$70 million and $84 million, respectively, compared to the prior-year periods.

The following table presents a summary of exploration expense:

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2017		2016		2017		2016
	(In millions)
Unproved leasehold impairments	$	160	$	114	$	214	$	222
Dry hole expense	38		7		136		38
Geological and geophysical expense	12		21		24		30
Exploration overhead and other	21		19		57		57
	$	231	$	161	$	431	$	347

Unproved leasehold impairments in the third quarter of 2017increased$46 million compared to the third quarter of 2016, primarily relate to legacy acreage and a reallocation of capital budgets in the U.S. For the first nine months of 2017, unproved leasehold impairments decreased$8 million compared to the prior-year period, primarily a result of stabilizing commodity and leasehold prices. Dry hole expense increased$31 million and $98 million for the third quarter and first nine months of 2017, respectively, from the comparative prior-year periods primarily related to unsuccessful international offshore exploration.

General and Administrative (G&A) Expenses G&A expense for the third quarter of 2017 was $4 millionlower than the third quarter of 2016. For the first nine months of 2017, G&A expense increased$9 million compared to the prior-year period, primarily related to non-cash stock-based compensation expense and other corporate costs.

Transaction, Reorganization, and Separation (TRS) Costs The Company recorded TRS expense of $20 million and $14 million for the third quarter and first nine months of 2017, respectively, related to asset divestitures in the U.S. and Canada and employee separation. The Company recorded TRS expense of $12 million and $36 million in the third quarter and first nine months of 2016, respectively, related to various asset divestitures, company reorganization, and employee separation.

Depreciation, Depletion, and Amortization (DD&A) Oil and gas property DD&A expense of $524 million in the third quarter of 2017decreased$86 million compared to the third quarter of 2016. For the first nine months of 2017, oil and gas property DD&A expense decreased$277 million compared to the prior-year period. The Company’s oil and gas property DD&A rate increased$0.09 per boe and decreased$0.24 per boe in the third quarter and first nine months of 2017, respectively, compared to the comparable prior-year periods. The primary factor driving lower absolute dollar expense was a decrease in production volumes from the comparative prior-year periods.

Impairments The Company did not record any asset impairments in connection with fair value assessments in the third quarter of 2017. During the first quarter of 2017, the Company recorded asset impairments in connection with fair value assessments totaling $8 million for a U.K. PRT decommissioning asset that is no longer expected to be realizable from future abandonment activities in the North Sea. The Company recorded $836 million and $1.0 billion of impairments in connection with fair value assessments in the third quarter and first nine months of 2016, respectively. For more information regarding asset impairments, please refer to “Fair Value Measurements” within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q.

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Financing Costs, Net Financing costs incurred during the period comprised the following:

	For the Quarter Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(In millions)
Interest expense	$	113		$	116		$	344		$	348
Amortization of deferred loan costs	3			2			7			5
Capitalized interest	(12		)	(13		)	(39		)	(36		)
Loss on extinguishment of debt	—			—			1			—
Interest income	(3		)	(3		)	(13		)	(6		)
Financing costs, net	$	101		$	102		$	300		$	311

Net financing costs decreased$1 million and $11 million in the third quarter and first nine months of 2017, respectively. The $11 million decrease in the first nine months of 2017 was primarily the result of higher capitalized interest and interest income.

Provision for Income Taxes The Company estimates its annual effective income tax rate for continuing operations in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments of the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur.

In August 2017, Apache completed the sale of ACL. For more information regarding this transaction, please refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q. As a result of this transaction, Apache recorded a deferred tax asset associated with its realizable capital loss on the sale of ACL, and a decrease in the Company’s deferred tax liability associated with its investment in foreign subsidiaries. In the third and second quarters of 2017, the Company recorded a $2 million deferred income tax expense and a $674 million deferred income tax benefit, respectively, in connection with these transactions.

Apache’s third quarter of 2017 effective income tax rate was primarily impacted by gains on the sale of oil and gas properties and a $30 million current tax benefit associated with U.S. federal income tax credits. On September 15, 2016, U.K. Finance Act 2016 received Royal Assent. Under the enacted legislation, the corporate income tax rate on North Sea oil and gas profits was reduced from 50 percent to 40 percent effective January 1, 2016. As a result of the enacted legislation, in the third quarter of 2016 the Company recorded a deferred tax benefit of $235 million related to the remeasurement of the Company’s December 31, 2015 U.K. deferred income tax liability.

Apache’s 2017 year-to-date effective income tax rate is primarily impacted by the decrease in deferred taxes associated with its investments in foreign subsidiaries, gains on the sale of oil and gas properties, non-cash impairments of the Company’s PRT decommissioning asset, and the current tax benefit associated with U.S. federal income tax credits. Apache’s 2016 year-to-date effective income tax rate was primarily impacted by non-cash impairments of the carrying value of the Company’s oil and gas properties, non-cash impairments of the Company’s PRT decommissioning asset, the impact of the change in U.K. statutory income tax rate, and an increase in the amount of valuation allowances on U.S. and Canadian deferred tax assets.

Apache and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. In April 2017, the Internal Revenue Service (IRS) began their audit of the Company’s 2014 income tax year. The Company is also under audit in various states and in most of the Company’s foreign jurisdictions as part of its normal course of business.

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Capital Resources and Liquidity

Operating cash flows are the Company’s primary source of liquidity. The Company may also elect to use available cash on hand, available committed borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets for all other liquidity and capital resource needs.

Apache’s operating cash flows, both in the short term and the long term, are impacted by highly volatile oil and natural gas prices, as well as costs and sales volumes. Significant changes in commodity prices impact Apache’s revenues, earnings, and cash flows. These changes potentially impact Apache’s liquidity if costs do not trend with changes in commodity prices. Historically, costs have trended with commodity prices, albeit with a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term.

Apache’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of Apache’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves. In the first nine months of 2017, Apache recognized positive reserve revisions of approximately 2 percent of its year-end 2016 estimated proved reserves as a result of higher prices.

Apache believes the liquidity and capital resource alternatives available to the Company, combined with proactive measures to adjust its capital budget to reflect volatile commodity prices and anticipated operating cash flows, will be adequate to fund short-term and long-term operations, including Apache’s capital spending program, repayment of debt maturities, payment of dividends, and any amount that may ultimately be paid in connection with commitments and contingencies.

For additional information, please see Part I, Items 1 and 2, “Business and Properties,” and Item 1A, “Risk Factors,” in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

Sources and Uses of Cash

The following table presents the sources and uses of the Company’s cash, cash equivalents, and restricted cash for the periods presented.

	For the Nine Months Ended September 30,
	2017		2016
	(In millions)
Sources of Cash, Cash Equivalents, and Restricted Cash:
Net cash provided by operating activities	$	1,760	$	1,634
Proceeds from sale of oil and gas properties	1,404		74
Other	—		38
	3,164		1,746
Uses of Cash and Cash Equivalents:
Capital expenditures(1)	$	1,855	$	1,314
Leasehold and property acquisitions	142		169
Payments on fixed-rate debt	70		1
Dividends paid	285		284
Distributions to noncontrolling interest	212		215
Other	35		—
	2,599		1,983
Increase (decrease) in cash, cash equivalents, and restricted cash	$	565	$	(237	)

(1) The table presents capital expenditures on a cash basis; therefore, the amounts may differ from those discussed elsewhere in this document, which include accruals.

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Net Cash Provided by Operating Activities Operating cash flows are Apache’s primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile oil and natural gas prices. The factors that determine operating cash flow are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation (ARO) accretion, and deferred income tax expense, which affect earnings but do not affect cash flows.

Net cash provided by operating activities for the first nine months of 2017 totaled $1.8 billion, an increase of $126 million from the first nine months of 2016. The increase primarily reflects higher commodity prices compared to the prior-year period.

For a detailed discussion of commodity prices, production, and expenses, refer to the “Results of Operations” of this Item 2. For additional detail on the changes in operating assets and liabilities and the non-cash expenses that do not impact net cash provided by operating activities, please see the statement of consolidated cash flows in Item 1, Financial Statements of this Quarterly Report on Form 10-Q.

Asset Divestitures The Company recorded proceeds from asset divestitures totaling $1.4 billion and $74 million in the first nine months of 2017 and 2016, respectively. For more information regarding the Company’s acquisitions and divestitures, please see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q.

Capital Expenditures Worldwide exploration and development (E&D) cash expenditures for the first nine months of 2017 totaled $1.5 billion, compared to $1.3 billion for the first nine months of 2016. Apache operated an average of 36 drilling rigs during the third quarter of 2017.

Apache also completed leasehold and property acquisitions totaling $142 million and $169 million during the first nine months of 2017 and 2016, respectively.

Apache’s investment in gas gathering, transmission, and processing (GTP) facilities totaled $384 million and $33 million during the first nine months of 2017 and 2016, respectively. Expenditures in 2017 primarily comprise investments in infrastructure for the Alpine High play.

Dividends For the nine-month periods ended September 30, 2017 and 2016, the Company paid $285 million and $284 million, respectively, in dividends on its common stock.

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Liquidity

The following table presents a summary of the Company’s key financial indicators at the dates presented:

	September 30, 2017		December 31, 2016
	(In millions)
Cash and cash equivalents	$	1,846	$	1,377
Total debt	8,483		8,544
Equity	8,377		7,679
Available committed borrowing capacity	3,500		3,500

Cash and cash equivalents The Company had $1.8 billion in cash and cash equivalents as of September 30, 2017, compared to $1.4 billion at December 31, 2016. At September 30, 2017, approximately $1.3 billion of the cash was held by foreign subsidiaries. The cash held by foreign subsidiaries should not be subject to additional U.S. income taxes if repatriated. The majority of the cash is invested in highly liquid, investment grade securities with maturities of three months or less at the time of purchase. The Company also had $96 million of restricted cash at September 30, 2017, expected to be released in the fourth quarter of 2017.

Debt As of September 30, 2017, outstanding debt, which consisted of notes and debentures, totaled $8.5 billion. Current debt as of September 30, 2017, included $150 million of 7.0% senior notes due February 1, 2018 and $400 million of 6.9% senior notes due September 15, 2018.

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, the Company 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.

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, the Company assumed the obligations of Apache Finance Canada Corporation (AFCC) in respect of $300 million7.75% 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 million7.75% 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.

Available committed borrowing capacity 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) and rights to increase commitments to $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, currently $3.5 billion. The commercial paper program, which is subject to market availability, facilitates Apache borrowing funds for up to 270 days at competitive interest rates. As of September 30, 2017, the Company had no commercial paper or borrowings under committed bank facilities or uncommitted bank lines outstanding.

In February 2016, the Company entered into a letter of credit facility providing £900 million in commitments and rights to increase commitments to £1.075 billion. This facility matures in February 2020 and 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. The facility also is available for loans 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. As of September 30, 2017, three letters of credit aggregating approximately £147.5 million and no borrowings were outstanding under this facility.

The Company was in compliance with the terms of these credit facilities as of September 30, 2017.

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ITEM 3 – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Risk

The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices the Company receives for its crude oil, natural gas, and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather, political climate, and global supply and demand. The Company’s average crude oil realizations have increased11 percent to $49.34 per barrel in the third quarter of 2017 from $44.35 per barrel in the comparable period of 2016. The Company’s average natural gas price realizations have increased6 percent to $2.75 per Mcf in the third quarter of 2017 from $2.59 per Mcf in the comparable period of 2016. Based on average daily production for the third quarter of 2017, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the quarter by approximately $22 million, and a $0.10 per Mcf change in the weighted average realized price of natural gas would have increased or decreased revenues for the quarter by approximately $9 million.

Apache periodically enters into derivative positions on a portion of its projected oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Apache does not hold or issue derivative instruments for trading purposes. As of September 30, 2017, the Company had open natural gas derivatives not designated as cash flow hedges in an asset position with a fair value of $6 million. A 10 percent increase in gas prices would move the derivatives to a liability position of $17 million, while a 10 percent decrease in prices would increase the asset by approximately $17 million. As of September 30, 2017, the Company had open oil derivatives not designated as cash flow hedges in an asset position with a fair value of $11 million. A 10 percent increase in oil prices would move the derivatives to a liability position of $50 million, while a 10 percent decrease in prices would increase the asset by approximately $84 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2017. See Note 3—Derivative Instruments and Hedging Activities of the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q for notional volumes and terms associated with the Company’s derivative contracts.

Foreign Currency Risk

The Company’s cash flow stream relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. The Company’s North Sea production is sold under U.S. dollar contracts, and the majority of costs incurred are paid in British pounds. In Egypt, all oil and gas production is sold under U.S. dollar contracts, and the majority of the costs incurred are denominated in U.S. dollars. Revenue and disbursement transactions denominated in British pounds are converted to U.S. dollar equivalents based on average exchange rates during the period.

Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Currency gains and losses are included as either a component of “Other” under “Revenues and Other” or, as is the case when the Company re-measures its foreign tax liabilities, as a component of the Company’s provision for income tax expense on the statement of consolidated operations. A foreign currency net gain or loss of $6 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of September 30, 2017.

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ITEM 4 – CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

John J. Christmann IV, the Company’s Chief Executive Officer and President, in his capacity as principal executive officer, and Stephen J. Riney, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2017, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that information we are required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

We periodically review the design and effectiveness of our disclosure controls, including compliance with various laws and regulations that apply to our operations both inside and outside the United States. We make modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if our reviews identify deficiencies or weaknesses in our controls.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

37

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Please refer to Part I, Item 3 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016 (filed with the SEC on February 24, 2017) and Note 9—Commitments and Contingencies in the notes to the consolidated financial statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q, for a description of material legal proceedings.

ITEM 1A. RISK FACTORS

Please refer to Part I, Item 1A—Risk Factors of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016, and Part I, Item 3—Quantitative and Qualitative Disclosures About Market Risk of this Quarterly Report on Form 10-Q. There have been no material changes to our risk factors since our annual report on Form 10-K for the fiscal year ended December 31, 2016.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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 negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through September 30, 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 additional shares during 2017.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4. MINE SAFETY DISCLOSURES

None

ITEM 5. OTHER INFORMATION

None

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ITEM 6. EXHIBITS

3.1	–	Restated Certificate of Incorporation of Registrant, dated September 19, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed September 20, 2013, SEC File No. 001-4300).
3.2	–	Certificate of Amendment of Restated Certificate of Incorporation of Registrant, dated May 14, 2015, as filed with the Secretary of State of Delaware on May 14, 2015 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed May 20, 2015, SEC File No. 001-4300).
3.3	–	Bylaws of Registrant, as amended May 11, 2017 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed May 16, 2017, SEC File No. 001-4300).
*4.1	–	Supplemental Indenture, dated as of August 14, 2017, among Apache Finance Canada Corporation, Apache Corporation, and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A., formerly The Chase Manhattan Bank), as trustee.
*31.1	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
*32.1	–	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
*101.INS	–	XBRL Instance Document.
*101.SCH	–	XBRL Taxonomy Schema Document.
*101.CAL	–	XBRL Calculation Linkbase Document.
*101.DEF	–	XBRL Definition Linkbase Document.
*101.LAB	–	XBRL Label Linkbase Document.
*101.PRE	–	XBRL Presentation Linkbase Document.

* Filed herewith

39

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

		APACHE CORPORATION
Dated:	November 2, 2017	/s/ STEPHEN J. RINEY
		Stephen J. Riney
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)
Dated:	November 2, 2017	/s/ REBECCA A. HOYT
		Rebecca A. Hoyt
		Senior Vice President, Chief Accounting Officer, and Controller
		(Principal Accounting Officer)

40

EX-4.1

APACHE FINANCE CANADA CORPORATION,

Company

APACHE CORPORATION,

Guarantor

to

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.,

Trustee

SUPPLEMENTAL INDENTURE

Dated as of August 14, 2017

to Indenture

Dated as of November 23, 1999

Debt Securities

SUPPLEMENTAL INDENTURE

SUPPLEMENTAL INDENTURE, dated as of August 14, 2017 (this “Supplemental Indenture”), among APACHE FINANCE CANADA CORPORATION, an unlimited liability company duly organized and existing under the laws of Nova Scotia, Canada (the “Company”), APACHE CORPORATION, a corporation duly organized and existing under the laws of the State of Delaware (the “Guarantor”), and THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A. (as successor to JPMorgan Chase Bank, N.A., formerly The Chase Manhattan Bank), a national banking association, as trustee under the Indenture referred to below (the “Trustee”).

RECITALS OF THE COMPANY AND THE GUARANTOR:

A.The Company and the Guarantor have heretofore executed and delivered to the Trustee (as successor to JPMorgan Chase Bank, N.A., formerly The Chase Manhattan Bank) an Indenture, dated as of November 23, 1999 (as heretofore amended and supplemented, the “Indenture”), providing for the issuance from time to time of the Company’s senior unsecured debentures, notes or other evidences of Indebtedness (herein and in the Indenture called the “Securities”) in one or more series.

B.Pursuant to the Indenture, the Company issued $300,000,000 aggregate principal amount of Securities of a series designated as the 7.75% Notes due December 15, 2029 (the “Notes”), which are guaranteed by the Guarantor and are the only outstanding Securities under the Indenture.

C.Section 804(a) of the Indenture provides that under certain circumstances the Guarantor may, at its option, assume the obligations of the Company as obligor under any series of Securities and the Indenture, in a supplemental indenture thereto, executed and delivered to the Trustee.

D.Pursuant to Section 804(a) of the Indenture, the Guarantor has elected to assume the obligations of the Company as obligor under all Securities and the Indenture.

E.Pursuant to Section 901(a) of the Indenture, the Company (when authorized by or pursuant to a Board Resolution), the Guarantor (when authorized by or pursuant to a Board Resolution), and the Trustee are authorized to enter into this Supplemental Indenture to evidence the succession of the Guarantor to the Company, and the assumption by the Guarantor of covenants of the Company contained in the Indenture and in the Securities, without the consent of any Holder.

F.Upon the assumption by the Guarantor pursuant to Section 804(a) of the Indenture and this Supplemental Indenture, the Guarantor shall succeed to, and be substituted for, and may exercise every right and power of, the Company under all Securities and the Indenture with the same effect as if the Guarantor had been named as the Company therein, and the Company shall be released from its liability as obligor upon all Securities and any Coupons and under the Indenture.

G.The Company hereby requests that the Trustee join with the Company and the Guarantor in the execution and delivery of this Supplemental Indenture, and the Company and the Guarantor have each provided the Trustee with a Board Resolution authorizing the execution of and approving this Supplemental Indenture.

NOW, THEREFORE, the Company, the Guarantor, and the Trustee agree as follows:

ARTICLE I

Definitions

As used in this Supplemental Indenture, terms defined in the Indenture have the meaning set forth in the Indenture and the terms defined above have the meaning set forth above. The words “herein,” “hereof” and “hereby” and other words of similar import used in this Supplemental Indenture refer to this Supplemental Indenture as a whole and not to any particular section hereof.

ARTICLE II

Agreement to be Bound, Indemnification and Succession

SECTION 2.1 Agreement to be Bound. The Guarantor hereby assumes the due and punctual payment of the principal of and any premium and interest on all Securities (including the Notes) and the performance or observance of every covenant of the Indenture on the part of the Company to be performed or observed (including any obligation to pay any Additional Amounts).

SECTION 2.2 Indemnification. The Guarantor hereby agrees to immediately indemnify (pursuant to the indemnification procedure described in Section 805 of the Indenture) the Holder of each Security against (i) any tax, assessment or governmental charge imposed on such Holder or required to be withheld or deducted from any payment to such Holder (including any governmental charge or withholding tax attributable to the Guarantor indemnifying such Holder) as a consequence of the assumption hereby and (ii) any costs or expenses of such assumption (except that a Holder will have indemnification rights pursuant to the indemnification procedure described in Section 805 of the Indenture only if and when gain for U.S. federal income tax purposes is actually recognized by such Holder).

ARTICLE III

Miscellaneous

SECTION 3.1 Notices. All notices and other communications to the Guarantor shall be given at its address set forth below, as provided in the Indenture for notices to the Company.

Apache Corporation

One Post Oak Central

2000 Post Oak Boulevard, Suite 100

Houston, Texas 77056-4400

Attention: Vice President and Treasurer

SECTION 3.2 Parties. Nothing expressed or mentioned herein is intended or shall be construed to give any Person, firm or corporation, other than the Holders and the Trustee, any legal or equitable right, remedy or claim under or in respect of this Supplemental Indenture or the Indenture or any provision herein or therein contained.

SECTION 3.3 Governing Law. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK. BY THE EXECUTION AND DELIVERY OF THIS SUPPLEMENTAL INDENTURE, EACH OF THE COMPANY AND THE GUARANTOR SUBMITS TO THE JURISDICTION OF ANY FEDERAL OR NEW YORK STATE COURT HAVING SUBJECT MATTER JURISDICTION, SITTING, IN EACH CASE, IN THE BOROUGH OF MANHATTAN, THE CITY OF NEW YORK, UNITED STATES OF AMERICA IN ANY SUIT, ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS SUPPLEMENTAL INDENTURE OR THE NOTES.

SECTION 3.4 Severability Clause. In case any provision in this Supplemental Indenture shall be invalid, illegal or unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby and such provision shall be ineffective only to the extent of such invalidity, illegality or unenforceability.

SECTION 3.5 Ratification of Indenture; Supplemental Indenture Part of Indenture. Except as expressly amended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every Holder of Securities heretofore or hereafter authenticated and delivered shall be bound hereby. The Trustee makes no representation or warranty as to the validity or sufficiency of this Supplemental Indenture.

SECTION 3.6 Counterparts. The parties hereto may sign one or more copies of this Supplemental Indenture in counterparts, all of which together shall constitute one and the same agreement. The exchange of copies of this Supplemental Indenture and of signature pages by facsimile or electronic (i.e., “pdf” or “tif”) transmission shall constitute effective execution and delivery of this Indenture as to the parties hereto and may be used in lieu of the original Supplemental Indenture for all purposes. Signatures of the parties hereto transmitted by facsimile or electronic (i.e., “pdf” or “tif”) transmission shall be deemed to be their original signatures for all purposes.

SECTION 3.7 Headings. The headings of the Articles and the sections in this Supplemental Indenture are for convenience of reference only and shall not be deemed to alter or affect the meaning or interpretation of any provisions hereof.

SECTION 3.8 The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity, sufficiency or adequacy of this Supplemental Indenture or for or in respect of the statements or recitals contained herein, all of which recitals are made solely by the Company and the Guarantor, and the Trustee assumes no responsibility for their correctness.

[SIGNATURE PAGES FOLLOW]

The parties have executed this Supplemental Indenture as of the date first above written.

APACHE FINANCE CANADA CORPORATION, as Company

By: /s/ Jon W. Sauer

Name: Jon W. Sauer

Title:Senior Vice President

APACHE CORPORATION, as Guarantor

By: /s/ Stephen J. Riney

Name:Stephen J. Riney

Title:Executive Vice President and

Chief Financial Officer

[Signature Page - Supplemental Indenture (November 23, 1999 Indenture)]

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., as Trustee

By: /s/ Valere Boyd

Name: Valere Boyd

Title:Vice President

[Signature Page - Supplemental Indenture (November 23, 1999 Indenture)]

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

I, John J. Christmann IV, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Apache Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ John J. Christmann IV

John J. Christmann IV

Chief Executive Officer and President

(principal executive officer)

Date: November 2, 2017

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

I, Stephen J. Riney, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Apache Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Stephen J. Riney

Stephen J. Riney

Executive Vice President and Chief Financial Officer

(principal financial officer)

Date: November 2, 2017

EX-32.1

EXHIBIT 32.1

APACHE CORPORATION

Certification of Principal Executive Officer

and Principal Financial Officer

I, John J. Christmann IV, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of Apache Corporation for the quarterly period ending September 30, 2017, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Corporation.

/s/ John J. Christmann IV
By:	John J. Christmann IV
Title:	Chief Executive Officer and President
	(principal executive officer)

Date: November 2, 2017

I, Stephen J. Riney, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of Apache Corporation for the quarterly period ending September 30, 2017, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Corporation.

/s/ Stephen J. Riney
By:	Stephen J. Riney
Title:	Executive Vice President and Chief Financial Officer
	(principal financial officer)

Date: November 2, 2017

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Oct. 31, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Trading Symbol	APA
Entity Registrant Name	APACHE CORP
Entity Central Index Key	0000006769
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		380,942,629

XML

STATEMENT OF CONSOLIDATED OPERATIONS (Unaudited) - USD ($) shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
REVENUES AND OTHER:
Oil and Gas Production Revenues	$ 1,389,000,000	$ 1,439,000,000	$ 4,247,000,000	$ 3,912,000,000
Derivative instrument losses, net	(110,000,000)	0	(69,000,000)	0
Gain on divestitures	296,000,000	5,000,000	616,000,000	21,000,000
Other	0	(6,000,000)	43,000,000	(30,000,000)
Total revenues and other	1,575,000,000	1,438,000,000	4,837,000,000	3,903,000,000
OPERATING EXPENSES:
Lease operating expenses	358,000,000	382,000,000	1,066,000,000	1,119,000,000
Gathering and transportation	39,000,000	51,000,000	144,000,000	155,000,000
Taxes other than income	46,000,000	9,000,000	117,000,000	85,000,000
Exploration	231,000,000	161,000,000	431,000,000	347,000,000
General and administrative	98,000,000	102,000,000	307,000,000	298,000,000
Transaction, reorganization, and separation	20,000,000	12,000,000	14,000,000	36,000,000
Depreciation, depletion and amortization			1,707,000,000	1,995,000,000
Asset retirement obligation accretion	30,000,000	40,000,000	103,000,000	116,000,000
Impairments	0	836,000,000	8,000,000	1,009,000,000
Financing costs, net	101,000,000	102,000,000	300,000,000	311,000,000
Total operating expenses	1,482,000,000	2,343,000,000	4,197,000,000	5,471,000,000
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	93,000,000	(905,000,000)	640,000,000	(1,568,000,000)
Current income tax provision	99,000,000	150,000,000	413,000,000	284,000,000
Deferred income tax benefit	(111,000,000)	(529,000,000)	(758,000,000)	(755,000,000)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	105,000,000	(526,000,000)	985,000,000	(1,097,000,000)
Net loss from discontinued operations, net of tax	0	(33,000,000)	0	(33,000,000)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	105,000,000	(559,000,000)	985,000,000	(1,130,000,000)
Net income attributable to noncontrolling interest	42,000,000	48,000,000	137,000,000	93,000,000
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	63,000,000	(607,000,000)	848,000,000	(1,223,000,000)
Net income (loss) from continuing operations attributable to common shareholders	63,000,000	(574,000,000)	848,000,000	(1,190,000,000)
Net loss from discontinued operations	0	(33,000,000)	0	(33,000,000)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$ 63,000,000	$ (607,000,000)	$ 848,000,000	$ (1,223,000,000)
NET INCOME (LOSS) PER COMMON SHARE:
Basic net income (loss) from continuing operations per share (in USD per share)	$ 0.16	$ (1.51)	$ 2.23	$ (3.14)
Basic net loss from discontinued operations per share (in USD per share)	0.00	(0.09)	0.00	(0.08)
Basic net income (loss) per share (in USD per share)	0.16	(1.60)	2.23	(3.22)
DILUTED NET INCOME (LOSS) PER COMMON SHARE:
Diluted net income (loss) from continuing operations per share (in USD per share)	0.16	(1.51)	2.22	(3.14)
Diluted net loss from discontinued operations per share (in USD per share)	0.00	(0.09)	0.00	(0.08)
Diluted net income (loss) per share (in USD per share)	$ 0.16	$ (1.60)	$ 2.22	$ (3.22)
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic (in shares)	381	380	381	379
Diluted (in shares)	383	380	383	379
DIVIDENDS DECLARED PER COMMON SHARE (in USD per share)	$ 0.25	$ 0.25	$ 0.75	$ 0.75
Oil and gas property and equipment
OPERATING EXPENSES:
Depreciation, depletion and amortization	$ 524,000,000	$ 610,000,000	$ 1,598,000,000	$ 1,875,000,000
Other assets
OPERATING EXPENSES:
Depreciation, depletion and amortization	35,000,000	38,000,000	109,000,000	120,000,000
Oil revenues
REVENUES AND OTHER:
Oil and Gas Production Revenues	1,070,000,000	1,117,000,000	3,292,000,000	3,057,000,000
Gas revenues
REVENUES AND OTHER:
Oil and Gas Production Revenues	238,000,000	263,000,000	726,000,000	695,000,000
Natural gas liquids revenues
REVENUES AND OTHER:
Oil and Gas Production Revenues	$ 81,000,000	$ 59,000,000	$ 229,000,000	$ 160,000,000

XML

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	$ 105	$ (559)	$ 985	$ (1,130)
OTHER COMPREHENSIVE INCOME:
Currency translation adjustment	109	0	109	0
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	214	(559)	1,094	(1,130)
Comprehensive income attributable to noncontrolling interest	42	48	137	93
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$ 172	$ (607)	$ 957	$ (1,223)

XML

STATEMENT OF CONSOLIDATED CASH FLOWS (Unaudited) - USD ($)	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) including noncontrolling interest	$ 985,000,000	$ (1,130,000,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss from discontinued operations	0	33,000,000
Unrealized derivative instrument losses, net	42,000,000	0
Gain on divestitures	(616,000,000)	(21,000,000)
Exploratory dry hole expense and unproved leasehold impairments	350,000,000	260,000,000
Depreciation, depletion, and amortization	1,707,000,000	1,995,000,000
Asset retirement obligation accretion	103,000,000	116,000,000
Impairments	8,000,000	1,009,000,000
Deferred income tax benefit	(758,000,000)	(755,000,000)
Other	167,000,000	126,000,000
Changes in operating assets and liabilities:
Receivables	(70,000,000)	192,000,000
Inventories	17,000,000	(2,000,000)
Drilling advances	(72,000,000)	(36,000,000)
Deferred charges and other	(60,000,000)	40,000,000
Accounts payable	2,000,000	(93,000,000)
Accrued expenses	(65,000,000)	(67,000,000)
Deferred credits and noncurrent liabilities	20,000,000	(33,000,000)
NET CASH PROVIDED BY OPERATING ACTIVITIES	1,760,000,000	1,634,000,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(1,471,000,000)	(1,281,000,000)
Leasehold and property acquisitions	(142,000,000)	(169,000,000)
Additions to gas gathering, transmission, and processing facilities	(384,000,000)	(33,000,000)
Proceeds from sale of Canadian assets, net of cash divested	661,000,000	0
Proceeds from sale of oil and gas properties	743,000,000	74,000,000
Other, net	(30,000,000)	47,000,000
NET CASH USED IN INVESTING ACTIVITIES	(623,000,000)	(1,362,000,000)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on fixed-rate debt	(70,000,000)	(1,000,000)
Distributions to noncontrolling interest	(212,000,000)	(215,000,000)
Dividends paid	(285,000,000)	(284,000,000)
Other	(5,000,000)	(9,000,000)
NET CASH USED IN FINANCING ACTIVITIES	(572,000,000)	(509,000,000)
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS, AND RESTRICTED CASH	565,000,000	(237,000,000)
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF YEAR	1,377,000,000	1,467,000,000
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	1,942,000,000	1,230,000,000
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	341,000,000	345,000,000
Income taxes paid, net of refunds	$ 315,000,000	$ 256,000,000

XML

CONSOLIDATED BALANCE SHEET (Unaudited) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
CURRENT ASSETS:
Cash and cash equivalents	$ 1,846	$ 1,377
Restricted cash	96	0
Receivables, net of allowance	1,145	1,128
Inventories	396	476
Drilling advances	151	81
Prepaid assets and other	135	179
Total current assets	3,769	3,241
Oil and gas, on the basis of successful efforts accounting:
Proved properties	38,569	42,693
Unproved properties and properties under development	1,810	1,969
Gathering, transmission, and processing facilities	1,363	976
Other	1,012	1,111
Property and equipment, gross	42,754	46,749
Less: Accumulated depreciation, depletion, and amortization	(25,099)	(27,882)
Property and equipment, net	17,655	18,867
OTHER ASSETS:
Deferred charges and other	411	411
Total assets	21,835	22,519
CURRENT LIABILITIES:
Accounts payable	583	585
Current debt	550	0
Other current liabilities (Note 5)	1,332	1,258
Total current liabilities	2,465	1,843
LONG-TERM DEBT	7,933	8,544
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	948	1,710
Asset retirement obligation	1,831	2,432
Other	281	311
Total deferred credits and other noncurrent liabilities	3,060	4,453
COMMITMENTS AND CONTINGENCIES (Note 9)
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 414,108,944 and 412,612,102 shares issued, respectively	259	258
Paid-in capital	12,186	12,364
Accumulated deficit	(2,544)	(3,385)
Treasury stock, at cost, 33,171,015 and 33,172,426 shares, respectively	(2,887)	(2,887)
Accumulated other comprehensive loss	(3)	(112)
APACHE SHAREHOLDERS’ EQUITY	7,011	6,238
Noncontrolling interest	1,366	1,441
TOTAL EQUITY	8,377	7,679
TOTAL LIABILITIES AND EQUITY	$ 21,835	$ 22,519

XML

CONSOLIDATED BALANCE SHEET (Unaudited) (Parenthetical) - $ / shares	Sep. 30, 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	414,108,944	412,612,102
Treasury stock, shares	33,171,015	33,172,426

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STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (Unaudited) - USD ($) $ in Millions	Total	Common Stock	Paid-In Capital	Accumulated Deficit	Treasury Stock	Accumulated Other Comprehensive Loss	APACHE SHAREHOLDERS’ EQUITY	Noncontrolling Interest
Beginning 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)	(1,130)			(1,223)			(1,223)	93
Distributions to noncontrolling interest	(215)							(215)
Common dividends ($0.75 per share)	(284)		(284)				(284)
Other	88	1	86		1		88
Ending Balance at Sep. 30, 2016	7,949	258	12,421	(3,203)	(2,888)	(119)	6,469	1,480
Beginning 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)	985			848			848	137
Distributions to noncontrolling interest	(212)							(212)
Common dividends ($0.75 per share)	(286)		(286)				(286)
Other	211	1	108	(7)		109	211
Ending Balance at Sep. 30, 2017	$ 8,377	$ 259	$ 12,186	$ (2,544)	$ (2,887)	$ (3)	$ 7,011	$ 1,366

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STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (Unaudited) (Parenthetical) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Statement of Stockholders' Equity [Abstract]
Common stock, dividends (USD per share)	$ 0.25	$ 0.25	$ 0.75	$ 0.75

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These consolidated financial statements have been prepared by Apache Corporation (Apache or the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016, which contains a summary of the Company’s significant accounting policies and other disclosures.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of September 30, 2017, Apache’s significant accounting policies are consistent with those discussed in Note 1—Summary of Significant Accounting Policies of its consolidated financial statements contained in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016, with the exception of Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) 2016-09, “Improvements to Employee Share-Based Payment Accounting” and ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash” (see “Recently Adopted Accounting Pronouncements” in this Note 1 below).

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates with regard to these financial statements include the fair value determination of acquired assets and liabilities, the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, the assessment of asset retirement obligations, the estimates of fair value for long-lived assets and goodwill, and the estimate of income taxes. Actual results could differ from those estimates.

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).

Apache also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. The Company recorded no asset impairments in connection with fair value assessments in the third quarter of 2017. For the nine-month period ended September 30, 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 the first quarter of 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 quarter ended September 30, 2016, the Company recorded asset impairments totaling $836 million in connection with fair value assessments including $355 million for proved oil and gas properties in Canada and $481 million for the impairment of the recoverable value of the PRT decommissioning asset. For the nine-month period ended September 30, 2016, the Company recorded asset impairments totaling $1.0 billion in connection with fair value assessments including $423 million for proved oil and gas properties in the U.S. and Canada, $481 million for the impairment of the recoverable value of the PRT decommissioning asset, and $105 million for the impairment of certain gas gathering, transmission, and processing (GTP) assets, which were written down to their fair values of $175 million.

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 of exploratory wells and development costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.

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

When circumstances indicate that 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 the third quarters and first nine months of 2017 and 2016:

	Quarter Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(In millions)
Oil and Gas Property:
Proved	$	—	$	355	$	—	$	423
Unproved	160		114		214		222

Proved properties impaired during the second and third quarters of 2016 had aggregate fair values of $143 million and $163 million, respectively.

On the statement of consolidated operations, unproved impairments are recorded in exploration expense, and proved impairments are recorded in impairments.

Recently Adopted Accounting Pronouncements

Stock Compensation

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.

Restricted Cash

In November 2016, the 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. Other than the change in presentation within the statement of consolidated cash flows, the adoption of ASU 2016-18 did not have an impact on the Company’s consolidated financial statements.

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheet to the amounts shown in the statement of consolidated cash flows:

	September 30, 2017		December 31, 2016
	(In millions)
Cash and cash equivalents	$	1,846	$	1,377
Restricted cash	96		—
Total cash, cash equivalents, and restricted cash shown in the statement of consolidated cash flows	$	1,942	$	1,377

For information regarding the restricted cash balance, please refer to Note 2—Acquisitions and Divestitures.

New Pronouncements Issued But Not Yet Adopted

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 U.S. 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. As part of the assessment to date, the Company has formed an implementation work team and is continuing to evaluate contracts to determine the impact this ASU will have on its consolidated financial statements. 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.

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 standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Company continues to make progress on evaluating the accounting implications of this ASU and its assessment of contracts with customers is largely complete. Based on the Company’s evaluation to date, it does not expect the adoption of this ASU to have a material impact on net earnings, however, the Company is analyzing whether the classification of certain items in revenue and expense will be impacted. The Company continues to evaluate the disclosure requirements, develop accounting policies, and assess changes to the relevant business processes and the control activities within them as a result of the provisions of this ASU. The Company will adopt the new standard on January 1, 2018, utilizing the modified retrospective approach.

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ACQUISITIONS AND DIVESTITURES

9 Months Ended

Sep. 30, 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. The Company has classified $96 million of proceeds as “Restricted cash” on the Company’s consolidated balance sheet, pending the Alberta Energy Regulator’s clearance of the transfer of Provost area licenses from ACL to the buyer.

A summary of the assets and liabilities at closing of the August transactions is detailed below:

	(In millions)
ASSETS
Current assets	$	110
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 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 $12 million and $141 million for the third quarter and first nine months of 2017, respectively, compared to pretax losses of $483 million and $644 million, respectively, for the comparable periods in 2016.

U.S. Divestitures

During the first nine months of 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 $783 million, subject to customary closing adjustments. A refundable deposit of $40 million was received in the fourth quarter of 2016 in connection with certain of these transactions. The Company recognized gains of approximately $594 million during the first nine months of 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 Scottish Area Gas Evacuation system (SAGE) and its 60.56 percent interest in the Beryl pipeline in the North Sea to Ancala Midstream Acquisitions Limited (Ancala). The transaction is subject to regulatory and third-party approvals, which are ongoing in 2017. The Company received a refundable deposit in connection with this transaction, which is recorded in “Other current liabilities” on the consolidated balance sheet. The refundable deposit was $149 million as of September 30, 2017.

Leasehold and Property Acquisitions

During the third quarter and first nine months of 2017, Apache purchased $75 million and $142 million, respectively, of leasehold and property acquisitions primarily in its North America onshore regions.

2016 Activity

Leasehold and Property Acquisitions

During the third quarter and first nine months of 2016, Apache purchased $51 million and $169 million, respectively, of leasehold and property acquisitions primarily in its North America onshore regions and Egypt.

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 Quarter Ended September 30,					For the Nine Months Ended September 30,
	2017		2016			2017		2016
	(In millions)
Loss from Australia divestiture	$	—	$	(23	)	$	—	$	(23	)
Loss from Argentina divestiture	—		(10		)	—		(10		)
Loss from discontinued operations, net of tax	$	—	$	(33	)	$	—	$	(33	)

Transaction, Reorganization, and Separation

During the third quarter and first nine months of 2017, Apache recorded $20 million and $14 million, respectively, in expense related to asset divestitures in the U.S. and Canada and employee separation. During the third quarter and first nine months of 2016, Apache recorded $12 million and $36 million, respectively, in expense related to various asset divestitures, company reorganization, and employee separation.

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

9 Months Ended

Sep. 30, 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. The Company’s derivatives are not designated as cash flow hedges, therefore, changes in fair value are recognized currently in earnings.

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 September 30, 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 September 30, 2017, Apache had the following open crude oil derivative positions:

		Put Options(1)(2)
Production Period	Settlement Index	Mbbls	Weighted Average Strike Price
October—December 2017	NYMEX WTI	8,464	$50.00
October—December 2017	Dated Brent	7,636	$51.00

(1) The remaining unamortized premium paid as of September 30, 2017, was $50 million.

(2) Subsequent to September 30, 2017, Apache entered into put option contracts settling against Dated Brent totaling 3,650 Mbbls with a strike price of $50 for the calendar year 2018.

		Fixed-Price Swaps		Collars(3)			Call Options(4)
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	—	—	6,023	$45.00	$57.02	6,023	$60.00

(3) Subsequent to September 30, 2017, Apache entered into crude oil contracts settling against NYMEX WTI totaling 730 Mbbls with a floor and ceiling of $45.00 and $56.90, respectively, for the calendar year 2018.

(4) The remaining unamortized premium paid as of September 30, 2017, was $9 million.

As of September 30, 2017, Apache had the following open natural gas derivative positions:

		Fixed-Price Swaps(1)
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Fixed Price
October—December 2017	NYMEX Henry Hub	4,370	$3.32
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	18,400	$2.97

(1) Subsequent to September 30, 2017, Apache entered into fixed-price natural gas swaps settling against NYMEX Henry Hub totaling 15,180,000 MMBtu with a weighted average fixed-price of $2.95 for the second half of 2018.

As of September 30, 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)
September 30, 2017
Assets:
Commodity Derivative Instruments	$	—	$	24	$	—	$	24	$	(7	)	$	17
Liabilities:
Commodity Derivative Instruments	—		7		—		7		(7		)	—
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:

	September 30, 2017		December 31, 2016
	(In millions)
Current Assets: Prepaid assets and other	$	13	$	—
Other Assets: Deferred charges and other	4		—
Total Assets	$	17	$	—

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 Quarter Ended September 30,					For the Nine Months Ended September 30,
	2017			2016		2017			2016
	(In millions)
Realized gain (loss):
Derivative settlements, realized gain	$	23		$	—	$	23		$	—
Amortization of put premium, realized loss	(50		)	—		(50		)	—
Unrealized loss	(83		)	—		(42		)	—
Derivative instrument losses, net	$	(110	)	$	—	$	(69	)	$	—

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 a component of “Unrealized derivative instrument losses, net” in “Adjustments to reconcile net income (loss) to net cash provided by operating activities.”

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CAPITALIZED EXPLORATORY WELL COSTS

9 Months Ended

Sep. 30, 2017

Extractive Industries [Abstract]

CAPITALIZED EXPLORATORY WELL COSTS

CAPITALIZED EXPLORATORY WELL COSTS

The Company’s capitalized exploratory well costs were $369 million and $264 million at September 30, 2017 and December 31, 2016, respectively. The increase is primarily attributable to additional drilling activities in the U.S. during the period, partially offset by successful transfers and dry hole write-offs. No suspended exploratory well costs previously capitalized for greater than one year at December 31, 2016 were charged to dry hole expense during the nine months ended September 30, 2017. 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.

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OTHER CURRENT LIABILITIES

9 Months Ended

Sep. 30, 2017

Payables and Accruals [Abstract]

OTHER CURRENT LIABILITIES

OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities as of September 30, 2017 and December 31, 2016:

	September 30, 2017		December 31, 2016
	(In millions)
Accrued operating expenses	$	73	$	110
Accrued exploration and development	691		463
Accrued compensation and benefits	99		201
Accrued interest	108		145
Accrued income taxes	68		22
Current asset retirement obligation	35		66
Refundable deposits	149		174
Other	109		77
Total other current liabilities	$	1,332	$	1,258

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ASSET RETIREMENT OBLIGATION

9 Months Ended

Sep. 30, 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 nine-month period ended September 30, 2017:

	(In millions)
Asset retirement obligation at December 31, 2016	$	2,498
Liabilities incurred	39
Liabilities divested	(810		)
Liabilities settled	(30		)
Accretion expense	103
Revisions in estimated liabilities	66
Asset retirement obligation at September 30, 2017	1,866
Less current portion	35
Asset retirement obligation, long-term	$	1,831

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INCOME TAXES

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

The Company estimates its annual effective income tax rate for continuing operations in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments of the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur.

In August 2017, Apache completed the sale of ACL. For more information regarding this transaction, please refer to Note 2—Acquisitions and Divestitures. As a result of this transaction, Apache recorded a deferred tax asset associated with its realizable capital loss on the sale of ACL, and a decrease in the Company’s deferred tax liability associated with its investment in foreign subsidiaries. In the third and second quarters of 2017, the Company recorded a $2 million deferred income tax expense and a $674 million deferred income tax benefit, respectively, in connection with these transactions.

Apache’s third quarter of 2017 effective income tax rate was primarily impacted by gains on the sale of oil and gas properties and a $30 million current tax benefit associated with U.S. federal income tax credits. On September 15, 2016, U.K. Finance Act 2016 received Royal Assent. Under the enacted legislation, the corporate income tax rate on North Sea oil and gas profits was reduced from 50 percent to 40 percent effective January 1, 2016. As a result of the enacted legislation, in the third quarter of 2016 the Company recorded a deferred tax benefit of $235 million related to the remeasurement of the Company’s December 31, 2015 U.K. deferred income tax liability.

Apache’s 2017 year-to-date effective income tax rate is primarily impacted by the decrease in deferred taxes associated with its investments in foreign subsidiaries, gains on the sale of oil and gas properties, non-cash impairments of the Company’s PRT decommissioning asset, and the current tax benefit associated with U.S. federal income tax credits. Apache’s 2016 year-to-date effective income tax rate was primarily impacted by non-cash impairments of the carrying value of the Company’s oil and gas properties, non-cash impairments of the Company’s PRT decommissioning asset, the impact of the change in U.K. statutory income tax rate, and an increase in the amount of valuation allowances on U.S. and Canadian deferred tax assets.

Apache and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. In April 2017, the Internal Revenue Service (IRS) began their audit of the Company’s 2014 income tax year. The Company is also under audit in various states and in most of the Company’s foreign jurisdictions as part of its normal course of business.

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DEBT AND FINANCING COSTS

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

DEBT AND FINANCING COSTS

DEBT AND FINANCING COSTS

The following table presents the carrying amounts and estimated fair values of the Company’s outstanding debt as of September 30, 2017 and December 31, 2016:

	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Commercial paper and committed bank facilities	$	—	$	—	$	—	$	—
Notes and debentures	8,483		9,094		8,544		9,183
Total Debt	$	8,483	$	9,094	$	8,544	$	9,183

The Company’s debt is recorded at the carrying amount, net of related unamortized discount and debt issuance costs, on its consolidated balance sheet. When recorded, the carrying amount of the Company’s commercial paper, committed bank facilities, and uncommitted bank lines approximates 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 notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

The following table presents the carrying value of the Company’s debt as of September 30, 2017 and December 31, 2016:

	September 30, 2017			December 31, 2016
	(In millions)
Debt before unamortized discount and debt issuance costs	$	8,580		$	8,650
Unamortized discount	(48		)	(50		)
Debt issuance costs	(49		)	(56		)
Total debt	8,483			8,544
Current maturities	(550		)	—
Long-term debt	$	7,933		$	8,544

As of September 30, 2017, current debt included $150 million of 7.0% senior notes due February 1, 2018 and $400 million of 6.9% senior notes due September 15, 2018.

As of September 30, 2017, the Company had a revolving credit facility that matures in June 2020, subject to Apache’s twoone-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 $3.5 billion commercial paper program. The commercial paper program, which is subject to market availability, facilitates Apache borrowing funds for up to 270 days at competitive interest rates. As of September 30, 2017, the Company had no commercial paper or borrowings under committed bank facilities or uncommitted bank lines outstanding.

As of September 30, 2017, the Company had a letter of credit facility, which provides for £900 million in commitments and rights to increase commitments to £1.075 billion. This facility matures in February 2020. The facility is available for letters of credit and loans 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. As of September 30, 2017, three letters of credit aggregating approximately £147.5 million and no borrowings were outstanding under this facility.

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, the Company 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.

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, the Company assumed the obligations of Apache Finance Canada Corporation (AFCC) in respect of $300 million7.75% 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 million7.75% 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.

Financing Costs, Net

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

	For the Quarter Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(In millions)
Interest expense	$	113		$	116		$	344		$	348
Amortization of deferred loan costs	3			2			7			5
Capitalized interest	(12		)	(13		)	(39		)	(36		)
Loss on extinguishment of debt	—			—			1			—
Interest income	(3		)	(3		)	(13		)	(6		)
Financing costs, net	$	101		$	102		$	300		$	311

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COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 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. As of September 30, 2017, 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.

For additional information on each of the Legal Matters described below, please see Note 10—Commitments and Contingencies to the consolidated financial statements contained in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

Argentine Environmental Claims and Argentina Tariff

No material change in the status of the YPF Sociedad Anónima and Pioneer Natural Resources Company indemnities matters has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

Louisiana Restoration

As more fully described in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016, numerous surface owners have filed claims or sent demand letters to various oil and gas companies, including Apache, claiming that, under either express or implied lease terms or Louisiana law, the companies are liable for damage measured by the cost of restoration of leased premises to their original condition as well as damages for contamination and cleanup.

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. On October 30, 2017, the United States Supreme Court denied review and declined to consider the plaintiff’s Petition of Certiorari.

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.

No other material change in the status of these matters has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

Apollo Exploration Lawsuit

In a fourth amended petition filed on March 21, 2016, in a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs have reduced their alleged damages to approximately $500 million (having previously claimed in excess of $1.1 billion) relating to certain purchase and sale agreements, mineral leases, and areas of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The Court recently granted two of Apache’s motions for summary judgment further limiting the plaintiffs’ theories and potential damages. Apache believes that plaintiffs’ claims lack merit, and further that plaintiffs’ alleged damages, even as amended, are grossly inflated. Apache will vigorously oppose the claims. No other material change in the status of these matters has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

Escheat Audits

There has been no material change with respect to the review of the books and records of the Company and its subsidiaries and related entities by the State of Delaware, Department of Finance (Unclaimed Property), to determine compliance with the Delaware Escheat Laws, since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

Environmental Matters

As of September 30, 2017, the Company had an undiscounted reserve for environmental remediation of approximately $4 million. The Company is not aware of any environmental claims existing as of September 30, 2017, that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

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.

In addition to the matters for which the Company has already accrued, 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. Apache believes that the claims made against it are baseless and intends to vigorously defend these lawsuits.

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 Viraciti Energy Pty Ltd, which has since been renamed Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. By letter dated June 6, 2016, Quadrant provided the Company with a placeholder notice of claim under the SPA concerning tax and other issues totaling approximately $200 million in the aggregate. The Company believes that these claims lack merit and intends to vigorously defend against them. Moreover, on September 22, 2017, subsidiaries of the Company filed suit against Quadrant for breaching the SPA and wrongfully withholding tax refunds owed under the SPA. This claim totals approximately $80 million AUD.

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CAPITAL STOCK

9 Months Ended

Sep. 30, 2017

Equity [Abstract]

CAPITAL STOCK

CAPITAL STOCK

Net Income (Loss) per Common Share

A reconciliation of the components of basic and diluted net income (loss) per common share for the quarters and nine months ended September 30, 2017 and 2016, is presented in the table below.

	For the Quarter Ended September 30,
	2017					2016
	Income		Shares	Per Share		Loss			Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) from continuing operations	$	63	381	$	0.16	$	(574	)	380	$	(1.51	)
Loss from discontinued operations	—		381	—		(33		)	380	(0.09		)
Income (loss) attributable to common stock	$	63	381	$	0.16	$	(607	)	380	$	(1.60	)
Effect of Dilutive Securities:
Stock options and other	$	—	2	$	—	$	—		—	$	—
Diluted:
Income (loss) from continuing operations	$	63	383	$	0.16	$	(574	)	380	$	(1.51	)
Loss from discontinued operations	—		383	—		(33		)	380	(0.09		)
Income (loss) attributable to common stock	$	63	383	$	0.16	$	(607	)	380	$	(1.60	)

	For the Nine Months Ended September 30,
	2017						2016
	Income		Shares	Per Share			Loss			Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) from continuing operations	$	848	381	$	2.23		$	(1,190	)	379	$	(3.14	)
Loss from discontinued operations	—		381	—			(33		)	379	(0.08		)
Income (loss) attributable to common stock	$	848	381	$	2.23		$	(1,223	)	379	$	(3.22	)
Effect of Dilutive Securities:
Stock options and other	$	—	2	$	(0.01	)	$	—		—	$	—
Diluted:
Income (loss) from continuing operations	$	848	383	$	2.22		$	(1,190	)	379	$	(3.14	)
Loss from discontinued operations	—		383	—			(33		)	379	(0.08		)
Income (loss) attributable to common stock	$	848	383	$	2.22		$	(1,223	)	379	$	(3.22	)

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 8.4 million and 4.7 million for the quarters ended September 30, 2017 and 2016, respectively, and 7.5 million and 6.5 million for the nine months ended September 30, 2017 and 2016, respectively.

Common Stock Dividends

For each of the quarters ended September 30, 2017, and 2016, Apache paid $95 million in dividends on its common stock. For the nine months ended September 30, 2017 and 2016, the Company paid $285 million and $284 million, 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 negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through September 30, 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.

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ACCUMULATED OTHER COMPREHENSIVE LOSS

9 Months Ended

Sep. 30, 2017

Equity [Abstract]

ACCUMULATED OTHER COMPREHENSIVE LOSS

ACCUMULATED OTHER COMPREHENSIVE LOSS

The following table describes changes to the Company’s accumulated other comprehensive loss by component for the nine-month period ended September 30, 2017:

	Currency Translation Adjustment			Pension and Postretirement Benefit Plan			Total
	(In millions)
Accumulated other comprehensive loss at December 31, 2016	$	(109	)	$	(3	)	$	(112	)
Currency translation adjustment divested(1)	109			—			109
Accumulated other comprehensive loss at September 30, 2017	$	—		$	(3	)	$	(3	)

(1) Currency translation adjustments resulting from translating the 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.

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BUSINESS SEGMENT INFORMATION

9 Months Ended

Sep. 30, 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 September 30, 2017, the Company had production in three reporting segments: the United States, Egypt, and offshore the United Kingdom 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. Financial information for each area is presented below:

	United States			Canada(1)			Egypt(2)		North Sea		Other International			Total
	(In millions)
For the Quarter Ended September 30, 2017
Oil and Gas Production Revenues	$	550		$	36		$	543	$	260	$	—		$	1,389
Operating Income (Loss)(3)	$	(114	)	$	(1	)	$	226	$	16	$	(1	)	$	126
Other Income (Expense):
Gain on divestitures, net														296
Derivative instrument losses, net														(110		)
General and administrative														(98		)
Transaction, reorganization, and separation														(20		)
Financing costs, net														(101		)
Income Before Income Taxes														$	93
For the Nine Months Ended September 30, 2017
Oil and Gas Production Revenues	$	1,593		$	231		$	1,655	$	768	$	—		$	4,247
Operating Income (Loss)(3)	$	(71	)	$	(33	)	$	740	$	59	$	(24	)	$	671
Other Income (Expense):
Gain on divestitures, net														616
Derivative instrument losses, net														(69		)
Other														43
General and administrative														(307		)
Transaction, reorganization, and separation														(14		)
Financing costs, net														(300		)
Income Before Income Taxes														$	640
Total Assets	$	13,105		$	—		$	4,906	$	3,770	$	54		$	21,835

	United States			Canada(1)			Egypt(2)		North Sea			Other International			Total
	(In millions)
For the Quarter Ended September 30, 2016
Oil and Gas Production Revenues	$	524		$	87		$	581	$	247		$	—		$	1,439
Operating Income (Loss)(4)	$	(17	)	$	(466	)	$	263	$	(455	)	$	(13	)	$	(688	)
Other Income (Expense):
Gain on divestitures, net															5
Other															(6		)
General and administrative															(102		)
Transaction, reorganization, and separation															(12		)
Financing costs, net															(102		)
Loss From Continuing Operations Before Income Taxes															$	(905	)
For the Nine Months Ended September 30, 2016
Oil and Gas Production Revenues	$	1,453		$	243		$	1,515	$	701		$	—		$	3,912
Operating Income (Loss)(4)	$	(283	)	$	(586	)	$	525	$	(557	)	$	(13	)	$	(914	)
Other Income (Expense):
Gain on divestitures, net															21
Other															(30		)
General and administrative															(298		)
Transaction, reorganization, and separation															(36		)
Financing costs, net															(311		)
Loss From Continuing Operations Before Income Taxes															$	(1,568	)
Total Assets	$	12,299		$	1,630		$	5,320	$	3,851		$	49		$	23,149

(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.

(3) Operating income (loss) consists of oil and gas production revenues less lease operating expenses, gathering and transportation costs, taxes other than income, exploration costs, depreciation, depletion, and amortization, asset retirement obligation accretion, and impairments. The operating income (loss) of U.S. includes leasehold impairments totaling $160 million for the third quarter of 2017. The operating income (loss) of U.S., Canada, and North Sea includes leasehold and other asset impairments totaling $212 million, $2 million, and $8 million, respectively, for the first nine months of 2017.

(4) The operating income (loss) of U.S., Canada, and North Sea includes leasehold, property, and other asset impairments totaling $46 million, $423 million, and $481 million, respectively, for the third quarter of 2016. The operating income (loss) of U.S., Canada, and North Sea includes leasehold, property, and other asset impairments totaling $212 million, $433 million, and $586 million, respectively, for the first nine months of 2016.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates with regard to these financial statements include the fair value determination of acquired assets and liabilities, the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, the assessment of asset retirement obligations, the estimates of fair value for long-lived assets and goodwill, and the estimate of income taxes. Actual results could differ from those estimates.

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).

Apache also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. The Company recorded no asset impairments in connection with fair value assessments in the third quarter of 2017. For the nine-month period ended September 30, 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 the first quarter of 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.

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 of exploratory wells and development costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.

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

When circumstances indicate that 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 the third quarters and first nine months of 2017 and 2016:

	Quarter Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(In millions)
Oil and Gas Property:
Proved	$	—	$	355	$	—	$	423
Unproved	160		114		214		222

Proved properties impaired during the second and third quarters of 2016 had aggregate fair values of $143 million and $163 million, respectively.

On the statement of consolidated operations, unproved impairments are recorded in exploration expense, and proved impairments are recorded in impairments.

Recently Adopted Accounting Pronouncements and New Pronouncements Issued But Not Yet Adopted

Recently Adopted Accounting Pronouncements

Stock Compensation

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.

Restricted Cash

In November 2016, the 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. Other than the change in presentation within the statement of consolidated cash flows, the adoption of ASU 2016-18 did not have an impact on the Company’s consolidated financial statements.

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheet to the amounts shown in the statement of consolidated cash flows:

	September 30, 2017		December 31, 2016
	(In millions)
Cash and cash equivalents	$	1,846	$	1,377
Restricted cash	96		—
Total cash, cash equivalents, and restricted cash shown in the statement of consolidated cash flows	$	1,942	$	1,377

For information regarding the restricted cash balance, please refer to Note 2—Acquisitions and Divestitures.

New Pronouncements Issued But Not Yet Adopted

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 U.S. 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. As part of the assessment to date, the Company has formed an implementation work team and is continuing to evaluate contracts to determine the impact this ASU will have on its consolidated financial statements. 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.

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 standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Company continues to make progress on evaluating the accounting implications of this ASU and its assessment of contracts with customers is largely complete. Based on the Company’s evaluation to date, it does not expect the adoption of this ASU to have a material impact on net earnings, however, the Company is analyzing whether the classification of certain items in revenue and expense will be impacted. The Company continues to evaluate the disclosure requirements, develop accounting policies, and assess changes to the relevant business processes and the control activities within them as a result of the provisions of this ASU. The Company will adopt the new standard on January 1, 2018, utilizing the modified retrospective approach.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

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 the third quarters and first nine months of 2017 and 2016:

	Quarter Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(In millions)
Oil and Gas Property:
Proved	$	—	$	355	$	—	$	423
Unproved	160		114		214		222

Schedule of cash, cash equivalents, and restricted cash

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheet to the amounts shown in the statement of consolidated cash flows:

	September 30, 2017		December 31, 2016
	(In millions)
Cash and cash equivalents	$	1,846	$	1,377
Restricted cash	96		—
Total cash, cash equivalents, and restricted cash shown in the statement of consolidated cash flows	$	1,942	$	1,377

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ACQUISITIONS AND DIVESTITURES ACQUISITIONS AND DIVESTITURES (Tables)

9 Months Ended

Sep. 30, 2017

Business Combinations [Abstract]

Summary of assets and liabilities at closing

The components of the Company’s loss from discontinued operations were as follows:

	For the Quarter Ended September 30,					For the Nine Months Ended September 30,
	2017		2016			2017		2016
	(In millions)
Loss from Australia divestiture	$	—	$	(23	)	$	—	$	(23	)
Loss from Argentina divestiture	—		(10		)	—		(10		)
Loss from discontinued operations, net of tax	$	—	$	(33	)	$	—	$	(33	)

A summary of the assets and liabilities at closing of the August transactions is detailed below:

	(In millions)
ASSETS
Current assets	$	110
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

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)

9 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of commodity derivative positions

As of September 30, 2017, Apache had the following open crude oil derivative positions:

		Put Options(1)(2)
Production Period	Settlement Index	Mbbls	Weighted Average Strike Price
October—December 2017	NYMEX WTI	8,464	$50.00
October—December 2017	Dated Brent	7,636	$51.00

(1) The remaining unamortized premium paid as of September 30, 2017, was $50 million.

(2) Subsequent to September 30, 2017, Apache entered into put option contracts settling against Dated Brent totaling 3,650 Mbbls with a strike price of $50 for the calendar year 2018.

		Fixed-Price Swaps		Collars(3)			Call Options(4)
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	—	—	6,023	$45.00	$57.02	6,023	$60.00

(3) Subsequent to September 30, 2017, Apache entered into crude oil contracts settling against NYMEX WTI totaling 730 Mbbls with a floor and ceiling of $45.00 and $56.90, respectively, for the calendar year 2018.

(4) The remaining unamortized premium paid as of September 30, 2017, was $9 million.

As of September 30, 2017, Apache had the following open natural gas derivative positions:

		Fixed-Price Swaps(1)
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Fixed Price
October—December 2017	NYMEX Henry Hub	4,370	$3.32
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	18,400	$2.97

(1) Subsequent to September 30, 2017, Apache entered into fixed-price natural gas swaps settling against NYMEX Henry Hub totaling 15,180,000 MMBtu with a weighted average fixed-price of $2.95 for the second half of 2018.

As of September 30, 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)
September 30, 2017
Assets:
Commodity Derivative Instruments	$	—	$	24	$	—	$	24	$	(7	)	$	17
Liabilities:
Commodity Derivative Instruments	—		7		—		7		(7		)	—
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)
September 30, 2017
Assets:
Commodity Derivative Instruments	$	—	$	24	$	—	$	24	$	(7	)	$	17
Liabilities:
Commodity Derivative Instruments	—		7		—		7		(7		)	—
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:

	September 30, 2017		December 31, 2016
	(In millions)
Current Assets: Prepaid assets and other	$	13	$	—
Other Assets: Deferred charges and other	4		—
Total Assets	$	17	$	—

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 Quarter Ended September 30,					For the Nine Months Ended September 30,
	2017			2016		2017			2016
	(In millions)
Realized gain (loss):
Derivative settlements, realized gain	$	23		$	—	$	23		$	—
Amortization of put premium, realized loss	(50		)	—		(50		)	—
Unrealized loss	(83		)	—		(42		)	—
Derivative instrument losses, net	$	(110	)	$	—	$	(69	)	$	—

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OTHER CURRENT LIABILITIES (Tables)

9 Months Ended

Sep. 30, 2017

Payables and Accruals [Abstract]

Detail of Other Current Liabilities

The following table provides detail of the Company’s other current liabilities as of September 30, 2017 and December 31, 2016:

	September 30, 2017		December 31, 2016
	(In millions)
Accrued operating expenses	$	73	$	110
Accrued exploration and development	691		463
Accrued compensation and benefits	99		201
Accrued interest	108		145
Accrued income taxes	68		22
Current asset retirement obligation	35		66
Refundable deposits	149		174
Other	109		77
Total other current liabilities	$	1,332	$	1,258

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ASSET RETIREMENT OBLIGATION (Tables)

9 Months Ended

Sep. 30, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the nine-month period ended September 30, 2017:

	(In millions)
Asset retirement obligation at December 31, 2016	$	2,498
Liabilities incurred	39
Liabilities divested	(810		)
Liabilities settled	(30		)
Accretion expense	103
Revisions in estimated liabilities	66
Asset retirement obligation at September 30, 2017	1,866
Less current portion	35
Asset retirement obligation, long-term	$	1,831

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DEBT AND FINANCING COSTS (Tables)

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Summary of Carrying Amounts and Estimated Fair Values

The following table presents the carrying amounts and estimated fair values of the Company’s outstanding debt as of September 30, 2017 and December 31, 2016:

	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Commercial paper and committed bank facilities	$	—	$	—	$	—	$	—
Notes and debentures	8,483		9,094		8,544		9,183
Total Debt	$	8,483	$	9,094	$	8,544	$	9,183

Schedule of Debt

The following table presents the carrying value of the Company’s debt as of September 30, 2017 and December 31, 2016:

	September 30, 2017			December 31, 2016
	(In millions)
Debt before unamortized discount and debt issuance costs	$	8,580		$	8,650
Unamortized discount	(48		)	(50		)
Debt issuance costs	(49		)	(56		)
Total debt	8,483			8,544
Current maturities	(550		)	—
Long-term debt	$	7,933		$	8,544

Components of Financing Costs, Net

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

	For the Quarter Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(In millions)
Interest expense	$	113		$	116		$	344		$	348
Amortization of deferred loan costs	3			2			7			5
Capitalized interest	(12		)	(13		)	(39		)	(36		)
Loss on extinguishment of debt	—			—			1			—
Interest income	(3		)	(3		)	(13		)	(6		)
Financing costs, net	$	101		$	102		$	300		$	311

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CAPITAL STOCK (Tables)

9 Months Ended

Sep. 30, 2017

Equity [Abstract]

Reconciliation of the components of basic and diluted net loss per common share

A reconciliation of the components of basic and diluted net income (loss) per common share for the quarters and nine months ended September 30, 2017 and 2016, is presented in the table below.

	For the Quarter Ended September 30,
	2017					2016
	Income		Shares	Per Share		Loss			Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) from continuing operations	$	63	381	$	0.16	$	(574	)	380	$	(1.51	)
Loss from discontinued operations	—		381	—		(33		)	380	(0.09		)
Income (loss) attributable to common stock	$	63	381	$	0.16	$	(607	)	380	$	(1.60	)
Effect of Dilutive Securities:
Stock options and other	$	—	2	$	—	$	—		—	$	—
Diluted:
Income (loss) from continuing operations	$	63	383	$	0.16	$	(574	)	380	$	(1.51	)
Loss from discontinued operations	—		383	—		(33		)	380	(0.09		)
Income (loss) attributable to common stock	$	63	383	$	0.16	$	(607	)	380	$	(1.60	)

	For the Nine Months Ended September 30,
	2017						2016
	Income		Shares	Per Share			Loss			Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) from continuing operations	$	848	381	$	2.23		$	(1,190	)	379	$	(3.14	)
Loss from discontinued operations	—		381	—			(33		)	379	(0.08		)
Income (loss) attributable to common stock	$	848	381	$	2.23		$	(1,223	)	379	$	(3.22	)
Effect of Dilutive Securities:
Stock options and other	$	—	2	$	(0.01	)	$	—		—	$	—
Diluted:
Income (loss) from continuing operations	$	848	383	$	2.22		$	(1,190	)	379	$	(3.14	)
Loss from discontinued operations	—		383	—			(33		)	379	(0.08		)
Income (loss) attributable to common stock	$	848	383	$	2.22		$	(1,223	)	379	$	(3.22	)

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ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables)

9 Months Ended

Sep. 30, 2017

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

The following table describes changes to the Company’s accumulated other comprehensive loss by component for the nine-month period ended September 30, 2017:

	Currency Translation Adjustment			Pension and Postretirement Benefit Plan			Total
	(In millions)
Accumulated other comprehensive loss at December 31, 2016	$	(109	)	$	(3	)	$	(112	)
Currency translation adjustment divested(1)	109			—			109
Accumulated other comprehensive loss at September 30, 2017	$	—		$	(3	)	$	(3	)

(1) Currency translation adjustments resulting from translating the 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.

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BUSINESS SEGMENT INFORMATION (Tables)

9 Months Ended

Sep. 30, 2017

Segment Reporting [Abstract]

Financial Segment Information

Financial information for each area is presented below:

	United States			Canada(1)			Egypt(2)		North Sea		Other International			Total
	(In millions)
For the Quarter Ended September 30, 2017
Oil and Gas Production Revenues	$	550		$	36		$	543	$	260	$	—		$	1,389
Operating Income (Loss)(3)	$	(114	)	$	(1	)	$	226	$	16	$	(1	)	$	126
Other Income (Expense):
Gain on divestitures, net														296
Derivative instrument losses, net														(110		)
General and administrative														(98		)
Transaction, reorganization, and separation														(20		)
Financing costs, net														(101		)
Income Before Income Taxes														$	93
For the Nine Months Ended September 30, 2017
Oil and Gas Production Revenues	$	1,593		$	231		$	1,655	$	768	$	—		$	4,247
Operating Income (Loss)(3)	$	(71	)	$	(33	)	$	740	$	59	$	(24	)	$	671
Other Income (Expense):
Gain on divestitures, net														616
Derivative instrument losses, net														(69		)
Other														43
General and administrative														(307		)
Transaction, reorganization, and separation														(14		)
Financing costs, net														(300		)
Income Before Income Taxes														$	640
Total Assets	$	13,105		$	—		$	4,906	$	3,770	$	54		$	21,835

	United States			Canada(1)			Egypt(2)		North Sea			Other International			Total
	(In millions)
For the Quarter Ended September 30, 2016
Oil and Gas Production Revenues	$	524		$	87		$	581	$	247		$	—		$	1,439
Operating Income (Loss)(4)	$	(17	)	$	(466	)	$	263	$	(455	)	$	(13	)	$	(688	)
Other Income (Expense):
Gain on divestitures, net															5
Other															(6		)
General and administrative															(102		)
Transaction, reorganization, and separation															(12		)
Financing costs, net															(102		)
Loss From Continuing Operations Before Income Taxes															$	(905	)
For the Nine Months Ended September 30, 2016
Oil and Gas Production Revenues	$	1,453		$	243		$	1,515	$	701		$	—		$	3,912
Operating Income (Loss)(4)	$	(283	)	$	(586	)	$	525	$	(557	)	$	(13	)	$	(914	)
Other Income (Expense):
Gain on divestitures, net															21
Other															(30		)
General and administrative															(298		)
Transaction, reorganization, and separation															(36		)
Financing costs, net															(311		)
Loss From Continuing Operations Before Income Taxes															$	(1,568	)
Total Assets	$	12,299		$	1,630		$	5,320	$	3,851		$	49		$	23,149

(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.

(3) Operating income (loss) consists of oil and gas production revenues less lease operating expenses, gathering and transportation costs, taxes other than income, exploration costs, depreciation, depletion, and amortization, asset retirement obligation accretion, and impairments. The operating income (loss) of U.S. includes leasehold impairments totaling $160 million for the third quarter of 2017. The operating income (loss) of U.S., Canada, and North Sea includes leasehold and other asset impairments totaling $212 million, $2 million, and $8 million, respectively, for the first nine months of 2017.

(4) The operating income (loss) of U.S., Canada, and North Sea includes leasehold, property, and other asset impairments totaling $46 million, $423 million, and $481 million, respectively, for the third quarter of 2016. The operating income (loss) of U.S., Canada, and North Sea includes leasehold, property, and other asset impairments totaling $212 million, $433 million, and $586 million, respectively, for the first nine months of 2016.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Detail) - USD ($)			3 Months Ended			9 Months Ended
	Jan. 01, 2016	Dec. 31, 2015	Sep. 30, 2017	Mar. 31, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016	Jun. 30, 2016
Schedule Of Significant Accounting Policies [Line Items]
Asset impairment charges			$ 0		$ 836,000,000	$ 8,000,000	$ 1,009,000,000
U.K. Petroleum Revenue Tax rate	0.00%	35.00%
Impairment of certain GTP assets							105,000,000
Oil and gas property, fair value					163,000,000		163,000,000		$ 143,000,000
Cash and cash equivalents			1,846,000,000			1,846,000,000		$ 1,377,000,000
Restricted cash			96,000,000			96,000,000		0
Total cash, cash equivalents, and restricted cash shown in the statement of consolidated cash flows		$ 1,467,000,000	1,942,000,000		1,230,000,000	1,942,000,000	1,230,000,000	1,377,000,000
Accounting Standards Update 2016-09, Excess Tax Benefit Component
Schedule Of Significant Accounting Policies [Line Items]
Deferred tax assets								4,000,000
Paid-In Capital | Accounting Standards Update 2016-09
Schedule Of Significant Accounting Policies [Line Items]
Cumulative effect of new accounting principle								11,000,000
Accumulated Deficit | Accounting Standards Update 2016-09
Schedule Of Significant Accounting Policies [Line Items]
Cumulative effect of new accounting principle								(11,000,000)
Accumulated Deficit | Accounting Standards Update 2016-09, Excess Tax Benefit Component
Schedule Of Significant Accounting Policies [Line Items]
Cumulative effect of new accounting principle								$ 4,000,000
Gas Gathering, Transmission, and Processing (GTP) Assets
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas property, fair value					175,000,000		175,000,000
Oil and Gas Properties, Proved
Schedule Of Significant Accounting Policies [Line Items]
Impairments for oil and gas properties			0		355,000,000	0	423,000,000
Oil and Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Impairments for oil and gas properties			$ 160,000,000		114,000,000	$ 214,000,000	222,000,000
Recoverable PRT Decommissioning Asset
Schedule Of Significant Accounting Policies [Line Items]
Asset impairment charges				$ 8,000,000
Impairments for oil and gas properties					481,000,000		481,000,000
Canada | Oil and Gas Properties, Proved
Schedule Of Significant Accounting Policies [Line Items]
Impairments for oil and gas properties					$ 355,000,000
US and Canada | Oil and Gas Properties, Proved
Schedule Of Significant Accounting Policies [Line Items]
Impairments for oil and gas properties							$ 423,000,000

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ACQUISITIONS AND DIVESTITURES - Additional Information (Detail) - USD ($) $ in Millions		1 Months Ended	3 Months Ended			9 Months Ended
	Jun. 30, 2017	Aug. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Business Acquisition [Line Items]
Refundable deposits for sale of non-core assets								$ 40
Gain on sale of non-core assets			$ 296		$ 5	$ 616	$ 21
Refundable deposits			149			149		$ 174
Leasehold and property acquisitions			75		51	142	169
Transaction, reorganization, and separation			20		12	14	36
Scottish Area Gas Evacuation System
Business Acquisition [Line Items]
Equity ownership percentage								30.28%
Beryl Pipeline
Business Acquisition [Line Items]
Equity ownership percentage								60.56%
Permian Region
Business Acquisition [Line Items]
Proceeds from sale of non-core assets						783
Gain on sale of non-core assets						594
Disposed of by sale | Midale and House Mountain
Business Acquisition [Line Items]
Gain (loss) recognized on sale				$ (52)
Disposed of by sale | Apache Canada Ltd. (ACL)
Business Acquisition [Line Items]
Proceeds from divestiture	$ 228	$ 478
Gain (loss) recognized on sale			74
Currency translation losses recorded in Accumulated Other Comprehensive Loss			109			109
Pretax losses from operations			$ 12		$ 483	$ 141	$ 644
Restricted Cash | Disposed of by sale | Apache Canada Ltd. (ACL)
Business Acquisition [Line Items]
Proceeds from divestiture		$ 96

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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, 2017 USD ($)
ASSETS
Current assets	$ 110
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

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ACQUISITIONS AND DIVESTITURES - Components of Loss from Discontinued Operations (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net loss from discontinued operations	$ 0	$ (33)	$ 0	$ (33)
Discontinued operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net loss from discontinued operations	0	(33)	0	(33)
Apache Australia Operation | Discontinued operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net loss from discontinued operations	0	(23)	0	(23)
Apache Argentina Operation | Discontinued operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net loss from discontinued operations	$ 0	$ (10)	$ 0	$ (10)

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Instruments (Detail) bbl in Thousands, $ in Millions	1 Months Ended	9 Months Ended
	Nov. 02, 2017 MMBTU $ / MMBTU $ / bbl bbl	Sep. 30, 2017 USD ($) MMBTU Counterparty $ / MMBTU $ / bbl bbl
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of derivative counterparties | Counterparty		14
Put Options | Crude Oil
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative remaining unamortized premium paid | $		$ 50
Put Options | October—December 2017 | Crude Oil | NYMEX WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume | bbl		8,464
Derivative, weighted average strike price (USD per bbl) | $ / bbl		50.00
Put Options | October—December 2017 | Crude Oil | Dated Brent
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume | bbl		7,636
Derivative, weighted average strike price (USD per bbl) | $ / bbl		51.00
Put Options | January—December 2018 | Crude Oil | Dated Brent | Subsequent Event
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume | bbl	3,650
Derivative, weighted average strike price (USD per bbl) | $ / bbl	50
Fixed-Price Swaps | October—December 2017 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU		4,370,000
Derivative, weighted average fixed price (USD per MMBtu)		3.32
Fixed-Price Swaps | January—June 2018 | Crude Oil | NYMEX WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume | 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		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, nonmonetary notional amount, energy measure | MMBTU		22,625,000
Derivative, weighted average fixed price (USD per MMBtu)		3.17
Fixed-Price Swaps | January - March 2018 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU		13,500,000
Derivative, weighted average fixed price (USD per MMBtu)		3.39
Fixed-Price Swaps | April—June 2018 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU		16,835,000
Derivative, weighted average fixed price (USD per MMBtu)		2.92
Fixed-Price Swaps | July - December 2018 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU		18,400,000
Derivative, weighted average fixed price (USD per MMBtu)		2.97
Fixed-Price Swaps | July - December 2018 | Natural Gas | NYMEX Henry Hub | Subsequent Event
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, weighted average fixed price (USD per MMBtu)	2.95
Fixed-Price Swaps | January—December 2018 | Natural Gas | NYMEX Henry Hub | Subsequent Event
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	15,180,000
Collars | January—June 2018 | Crude Oil | NYMEX WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume | bbl		2,715
Derivative, weighted average floor price (USD per bbl)		45.00
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		2,172
Derivative, weighted average floor price (USD per bbl)		50.00
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		6,023
Derivative, weighted average floor price (USD per bbl)		45.00
Derivative, weighted average ceiling price (USD per bbl)		57.02
Collars | January—December 2018 | Crude Oil | NYMEX WTI | Subsequent Event
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume | bbl	730
Derivative, weighted average floor price (USD per bbl)	45.00
Derivative, weighted average ceiling price (USD per bbl)	56.90
Call Options | Crude Oil
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative remaining unamortized premium paid | $		$ 9
Call Options | January—December 2018 | Crude Oil | NYMEX WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume | bbl		6,023
Derivative, weighted average strike price (USD per bbl) | $ / bbl		60.00
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		9,450,000
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		1,380,000
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		33,120,000
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		1,350,000
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		32,580,000
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		14,600,000
Weighted Average Price Differential		(0.45)

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities Measured at Fair Value (Details) - Commodity Derivative Instruments - Recurring - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative asset, fair value	$ 24	$ 0
Derivative asset, netting	(7)	0
Derivative asset	17	0
Derivative liability, fair value	7	0
Derivative liability, netting	(7)	0
Derivative liability	0	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	24	0
Derivative liability, fair value	7	0
Significant Unobservable Inputs (Level 3)
Derivative [Line Items]
Derivative asset, fair value	0	0
Derivative liability, fair value	$ 0	$ 0

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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	Sep. 30, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative asset	$ 17	$ 0
Current Assets: Prepaid assets and other
Derivatives, Fair Value [Line Items]
Derivative asset	13	0
Other Assets: Deferred charges and other
Derivatives, Fair Value [Line Items]
Derivative asset	$ 4	$ 0

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Activities Recorded in the Statement of Consolidated Operations (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Realized gain (loss):
Unrealized loss			$ (42)	$ 0
Not Designated as Hedging Instrument
Realized gain (loss):
Derivative settlements, realized gain	$ 23	$ 0	23	0
Amortization of put premium, realized loss	(50)	0	(50)	0
Unrealized loss	(83)	0	(42)	0
Derivative instrument losses, net	$ (110)	$ 0	$ (69)	$ 0

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CAPITALIZED EXPLORATORY WELL COSTS (Detail) - USD ($)	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Extractive Industries [Abstract]
Capitalized exploratory well costs	$ 369,000,000	$ 264,000,000
Capitalized exploratory well costs that have been capitalized for period greater than one year	$ 0

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OTHER CURRENT LIABILITIES (Detail) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Payables and Accruals [Abstract]
Accrued operating expenses	$ 73	$ 110
Accrued exploration and development	691	463
Accrued compensation and benefits	99	201
Accrued interest	108	145
Accrued income taxes	68	22
Current asset retirement obligation	35	66
Refundable deposits	149	174
Other	109	77
Total other current liabilities	$ 1,332	$ 1,258

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ASSET RETIREMENT OBLIGATION (Detail) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at the beginning of period	$ 2,498
Liabilities incurred	39
Liabilities divested	(810)
Liabilities settled	(30)
Accretion expense	103
Revisions in estimated liabilities	66
Asset retirement obligation at the end of period	1,866
Less current portion	35	$ 66
Asset retirement obligation, long-term	$ 1,831	$ 2,432

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INCOME TAXES (Detail) - USD ($) $ in Millions		3 Months Ended			9 Months Ended		12 Months Ended
	Jan. 01, 2016	Sep. 30, 2017	Jun. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2015
Income Tax Contingency [Line Items]
Deferred income tax expense (benefit)		$ (111)		$ (529)	$ (758)	$ (755)
Current tax benefit		30
North Sea
Income Tax Contingency [Line Items]
Deferred income tax expense (benefit)				$ (235)
Effective income tax rate	40.00%						50.00%
Apache Canada Ltd. (ACL) | Disposed of by sale
Income Tax Contingency [Line Items]
Deferred income tax expense (benefit)		$ 2	$ (674)

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DEBT AND FINANCING COSTS - Summary of Carrying Amounts and Estimated Fair Values (Detail) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument	$ 8,483	$ 8,544
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument	9,094	9,183
Notes and debentures | Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument	8,483	8,544
Notes and debentures | Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument	9,094	9,183
Commercial Paper | Commercial paper and committed bank facilities | Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument	0	0
Commercial Paper | Commercial paper and committed bank facilities | Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument	$ 0	$ 0

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DEBT AND FINANCING COSTS - Schedule of Debt (Detail) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term debt	$ 7,933	$ 8,544
Unsecured Debt
Debt Instrument [Line Items]
Debt before unamortized discount and debt issuance costs	8,580	8,650
Unamortized discount	(48)	(50)
Debt issuance costs	(49)	(56)
Total debt	8,483	8,544
Current maturities	(550)	0
Long-term debt	$ 7,933	$ 8,544

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DEBT AND FINANCING COSTS - Additional Information (Detail)	1 Months Ended	3 Months Ended			9 Months Ended
	Jan. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($) Contract	Sep. 30, 2016 USD ($)	Sep. 30, 2017 GBP (£)	Aug. 31, 2017 USD ($)	Nov. 30, 2016 USD ($)
Debt Instrument [Line Items]
Letters of credit outstanding, amount | £							£ 147,500,000
Loss on extinguishment of debt	$ 1,000,000	$ 0		$ 0	$ 1,000,000	$ 0
Commercial Paper
Debt Instrument [Line Items]
Debt instrument, face amount		3,500,000,000.0			$ 3,500,000,000.0
Debt instrument term					270 days
Letter of Credit
Debt Instrument [Line Items]
Number of debt instruments (in contracts) | Contract					3
Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity		3,500,000,000.0			$ 3,500,000,000.0
Credit Facility Matures in June 2020 | Letter of Credit
Debt Instrument [Line Items]
Line of credit amount		750,000,000			$ 750,000,000
Credit Facility Matures in June 2020 | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, number of extension options | Contract					2
Extended financing agreement term					1 year
Credit Facility Matures in February 2020 | Letter of Credit
Debt Instrument [Line Items]
Debt instrument, face amount | £							900,000,000
Credit facility maximum borrowing capacity | £							£ 1,075,000,000.000
Line of credit amount		0			$ 0
Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, face amount		8,580,000,000	$ 8,650,000,000		8,580,000,000
Unsecured Debt | 7% senior notes due February 1, 2018
Debt Instrument [Line Items]
Debt instrument, face amount		$ 150,000,000			$ 150,000,000
Debt instrument, stated interest rate		7.00%			7.00%		7.00%
Unsecured Debt | 6.9% senior notes due September 15, 2018
Debt Instrument [Line Items]
Debt instrument, face amount		$ 400,000,000			$ 400,000,000
Debt instrument, stated interest rate		6.90%			6.90%		6.90%
Senior Notes
Debt Instrument [Line Items]
Repurchased face amount of debt	69,000,000		181,000,000
Senior notes purchased and canceled	71,000,000		182,000,000
Debt instrument, premium amount	$ 1,000,000		$ 500,000
Senior Notes | 7.75% Senior Notes Due In 2029
Debt Instrument [Line Items]
Debt instrument, face amount								$ 300,000,000
Debt instrument, stated interest rate								7.75%
Maximum | Credit Facility Matures in June 2020 | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility aggregate commitment amount					$ 4,500,000,000.0
Maximum | Senior Notes
Debt Instrument [Line Items]
Repurchased face amount of debt									$ 250,000,000

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DEBT AND FINANCING COSTS - Components of Financing Costs, Net (Detail) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Jan. 31, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Debt Disclosure [Abstract]
Interest expense		$ 113	$ 116	$ 344	$ 348
Amortization of deferred loan costs		3	2	7	5
Capitalized interest		(12)	(13)	(39)	(36)
Loss on extinguishment of debt	$ 1	0	0	1	0
Interest income		(3)	(3)	(13)	(6)
Financing costs, net		$ 101	$ 102	$ 300	$ 311

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COMMITMENTS AND CONTINGENCIES (Detail) AUD in Millions	Jul. 17, 2017 Action Company	Mar. 21, 2016 USD ($)	Mar. 20, 2016 USD ($)	Sep. 30, 2017 USD ($)	Sep. 22, 2017 AUD	Jun. 06, 2016 USD ($)
Commitment And Contingencies [Line Items]
Accrued liability for legal contingencies				$ 37,000,000
Undiscounted reserve for environmental remediation				$ 4,000,000
Apollo Exploration Lawsuit
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages		$ 500,000,000
Apollo Exploration Lawsuit | Minimum
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages			$ 1,100,000,000.0
Damages as a result of global warning
Commitment And Contingencies [Line Items]
Number of separate litigation actions | Action	3
Number of defendants | Company	30
Australian Operations Divestiture Dispute | Australian Operations
Commitment And Contingencies [Line Items]
Divestiture of business, tax and other issues contingency amount						$ 200,000,000
Gain contingency, amount | AUD					AUD 80

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CAPITAL STOCK - Net Income (loss) Per Common Share (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Basic:
Income (loss) from continuing operations	$ 63	$ (574)	$ 848	$ (1,190)
Loss from discontinued operations	0	(33)	0	(33)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$ 63	$ (607)	$ 848	$ (1,223)
Income (loss) from continuing operations, shares	381	380	381	379
Loss from discontinued operations, shares	381	380	381	379
Income (loss) attributable to common stock, shares	381	380	381	379
Income (loss) from continuing operations (in USD per share)	$ 0.16	$ (1.51)	$ 2.23	$ (3.14)
Loss from discontinued operations (in USD per share)	0.00	(0.09)	0.00	(0.08)
Basic net income (loss) per share (in USD per share)	$ 0.16	$ (1.60)	$ 2.23	$ (3.22)
Effect of Dilutive Securities:
Stock options and other, shares	2		2
Stock options and other (in USD per share)			$ (0.01)
Diluted:
Income (loss) from continuing operations	$ 63	$ (574)	$ 848	$ (1,190)
Loss from discontinued operations	0	(33)	0	(33)
Income (loss) attributable to common stock	$ 63	$ (607)	$ 848	$ (1,223)
Income (loss) from continuing operations, shares	383	380	383	379
Loss from discontinued operations, shares	383	380	383	379
Income (loss) attributable to common stock, shares	383	380	383	379
Income (loss) from continuing operations (in USD per share)	$ 0.16	$ (1.51)	$ 2.22	$ (3.14)
Loss from discontinued operations (in USD per share)	0.00	(0.09)	0.00	(0.08)
Diluted net income (loss) per share (in USD per share)	$ 0.16	$ (1.60)	$ 2.22	$ (3.22)

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CAPITAL STOCK - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended		52 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017
Equity [Abstract]
Options and restricted stock, anti-dilutive	8,400,000	4,700,000	7,500,000	6,500,000
Dividends, common stock	$ 95	$ 95	$ 285	$ 284
Common stock, shares authorized for repurchase	40,000,000		40,000,000		40,000,000
Common stock share repurchase, shares					32,200,000
Common stock share repurchase average price (in USD per share)					$ 88.96

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ACCUMULATED OTHER COMPREHENSIVE LOSS (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning Balance	$ 7,679
Currency translation adjustment divested	109
Ending Balance	8,377
Currency Translation Adjustment
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning Balance	(109)
Currency translation adjustment divested	109
Ending Balance	0
Pension and Postretirement Benefit Plan
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning Balance	(3)
Currency translation adjustment divested	0
Ending Balance	(3)
Accumulated Other Comprehensive Loss
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning Balance	(112)
Ending Balance	$ (3)

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BUSINESS SEGMENT INFORMATION - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2017 Segment
Segment Reporting [Abstract]
Number of reporting segments	3

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BUSINESS SEGMENT INFORMATION - Financial Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Segment Reporting Information [Line Items]
Oil and Gas Production Revenues	$ 1,389	$ 1,439	$ 4,247	$ 3,912
Operating Income (Loss)	126	(688)	671	(914)
Other Income (Expense):
Gain on divestitures	296	5	616	21
Derivative instrument losses, net	(110)	0	(69)	0
Other		(6)	43	(30)
General and administrative	(98)	(102)	(307)	(298)
Transaction, reorganization, and separation	(20)	(12)	(14)	(36)
Financing costs, net	(101)	(102)	(300)	(311)
NET INCOME (LOSS) BEFORE INCOME TAXES	93	(905)	640	(1,568)
Total Assets	21,835	23,149	21,835	23,149	$ 22,519
Operating Segments | United States
Segment Reporting Information [Line Items]
Oil and Gas Production Revenues	550	524	1,593	1,453
Operating Income (Loss)	(114)	(17)	(71)	(283)
Other Income (Expense):
Total Assets	13,105	12,299	13,105	12,299
Asset impairments	160	46	212	212
Operating Segments | Canada
Segment Reporting Information [Line Items]
Oil and Gas Production Revenues	36	87	231	243
Operating Income (Loss)	(1)	(466)	(33)	(586)
Other Income (Expense):
Total Assets	0	1,630	0	1,630
Asset impairments		423	2	433
Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil and Gas Production Revenues	543	581	1,655	1,515
Operating Income (Loss)	226	263	740	525
Other Income (Expense):
Total Assets	4,906	5,320	4,906	5,320
Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil and Gas Production Revenues	260	247	768	701
Operating Income (Loss)	16	(455)	59	(557)
Other Income (Expense):
Total Assets	3,770	3,851	3,770	3,851
Asset impairments		481	8	586
Other International
Segment Reporting Information [Line Items]
Oil and Gas Production Revenues	0	0	0	0
Operating Income (Loss)	(1)	(13)	(24)	(13)
Other Income (Expense):
Total Assets	$ 54	$ 49	$ 54	$ 49