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, 2018

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, 2018 379,543,642

	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	23
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	35
4.	CONTROLS AND PROCEDURES	36
	PART II - OTHER INFORMATION
1.	LEGAL PROCEEDINGS	37
1A.	RISK FACTORS	37
2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	37
3.	DEFAULTS UPON SENIOR SECURITIES	37
4.	MINE SAFETY DISCLOSURES	37
5.	OTHER INFORMATION	37
6.	EXHIBITS	38

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, 2017, 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;

• pipeline and gathering system capacity;

• 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 2018 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,
	2018			2017			2018			2017
	(In millions, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues
Oil revenues	$	1,555		$	1,070		$	4,524		$	3,292
Natural gas revenues	241			238			675			726
Natural gas liquids revenues	180			81			446			229
	1,976			1,389			5,645			4,247
Derivative instrument losses, net	(23		)	(110		)	(46		)	(69		)
Gain on divestitures	1			296			10			616
Other	29			—			50			43
	1,983			1,575			5,659			4,837
OPERATING EXPENSES:
Lease operating expenses	382			353			1,087			1,059
Gathering, transmission, and processing	92			44			260			151
Taxes other than income	58			46			162			117
Exploration	99			231			251			431
General and administrative	99			98			330			307
Transaction, reorganization, and separation	8			20			20			14
Depreciation, depletion, and amortization:
Oil and gas property and equipment	575			524			1,666			1,598
Other assets	35			35			105			109
Asset retirement obligation accretion	27			30			81			103
Impairments	10			—			10			8
Financing costs, net	192			101			385			300
	1,577			1,482			4,357			4,197
NET INCOME BEFORE INCOME TAXES	406			93			1,302			640
Current income tax provision	262			99			709			413
Deferred income tax benefit	(17		)	(111		)	(43		)	(758		)
NET INCOME INCLUDING NONCONTROLLING INTEREST	161			105			636			985
Net income attributable to noncontrolling interest	80			42			215			137
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	81		$	63		$	421		$	848
NET INCOME PER COMMON SHARE:
Basic	$	0.21		$	0.16		$	1.10		$	2.23
Diluted	$	0.21		$	0.16		$	1.09		$	2.22
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	383			381			383			381
Diluted	385			383			385			383
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

(Unaudited)

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2018		2017		2018		2017
	(In millions)
NET INCOME INCLUDING NONCONTROLLING INTEREST	$	161	$	105	$	636	$	985
OTHER COMPREHENSIVE INCOME:
Currency translation adjustment	—		109		—		109
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTEREST	161		214		636		1,094
Comprehensive income attributable to noncontrolling interest	80		42		215		137
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$	81	$	172	$	421	$	957

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,
	2018			2017
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interest	$	636		$	985
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized derivative instrument (gain) loss, net	(88		)	42
Gain on divestitures	(10		)	(616		)
Exploratory dry hole expense and unproved leasehold impairments	133			350
Depreciation, depletion, and amortization	1,771			1,707
Asset retirement obligation accretion	81			103
Impairments	10			8
Deferred income tax benefit	(43		)	(758		)
Loss on extinguishment of debt	94			1
Other	147			166
Changes in operating assets and liabilities:
Receivables	(113		)	(70		)
Inventories	(7		)	17
Drilling advances	(22		)	(72		)
Deferred charges and other	91			(60		)
Accounts payable	110			2
Accrued expenses	(54		)	(65		)
Deferred credits and noncurrent liabilities	(2		)	20
NET CASH PROVIDED BY OPERATING ACTIVITIES	2,734			1,760
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(2,338		)	(1,471		)
Leasehold and property acquisitions	(86		)	(142		)
Additions to gas gathering, transmission, and processing facilities	(412		)	(384		)
Proceeds from sale of Canadian assets, net of cash divested	—			661
Proceeds from sale of oil and gas properties	51			743
Other, net	(55		)	(30		)
NET CASH USED IN INVESTING ACTIVITIES	(2,840		)	(623		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Fixed-rate debt borrowings	992			—
Payments on fixed-rate debt	(1,370		)	(70		)
Distributions to noncontrolling interest	(256		)	(212		)
Dividends paid	(287		)	(285		)
Other	(48		)	(5		)
NET CASH USED IN FINANCING ACTIVITIES	(969		)	(572		)
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS, AND RESTRICTED CASH	(1,075		)	565
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF YEAR	1,668			1,377
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	$	593		$	1,942
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	344		$	341
Income taxes paid, net of refunds	649			315

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, 2018			December 31, 2017
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	593		$	1,668
Receivables, net of allowance	1,457			1,345
Inventories	362			368
Drilling advances	229			207
Prepaid assets and other	144			137
	2,785			3,725
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of successful efforts accounting:
Proved properties	41,518			39,197
Unproved properties and properties under development	1,704			1,783
Gathering, transmission and processing facilities	1,742			1,376
Other	1,081			1,046
	46,045			43,402
Less: Accumulated depreciation, depletion, and amortization	(27,399		)	(25,643		)
	18,646			17,759
OTHER ASSETS:
Deferred charges and other	439			438
	$	21,870		$	21,922
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	744		$	641
Current debt	150			550
Other current liabilities (Note 5)	1,313			1,373
	2,207			2,564
LONG-TERM DEBT	8,053			7,934
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	502			545
Asset retirement obligation	1,867			1,792
Other	295			296
	2,664			2,633
COMMITMENTS AND CONTINGENCIES (Note 9)
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 415,660,982 and 414,125,879 shares issued, respectively	260			259
Paid-in capital	11,945			12,128
Accumulated deficit	(1,667		)	(2,088		)
Treasury stock, at cost, 34,092,692 and 33,171,015 shares, respectively	(2,930		)	(2,887		)
Accumulated other comprehensive income	4			4
APACHE SHAREHOLDERS’ EQUITY	7,612			7,416
Noncontrolling interest	1,334			1,375
TOTAL EQUITY	8,946			8,791
	$	21,870		$	21,922

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 Income (Loss)			APACHE SHAREHOLDERS’ EQUITY			Noncontrolling Interest			TOTAL EQUITY
	(In millions)
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
BALANCE AT DECEMBER 31, 2017	$	259	$	12,128		$	(2,088	)	$	(2,887	)	$	4		$	7,416		$	1,375		$	8,791
Net income	—		—			421			—			—			421			215			636
Distributions to noncontrolling interest	—		—			—			—			—			—			(256		)	(256		)
Common dividends ($0.75 per share)	—		(287		)	—			—			—			(287		)	—			(287		)
Other	1		104			—			(43		)	—			62			—			62
BALANCE AT SEPTEMBER 30, 2018	$	260	$	11,945		$	(1,667	)	$	(2,930	)	$	4		$	7,612		$	1,334		$	8,946

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, with the exception of recently adopted accounting pronouncements discussed below. 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 (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, 2017, which contains a summary of the Company’s significant accounting policies and other disclosures.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of September 30, 2018, 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, 2017, with the exception of Accounting Standards Update (ASU) 2014-09, “Revenue from Contracts with Customers (Topic 606)” (see “Revenue Recognition” section in this Note 1 below).

Use of Estimates

Preparation of financial statements in conformity with 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 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).

Recurring fair value measurements are presented in further detail in Note 4—Derivative Instruments and Hedging Activities and Note 8—Debt and Financing Costs.

Apache also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. For the third quarter and nine-month period ended September 30, 2018, the Company recorded asset impairments in connection with fair value assessments totaling $10 million. In the third quarter of 2018, Apache agreed to sell certain of its unproved properties offshore the U.K. in the North Sea (North Sea). As a result, the Company performed a fair value assessment of the properties and recorded a $10 million impairment on the carrying values of the associated capitalized exploratory well costs. The fair value of the impaired assets was determined using the negotiated sales price, a Level 1 fair value measurement.

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 in connection with fair value assessments

6

totaling $8 million for a United Kingdom (U.K.) Petroleum Revenue Tax (PRT) decommissioning asset that is no longer expected to be realizable from future abandonment activities in the North Sea.

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. 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

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

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

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

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

7

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 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 for the third quarters and first nine months of 2018 and 2017:

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2018		2017		2018		2017
	(In millions)
Oil and Gas Property:
Proved	$	—	$	—	$	—	$	—
Unproved	49		160		86		214

On the statement of consolidated operations, unproved leasehold impairments are recorded in exploration expense, and all other impairments of proved and unproved properties based on fair value assessments are recorded separately in impairments.

Revenue Recognition

On January 1, 2018, Apache adopted ASU 2014-09, “Revenue from Contracts with Customers (ASC 606),” using the modified retrospective method. The Company elected to evaluate all contracts at the date of initial application. While there was no impact to the opening balance of retained earnings as a result of the adoption, certain items previously netted in revenue are now recognized as “Gathering, transmission, and processing” in the Company’s statement of consolidated operations. The amounts reclassified are immaterial to the financial statements, and prior comparative periods have not been restated and continue to be reported under the accounting standards in effect for those periods. Adoption of the new standard is not anticipated to have a material impact on the Company’s net earnings on an ongoing basis.

The Company applies the provisions of ASC 606 for revenue recognition to contracts with customers. Sales of crude oil, natural gas, and NGLs are included in revenue when production is sold to a customer in fulfillment of performance obligations under the terms of agreed contracts. Performance obligations primarily comprise delivery of oil, gas, or NGLs at a delivery point, as negotiated within each contract. Each barrel of oil, million Btu (MMBtu) of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, the Company’s right to payment, and transfer of legal title. In each case, the term between delivery and when payments are due is not significant.

Apache markets its own United States (U.S.) natural gas and crude oil production based on market-priced contracts. Typically, these contracts are adjusted for quality, transportation, and other market-reflective differentials. Since the Company’s production may fluctuate as a result of operational issues, it is occasionally necessary to purchase third-party oil and gas to fulfill sales obligations and commitments. Sales proceeds related to third-party purchased oil and gas are determined to be revenue from a customer. Proceeds for these volumes totaled $124 million and $326 million for the third quarter and first nine months of 2018, respectively. Associated purchase costs for these volumes totaled $109 million and $308 million for the third quarter and first nine months of 2018, respectively. Proceeds and costs are both recorded as “Other” under “Revenues and Other” in the statement of consolidated operations.

Internationally, Apache sells its North Sea crude oil under contracts with a market-based index price. Natural gas from the North Sea Beryl field is processed through the SAGE gas plant. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. Apache’s gas production in Egypt is sold primarily under an industry-

8

pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. The Company’s Egypt oil production is sold at prices equivalent to the export market.

The Company’s Egyptian operations are conducted pursuant to production sharing contracts under which contractor partners pay all operating and capital costs for exploring and developing the concessions. A percentage of the production, generally up to 40 percent, is available to contractor partners to recover these operating and capital costs over contractually defined periods. The balance of the production is split among the contractor partners and the Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. Additionally, the contractor partner’s income taxes, which remain the liability of the contractor partners under domestic law, are paid by EGPC on behalf of the contractor partners out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of Apache as contract partner are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Revenues related to Egypt’s tax volumes are considered revenue from a non-customer.

For the third quarter of 2018, revenues from customers and non-customers were $1.9 billion and $198 million, respectively. For the first nine months of 2018, revenues from customers and non-customers were $5.4 billion and $534 million, respectively.

Apache records trade accounts receivable for its unconditional rights to consideration arising under sales contracts with customers. The carrying value of such receivables, net of the allowance for doubtful accounts, represents estimated net realizable value. The Company routinely assesses the collectability of all material trade and other receivables. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. Receivables from contracts with customers, net of allowance for doubtful accounts, totaled $1.3 billion and $1.1 billion as of September 30, 2018 and December 31, 2017, respectively.

Apache has concluded that disaggregating revenue by geographic area and by product appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. Refer to Note 11—Business Segment Information for a disaggregation of revenue by each product sold.

Practical Expedients and Exemptions

Apache does not disclose the value of unsatisfied performance obligations for contracts with an original expected length of one year or less or contracts for which variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

Apache will utilize the practical expedient to expense incremental costs of obtaining a contract if the expected amortization period is one year or less. Costs to obtain a contract with expected amortization periods of greater than one year will be recorded as an asset and will be recognized in accordance with ASC 340, “Other Assets and Deferred Costs.” Currently, the Company does not have contract assets related to incremental costs to obtain a contract.

New Pronouncements Issued But Not Yet Adopted

In February 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-02, “Leases (Topic 842),” requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous GAAP. The guidance is effective for fiscal years beginning after December 15, 2018. Early adoption is permitted; however, the Company does not intend to early adopt. In January 2018, the FASB issued ASU 2018-01, which permits an entity an optional election to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases prior to the adoption of ASU 2016-02. In July 2018, the FASB issued ASU 2018-11, which adds a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the consolidated financial statements. Under this transition option, comparative reporting would not be required, and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. Apache intends to elect both transitional practical expedients.

In the normal course of business, the Company enters into various lease agreements for real estate, aircraft, and equipment related to its exploration and development activities that are currently accounted for as operating leases. To track these lease arrangements and facilitate compliance with this ASU, the Company is in the process of implementing a third-party lease accounting software solution and designing processes and internal controls. The Company continues to evaluate contracts, train departments affected by the standard, and monitor updates to the standard 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.

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In June 2018, the FASB issued ASU 2018-07, “Improvements to Nonemployee Share-Based Payment Accounting,” to simplify the accounting for share-based transactions by expanding the scope of Topic 718 from only being applicable to share-based payments to employees to also include share-based payment transactions for acquiring goods and services from nonemployees. As a result, the same guidance that provides for employee share-based payments, including most of the requirements related to classification and measurement, applies to nonemployee share-based payment arrangements. ASU 2018-07 is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods. Early adoption is permitted. The Company anticipates adopting this guidance for the first quarter of 2019 and does not expect it to have a material impact on its consolidated financial statements.

In August 2018, the FASB issued ASU 2018-13, “Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement,” which changes the disclosure requirements for fair value measurements by removing, adding, and modifying certain disclosures. ASU 2018-13 is effective for financial statements issued for annual periods beginning after December 15, 2019, and interim periods within those annual periods. Early adoption is permitted. The company is currently evaluating the impact of adoption of this ASU on its related disclosures and does not expect it to have a material impact on its financial statements.

In August 2018, the FASB issued ASU 2018-14, “Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans,” which eliminates, modifies, and adds disclosure requirements for defined benefit plans. The ASU is effective for financial statements issued for fiscal years ending after December 15, 2020. Early adoption is permitted. The Company is currently evaluating the impact of adoption of this ASU on its related disclosures and does not expect it to have a material impact on its financial statements.

In August 2018, the FASB issued ASU 2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract.” This pronouncement clarifies the requirements for capitalizing implementation costs in cloud computing arrangements and aligns them with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. This pronouncement is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued. The Company is currently evaluating the impact of adoption of this ASU on its consolidated financial statements and does not expect it to have a material impact.

2. ACQUISITIONS AND DIVESTITURES

2018 Activity

U.S. Divestitures

On August 8, 2018, Apache and Kayne Anderson Acquisition Corp. (KAAC) announced an agreement pursuant to which Apache will contribute Apache’s Alpine High midstream assets into a newly formed limited partnership, Altus Midstream LP. Upon closing, KAAC will contribute to the partnership approximately $952 million in cash, less anticipated transaction expenses and any amount associated with potential KAAC share redemptions. The partnership will be jointly owned by Apache and KAAC. Apache will own an estimated 71 percent ownership interest in Altus Midstream LP, adjusted accordingly for any KAAC share redemptions, and expects to fully consolidate the entity in its consolidated financial statements, with the corresponding noncontrolling interest of third-party ownership reflected separately in the financial statements. The transaction is subject to approval by KAAC shareholders, as well as other customary closing conditions. Closing is expected in the fourth quarter of 2018. Upon closing, KAAC will be renamed Altus Midstream Company.

During the first nine months of 2018, Apache completed the sale of certain non-core assets, primarily in the Permian region, in multiple transactions for cash proceeds of $51 million. The Company recognized gains of approximately $10 million during the first nine months of 2018 upon the closing of these transactions.

Leasehold and Property Acquisitions

During the third quarter and first nine months of 2018, Apache completed $48 million and $86 million, respectively, of leasehold and property acquisitions primarily in its U.S. onshore and Egypt regions.

2017 Activity

Canada Divestitures

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.

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During the third quarter of 2017, Apache announced the sale of its subsidiary Apache Canada Ltd. (ACL) and complete exit of its Canadian operations for aggregate cash proceeds of approximately $478 million. The Company recognized a $74 million gain upon closing of these transactions in the third quarter of 2017.

A summary of the 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.

U.S. Divestitures

During the first nine months of 2017, Apache completed the sale of certain non-core assets, consisting primarily of 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.

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 U.S. onshore regions.

3.   CAPITALIZED EXPLORATORY WELL COSTS

The Company’s capitalized exploratory well costs were $300 million and $350 million at September 30, 2018 and December 31, 2017, respectively. The decrease is primarily attributable to successful transfers of well costs and dry hole write-offs, partially offset by additional drilling activities during the period. No suspended exploratory well costs previously capitalized for greater than one year at December 31, 2017 were charged to dry hole expense during the nine months ended September 30, 2018; however, during the third quarter of 2018, Apache announced an agreement to sell certain of its unproved properties in the North Sea. Exploratory well costs of approximately $70 million that have been capitalized greater than one year are included in the divestiture, which is anticipated to be completed prior to year-end.

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.

4.   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. Apache has elected not to designate any of its derivative contracts as cash flow hedges.

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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, 2018, Apache had derivative positions with 15 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, 2018, Apache had the following open crude oil derivative positions:

		Put Options(1)
Production Period	Settlement Index	Mbbls	Weighted Average Strike Price
October—December 2018	Dated Brent	3,680	$56.00
October—December 2018	NYMEX WTI	2,760	$53.00

(1) The remaining unamortized premium paid as of September 30, 2018, was $12 million.

		Collars			Call Options(2)
Production Period	Settlement Index	Mbbls	Weighted Average Floor Price	Weighted Average Ceiling Price	Mbbls	Strike Price
October—December 2018	NYMEX WTI	1,702	$45.00	$57.00	1,702	$60.03

(2) The remaining unamortized premium paid as of September 30, 2018, was $3 million.

As of September 30, 2018, Apache had the following open crude oil financial basis swap contracts:

Production Period	Settlement Index	Mbbls	Weighted Average Price Differential
October—December 2018	Midland-WTI/Cushing-WTI	1,380	$(9.23)
January—September 2019	Midland-WTI/Cushing-WTI	7,371	$(8.60)
October—December 2019	Midland-WTI/Cushing-WTI	1,380	$(3.72)

As of September 30, 2018, Apache had the following open natural gas derivative positions:

		Fixed-Price Swaps
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Fixed Price
October—December 2018	NYMEX Henry Hub	16,790	$2.96

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As of September 30, 2018, Apache had the following open natural gas financial basis swap contracts:

Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential
October—December 2018	NYMEX Henry Hub/Waha	17,940	$(0.53)
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, 2018
Assets:
Commodity Derivative Instruments	$	—	$	84	$	—	$	84	$	(36	)	$	48
Liabilities:
Commodity Derivative Instruments	—		41		—		41		(36		)	5
December 31, 2017
Assets:
Commodity Derivative Instruments	$	—	$	67	$	—	$	67	$	(43	)	$	24
Liabilities:
Commodity Derivative Instruments	—		107		—		107		(43		)	64

(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, 2018		December 31, 2017
	(In millions)
Current Assets: Prepaid assets and other	$	46	$	8
Other Assets: Deferred charges and other	2		16
Total Assets	$	48	$	24
Current Liabilities: Other current liabilities	$	4	$	64
Noncurrent Liabilities: Other	1		—
Total Liabilities	$	5	$	64

Derivative Activity Recorded in the Statement of Consolidated Operations

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

	For the Quarter Ended September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(In millions)
Realized gain (loss):
Derivative settlements	$	7		$	23		$	(110	)	$	23
Amortization of call and put premium	(14		)	(50		)	(24		)	(50		)
Unrealized gain (loss)	(16		)	(83		)	88			(42		)
Derivative instrument gain (losses), net	$	(23	)	$	(110	)	$	(46	)	$	(69	)

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

5. OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities as of September 30, 2018 and December 31, 2017:

	September 30, 2018		December 31, 2017
	(In millions)
Accrued operating expenses	$	79	$	72
Accrued exploration and development	660		680
Accrued gathering, transmission, and processing	67		122
Accrued compensation and benefits	147		115
Accrued interest	99		145
Accrued income taxes	89		55
Current asset retirement obligation	38		43
Other	134		141
Total other current liabilities	$	1,313	$	1,373

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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, 2018:

	(In millions)
Asset retirement obligation at December 31, 2017	$	1,835
Liabilities incurred	27
Liabilities settled	(39		)
Accretion expense	81
Revisions in estimated liabilities	1
Asset retirement obligation at September 30, 2018	1,905
Less current portion	(38		)
Asset retirement obligation, long-term	$	1,867

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7. INCOME TAXES

The Company estimates its annual effective income tax rate 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.

During the third quarter of 2018, Apache’s effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets. During the third quarter of 2017, Apache’s effective income tax rate was primarily impacted by gains on the sale of oil and gas properties, a $30 million current tax benefit associated with U.S. federal income tax credits, 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. For more information regarding the sale of ACL, please refer to Note 2—Acquisitions and Divestitures.

Apache’s 2018 year-to-date effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets. Apache’s 2017 year-to-date effective income tax rate was 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, the current tax benefit associated with U.S. federal income tax credits, and the sale of ACL.

On December 22, 2017, the Tax Cuts and Jobs Act (the Act) was signed into law. In 2018, the Internal Revenue Service (IRS) issued additional guidance related to the Act’s deemed repatriation of foreign earnings (i.e., transition inclusion). In light of this new guidance, the Company continues to reevaluate the tax impact of the transition inclusion in 2017. Tax benefit associated with the change in transition inclusion is likely to be fully offset by a change in the Company’s valuation allowance against its U.S. deferred tax assets. The Company has not revised any other 2017 provisional estimates under Staff Accounting Bulletin No. 118, but is continuing to gather information and awaits further guidance from the IRS, SEC and FASB on the Act.

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. The Company is currently under IRS audit for the 2014-2016 tax years and is also under audit in various states and foreign jurisdictions as part of its normal course of business.

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, 2018 and December 31, 2017:

	September 30, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Commercial paper and committed bank facilities	$	—	$	—	$	—	$	—
Notes and debentures	8,203		8,293		8,484		9,244
Total Debt	$	8,203	$	8,293	$	8,484	$	9,244

The Company’s debt is recorded at the carrying amount, net of related unamortized discount and deferred loan 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).

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The following table presents the carrying value of the Company’s debt as of September 30, 2018 and December 31, 2017:

	September 30, 2018			December 31, 2017
	(In millions)
Debt before unamortized discount and deferred loan costs	$	8,299		$	8,580
Unamortized discount	(45		)	(47		)
Debt issuance costs	(51		)	(49		)
Total debt	8,203			8,484
Current maturities	(150		)	(550		)
Long-term debt	$	8,053		$	7,934

As of September 30, 2018, current debt included $150 million of 7.625% senior notes due July 1, 2019. As of December 31, 2017, current debt included $150 million of 7.0% senior notes due February 1, 2018 that matured and were timely repaid and $400 million of 6.9% senior notes due September 15, 2018 that matured and were timely repaid.

On August 23, 2018, Apache closed an offering of $1.0 billion in aggregate principal amount of senior unsecured 4.375% notes due October 15, 2028. The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers, repay notes that matured in September 2018, and for general corporate purposes.

On August 24, 2018, the Company closed cash tender offers for certain outstanding notes. Apache accepted for purchase $731 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate of approximately $828 million reflecting principal, the discount to par, early tender premium, and accrued and unpaid interest. The Company recorded a net loss of $94 million on extinguishment of debt, including $5 million of unamortized debt issuance costs and discount, in connection with the note purchases.

In March 2018, the Company entered into a revolving credit facility that matures in March 2023 (subject to Apache’s two, one-year extension options) with commitments totaling $4.0 billion. The Company can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of September 30, 2018. The facility is for general corporate purposes and committed borrowing capacity fully supports Apache’s commercial paper program. As of September 30, 2018, letters of credit aggregating approximately £129.1 million and no borrowings were outstanding under this facility. In connection with entry into this facility, Apache terminated $3.5 billion and £900 million in commitments under two former credit facilities and wrote off $4 million of associated debt issuance costs, which is included in “Financing costs, net” in the Company’s consolidated statement of operations.

The Company’s $3.5 billion 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, 2018, the Company had no commercial paper outstanding.

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,
	2018			2017			2018			2017
	(In millions)
Interest expense	$	113		$	113		$	335		$	344
Amortization of deferred loan costs	2			3			8			7
Capitalized interest	(11		)	(12		)	(36		)	(39		)
Loss on extinguishment of debt	94			—			94			1
Interest income	(6		)	(3		)	(16		)	(13		)
Financing costs, net	$	192		$	101		$	385		$	300

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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, 2018, the Company has an accrued liability of approximately $39 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, 2017.

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, 2017.

Louisiana Restoration

As more fully described in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, Louisiana surface owners often file lawsuits or assert claims against oil and gas companies, including Apache, claiming that operators and working interest owners in the chain of title are liable for environmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to its original condition, regardless of the value of the underlying property. From time to time restoration lawsuits and claims are resolved by the Company for amounts that are not material to the Company, while new lawsuits and claims are asserted against the Company. With respect to each of the pending lawsuits and claims, the amount claimed is not currently determinable or is not material, except as noted. Further, the overall exposure related to these lawsuits and claims is not currently determinable. While an adverse judgment against Apache is possible, Apache intends to actively defend these lawsuits and claims.

Starting in November of 2013 and continuing into 2018, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including Apache. These cases have all been removed to federal court after having once been remanded back to state court. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. While 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, 2017.

Apollo Exploration Lawsuit

In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and areas of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The Court granted motions filed by Apache reducing the plaintiffs’ alleged damages to an amount that is not material to the Company. Apache believes that plaintiffs’ claims lack merit and 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, 2017.

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Australian Operations Divestiture Dispute

By a Sale and Purchase Agreement dated April 9, 2015 (SPA), the Company and its subsidiaries divested their remaining Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, Apache filed suit against Quadrant for breach of the SPA. In its suit, Apache seeks approximately $80 million. In December 2017, Quadrant filed a defense of equitable set-off to Apache’s claim and a counterclaim seeking approximately $200 million in the aggregate. The Company believes that Quadrant’s claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity.

California Litigation

On July 17, 2017, in three separate actions, San Mateo County, California, Marin County, California, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil, gas, and coal companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz, California and Santa Cruz County, California and in a separate action on January 22, 2018, the City of Richmond, California, filed similar lawsuits against many of the same defendants. The lawsuits were removed to federal court and then consolidated. Although the federal court remanded the lawsuits back to state court, it stayed its order of remand and certified the jurisdictional inquiry for appeal to the 9^th Circuit Court of Appeals. Apache believes that the claims made against it are baseless and intends to vigorously defend these lawsuits.

Environmental Matters

As of September 30, 2018, 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, 2018, that have not been provided for or that 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.

Commitments

During the third quarter of 2018, the Company executed a 10-year firm transportation agreement associated with the third-party Permian Highway Pipeline project to transport a minimum of 500,000 MMBtu per day at a fixed rate per MMBtu. The fees will commence when the pipeline accepts first commercial delivery, which is expected to begin service in late 2020, assuming timely receipt of regulatory approvals. Apache has entered into no other material commitments since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017.

10. CAPITAL STOCK

Net Income per Common Share

A reconciliation of the components of basic and diluted net income per common share for the quarters and nine months ended September 30, 2018 and 2017, is presented in the table below.

	For the Quarter Ended September 30,
	2018					2017
	Income		Shares	Per Share		Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	81	383	$	0.21	$	63	381	$	0.16
Effect of Dilutive Securities:
Stock options and other	$	—	2	$	—	$	—	2	$	—
Diluted:
Income attributable to common stock	$	81	385	$	0.21	$	63	383	$	0.16

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	For the Nine Months Ended September 30,
	2018						2017
	Income		Shares	Per Share			Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	421	383	$	1.10		$	848	381	$	2.23
Effect of Dilutive Securities:
Stock options and other	$	—	2	$	(0.01	)	$	—	2	$	(0.01	)
Diluted:
Income attributable to common stock	$	421	385	$	1.09		$	848	383	$	2.22

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 4.9 million and 8.4 million for the quarters ended September 30, 2018 and 2017, respectively, and 5.8 million and 7.5 million for the nine months ended September 30, 2018 and 2017, respectively.

Common Stock Dividends

For the quarters ended September 30, 2018 and 2017, Apache paid $96 million and $95 million, respectively, in dividends on its common stock. For the nine months ended September 30, 2018 and 2017, the Company paid $287 million and $285 million, respectively.

Stock Repurchase Program

In 2013 and 2014, Apache’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. Shares may be purchased either in the open market or through privately negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through September 30, 2018, had repurchased a total of 33.1 million shares at an average price of $87.77 per share. During the third quarter of 2018, the Company repurchased a total of 0.9 million shares at an average price of $46.38 per share. On October 30, 2018, the Company’s Board of Directors authorized the purchase of up to 40 million additional shares of the Company’s common stock. The Company is not obligated to acquire any specific number of shares.

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11. 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, 2018, the Company had production in three reporting segments: the U.S., Egypt, and offshore the U.K. in the 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(2,3)		North Sea		Other International			Total
	(In millions)
For the Quarter Ended September 30, 2018
Oil revenues	$	583	$	—	$	669	$	303	$	—		$	1,555
Natural gas revenues	125		—		86		30		—			241
Natural gas liquids revenues	171		—		4		5		—			180
Total Oil and Gas Production Revenues	$	879	$	—	$	759	$	338	$	—		$	1,976
Operating Income (Loss)(4)	$	147	$	—	$	438	$	114	$	(1	)	$	698
Other Income (Expense):
Gain on divestitures, net												1
Derivative instrument losses, net												(23		)
Other(5)												29
General and administrative												(99		)
Transaction, reorganization, and separation												(8		)
Financing costs, net												(192		)
Income Before Income Taxes												$	406
For the Nine Months Ended September 30, 2018
Oil revenues	$	1,743	$	—	$	1,887	$	894	$	—		$	4,524
Natural gas revenues	331		—		263		81		—			675
Natural gas liquids revenues	421		—		11		14		—			446
Total Oil and Gas Production Revenues	$	2,495	$	—	$	2,161	$	989	$	—		$	5,645
Operating Income (Loss)(4)	$	523	$	—	$	1,176	$	327	$	(3	)	$	2,023
Other Income (Expense):
Gain on divestitures, net												10
Derivative instrument losses, net												(46		)
Other(5)												50
General and administrative												(330		)
Transaction, reorganization, and separation												(20		)
Financing costs, net												(385		)
Income Before Income Taxes												$	1,302
Total Assets	$	14,389	$	—	$	4,404	$	3,033	$	44		$	21,870

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	United States			Canada(1)			Egypt(2)		North Sea		Other International			Total
	(In millions)
For the Quarter Ended September 30, 2017
Oil revenues	$	381		$	14		$	442	$	233	$	—		$	1,070
Natural gas revenues	97			19			98		24		—			238
Natural gas liquids revenues	72			3			3		3		—			81
Total Oil and Gas Production Revenues	$	550		$	36		$	543	$	260	$	—		$	1,389
Operating Income (Loss)(6)	$	(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 revenues	$	1,133		$	110		$	1,351	$	698	$	—		$	3,292
Natural gas revenues	266			104			295		61		—			726
Natural gas liquids revenues	194			17			9		9		—			229
Total Oil and Gas Production Revenues	$	1,593		$	231		$	1,655	$	768	$	—		$	4,247
Operating Income (Loss)(6)	$	(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

(1) Apache exited its Canadian operations in the third quarter of 2017.

(2) Includes a noncontrolling interest in Egypt.

(3) Includes revenue from non-customers of $181 million, $16 million, and $1 million for oil, natural gas, and natural gas liquids, respectively, for the third quarter of 2018, and $485 million, $47 million, and $2 million, for oil, natural gas, and natural gas liquids, respectively, for the first nine months of 2018.

(4) Operating income (loss) consists of oil and gas production revenues less lease operating expenses, gathering, transmission, and processing costs, taxes other than income, exploration costs, depreciation, depletion, and amortization, asset retirement obligation accretion, and impairments. The operating income of U.S. and North Sea includes leasehold and unproved impairments totaling $39 million and $10 million, respectively, for the third quarter of 2018. The operating income of U.S. and North Sea includes leasehold and unproved impairments totaling $76 million and $10 million, respectively, for the first nine months of 2018.

(5) Included in Other are sales proceeds related to U.S. third-party purchased oil and gas totaling $124 million and $326 million for the third quarter and first nine months of 2018, respectively, which are determined to be revenue from customers.

(6) 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.

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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, 2017.

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. Apache currently 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. In the third quarter of 2017, Apache completed the sale of its Canadian operations.

Apache reported third quarter net income of $81 million, or $0.21 per common share, an increase of $18 million, or $0.05 per common share, from the third quarter of 2017. The increase was driven by higher crude oil and natural gas liquid (NGL) price realizations and production, which more than offset the decrease related to a $296 million gain from asset sales benefiting the third quarter of 2017 and a $94 million charge for early extinguishment of debt in the third quarter of 2018.

Daily equivalent production in the third quarter of 2018 averaged 476 Mboe/d, an increase of 6 percent from the comparative prior-year quarter. Excluding asset divestitures, daily equivalent production increased12 percent driven by the activity in the Permian Basin, including continued development of the Company’s Alpine High field and infrastructure. Realized oil prices have been considerably higher than budgeted this year, particularly Dated Brent, which has provided increased operating cash flow to reinvest in the Company’s core development areas without a material impact on its balance sheet.

The Company generated $2.7 billion in cash from operating activities during the first nine months of 2018, a 55 percentincrease from the comparable prior-year period, and ended the quarter with $593 million of cash on hand. During the quarter, the Company took several steps to improve its debt portfolio: issuing $1.0 billion in aggregate principal amount of senior unsecured notes, concurrently repurchasing $731 million in aggregate principal amount of certain other outstanding notes, and paying off an additional $400 million of maturing debt in September. These transactions extended debt maturities, reduced the Company’s cost of debt, modernized its standard debenture terms, and, in conjunction with the repayment of $150 million of maturing debt in February, reduced debt by $281 million from 2017 year-end levels. During the quarter, the Company also re-initiated share repurchase activity under its existing authorization, which had 6.9 million shares remaining at the end of the quarter. In late October, the Company’s Board of Directors authorized the purchase of an additional 40 million shares of the Company’s common stock.

Apache achieved an important milestone during the third quarter with the announcement of Altus Midstream Company. This transaction enables Apache to maintain control of the midstream infrastructure buildout and establishes an entity capable of funding all future midstream investment at a lower cost of capital. For further information regarding this transaction, refer to “Operating Highlights” below.

Operating Highlights

Key operational highlights for the quarter include:

United States

• U.S. onshore equivalent production increased32 percent from the third quarter of 2017, a reflection of the success of the Midland Basin drilling program and the commencement and continued production ramp-up of the Company’s Alpine High development.

• Third-quarter equivalent production from the Permian region, which accounts for 82 percent of Apache’s total U.S. production, increased38 percent from the third quarter of 2017, driven by the Alpine High discovery and strong performance in the Midland Basin. Crude oil production in the region increased16 percent between the comparative quarters.

• In August 2018, the Company announced an agreement with Kayne Anderson Acquisition Corp. (KAAC) to create Altus Midstream Company (Altus Midstream).

◦ Upon closing of the transaction, KAAC will contribute approximately $952 million of cash, less anticipated transaction costs and any amount associated with potential shareholder redemptions, into a newly formed

23

limited partnership, Altus Midstream LP, for an approximate 29 percent noncontrolling interest, adjusted accordingly for any KAAC share redemptions. The cash will fund future development of the Alpine High midstream assets.

◦ Upon closing, Apache will contribute its Alpine High midstream assets, and Altus Midstream or its subsidiaries will hold options to acquire a noncontrolling equity participation in five planned long-haul pipelines from the Permian Basin to various points along the Texas Gulf Coast including the previously announced Gulf Coast Express, Salt Creek NGL Line, EPIC Crude, Shin Oak, and Permian Highway Pipeline projects.

◦ In exchange for such contributions, Apache will receive an approximate 71 percent controlling ownership interest in Altus Midstream, adjusted accordingly for any KAAC share redemptions.

◦ The transaction is subject to approval by KAAC shareholders, as well as other customary closing conditions. Closing is expected in the fourth quarter of 2018.

• 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 for the third quarter of 2018 averaged approximately 48.8 Mboe/d, up from 19.8 Mboe/d for the fourth quarter of 2017.

◦ During the third quarter of 2018, Apache invested $120 million in Alpine High infrastructure, with development ongoing. Inception-to-date investment in Alpine High infrastructure as of quarter-end was $1.1 billion.

International

• The Egypt region averaged 12 rigs and drilled or participated in drilling 26 gross wells during the third quarter of 2018. Gross production remained relatively flat and cash flows for the region increased compared to the third quarter of 2017 despite a 3 percent decrease in net equivalent production, a result of the impact of higher Brent oil prices on cost recovery volumes as a function of the Company’s production sharing contracts.

• The North Sea region average daily production decreased15 percent from the third quarter of 2017 primarily as a result of natural decline. Production is expected to increase in the fourth quarter, as the Company brought its fourth development well online in the Callater field in September and plans to accelerate initial production at Garten from the first quarter of 2019 to the fourth quarter of 2018, only seven months after its discovery.

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Results of Operations

Oil and Gas Revenues

The table below presents the third-quarter and year-to-date 2018 and 2017 revenues by geographic region and each region’s percent contribution to revenues.

	For the Quarter Ended September 30,								For the Nine Months Ended September 30,
	2018				2017				2018				2017
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution
	($ in millions)
Total Oil Revenues:
United States	$	583	37	%	$	381	36	%	$	1,743	39	%	$	1,133	35	%
Canada	—		—		14		1	%	—		—		110		3	%
North America	583		37	%	395		37	%	1,743		39	%	1,243		38	%
Egypt (1)	669		43	%	442		41	%	1,887		41	%	1,351		41	%
North Sea	303		20	%	233		22	%	894		20	%	698		21	%
International (1)	972		63	%	675		63	%	2,781		61	%	2,049		62	%
Total (1)	$	1,555	100	%	$	1,070	100	%	$	4,524	100	%	$	3,292	100	%
Total Natural Gas Revenues:
United States	$	125	52	%	$	97	41	%	$	331	49	%	$	266	37	%
Canada	—		—		19		8	%	—		—		104		14	%
North America	125		52	%	116		49	%	331		49	%	370		51	%
Egypt (1)	86		36	%	98		41	%	263		39	%	295		41	%
North Sea	30		12	%	24		10	%	81		12	%	61		8	%
International (1)	116		48	%	122		51	%	344		51	%	356		49	%
Total (1)	$	241	100	%	$	238	100	%	$	675	100	%	$	726	100	%
Total Natural Gas Liquids (NGL) Revenues:
United States	$	171	95	%	$	72	89	%	$	421	94	%	$	194	85	%
Canada	—		—		3		4	%	—		—		17		7	%
North America	171		95	%	75		93	%	421		94	%	211		92	%
Egypt (1)	4		2	%	3		4	%	11		3	%	9		4	%
North Sea	5		3	%	3		3	%	14		3	%	9		4	%
International (1)	9		5	%	6		7	%	25		6	%	18		8	%
Total (1)	$	180	100	%	$	81	100	%	$	446	100	%	$	229	100	%
Total Oil and Gas Revenues:
United States	$	879	44	%	$	550	40	%	$	2,495	44	%	$	1,593	38	%
Canada	—		—		36		2	%	—		—		231		5	%
North America	879		44	%	586		42	%	2,495		44	%	1,824		43	%
Egypt (1)	759		39	%	543		39	%	2,161		38	%	1,655		39	%
North Sea	338		17	%	260		19	%	989		18	%	768		18	%
International (1)	1,097		56	%	803		58	%	3,150		56	%	2,423		57	%
Total (1)	$	1,976	100	%	$	1,389	100	%	$	5,645	100	%	$	4,247	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 2018 and 2017 production and the relative increase or decrease from the prior period.

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2018	Increase (Decrease)		2017	2018	Increase (Decrease)		2017
Oil Volume – b/d
United States	103,538	14	%	90,883	102,830	15	%	89,228
Canada	—	NM		3,441	—	NM		8,881
North America	103,538	10	%	94,324	102,830	5	%	98,109
Egypt(1)(2)	97,129	4	%	93,749	96,201	(1	)%	97,447
North Sea	42,769	(14	)%	49,945	45,076	(9	)%	49,274
International	139,898	(3	)%	143,694	141,277	(4	)%	146,721
Total	243,436	2	%	238,018	244,107	—	%	244,830
Natural Gas Volume – Mcf/d
United States	651,782	61	%	404,486	563,299	49	%	378,625
Canada	—	NM		107,524	—	NM		175,787
North America	651,782	27	%	512,010	563,299	2	%	554,412
Egypt(1)(2)	331,681	(12	)%	378,426	338,813	(13	)%	389,533
North Sea	41,455	(17	)%	50,057	41,932	(2	)%	42,800
International	373,136	(13	)%	428,483	380,745	(12	)%	432,333
Total	1,024,918	9	%	940,493	944,044	(4	)%	986,745
NGL Volume – b/d
United States	60,239	23	%	49,149	56,886	18	%	48,063
Canada	—	NM		2,183	—	NM		3,780
North America	60,239	17	%	51,332	56,886	10	%	51,843
Egypt(1)(2)	753	(18	)%	916	939	2	%	917
North Sea	1,008	(17	)%	1,219	1,092	5	%	1,044
International	1,761	(18	)%	2,135	2,031	4	%	1,961
Total	62,000	16	%	53,467	58,917	10	%	53,804
BOE per day(3)
United States	272,406	31	%	207,447	253,599	27	%	200,396
Canada	—	NM		23,544	—	NM		41,959
North America	272,406	18	%	230,991	253,599	5	%	242,355
Egypt(2)	153,163	(3	)%	157,737	153,609	(6	)%	163,286
North Sea(4)	50,686	(15	)	59,507	53,157	(7	)%	57,451
International	203,849	(6	)%	217,244	206,766	(6	)%	220,737
Total	476,255	6	%	448,235	460,365	(1	)%	463,092

(1) Gross oil, natural gas, and NGL production in Egypt for the third quarter and nine-month period of 2018 and 2017 were as follows:

	For the Quarter Ended September 30,		For the Nine Months Ended September 30,
	2018	2017	2018	2017
Oil (b/d)	208,889	201,151	205,822	196,781
Natural Gas (Mcf/d)	766,128	818,350	775,405	813,880
NGL (b/d)	1,161	1,526	1,450	1,514

(2) Includes production volumes per day attributable to a noncontrolling interest in Egypt for the third quarter and nine-month period of 2018 and 2017 of:

	For the Quarter Ended September 30,		For the Nine Months Ended September 30,
	2018	2017	2018	2017
Oil (b/d)	32,385	31,275	32,077	32,573
Natural Gas (Mcf/d)	110,777	126,459	113,164	130,263
NGL (b/d)	251	305	313	306

(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 for the third quarter of 2018 and 2017 were 51,765 boe/d and 57,207 boe/d, respectively, and 53,985 boe/d and 57,963 boe/d for the first nine months of 2018 and 2017, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

NM — Not meaningful

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Pricing

The table below presents third-quarter and year-to-date 2018 and 2017 pricing and the relative increase or decrease from the prior period.

	For the Quarter Ended September 30,						For the Nine Months Ended September 30,
	2018		Increase (Decrease)		2017		2018		Increase (Decrease)		2017
Average Oil Price - Per barrel
United States	$	61.20	34	%	$	45.68	$	62.08	33	%	$	46.54
Canada	—		NM		42.23		—		NM		45.25
North America	61.20		34	%	45.56		62.08		34	%	46.42
Egypt	74.92		46	%	51.23		71.85		41	%	50.78
North Sea	75.01		41	%	53.11		71.32		39	%	51.35
International	74.95		44	%	51.87		71.68		41	%	50.97
Total	69.12		40	%	49.34		67.65		38	%	49.15
Average Natural Gas Price - Per Mcf
United States	$	2.09	(20	)%	$	2.62	$	2.15	(17	)%	$	2.58
Canada	—		NM		1.90		—		NM		2.17
North America	2.09		(15	)%	2.47		2.15		(12	)%	2.45
Egypt	2.85		1	%	2.81		2.85		3	%	2.77
North Sea	7.78		48	%	5.27		7.07		34	%	5.27
International	3.40		10	%	3.10		3.31		10	%	3.02
Total	2.56		(7	)%	2.75		2.62		(3	)%	2.70
Average NGL Price - Per barrel
United States	$	30.84	96	%	$	15.77	$	27.15	84	%	$	14.75
Canada	—		NM		15.80		—		NM		16.39
North America	30.84		96	%	15.77		27.15		83	%	14.87
Egypt	45.92		26	%	36.47		40.67		13	%	35.98
North Sea	54.73		103	%	26.92		47.16		55	%	30.51
International	50.96		64	%	31.02		44.16		34	%	33.07
Total	31.42		92	%	16.38		27.74		79	%	15.53

NM — Not meaningful

Third-Quarter 2018 compared to Third-Quarter 2017

Crude Oil Revenues Crude oil revenues for the third quarter of 2018 totaled $1.6 billion, a $485 millionincrease from the comparative 2017 quarter. A 40 percentincrease in average realized prices increased third-quarter 2018 revenues by $429 million compared to the prior-year quarter, while 2 percenthigher average daily production increased revenues by $56 million. Crude oil accounted for 79 percent of oil and gas production revenues and 51 percent of worldwide production in the third quarter of 2018. Crude oil prices realized in the third quarter of 2018 averaged $69.12 per barrel, compared with $49.34 per barrel in the comparative prior-year quarter.

Worldwide oil production increased 5.4 Mb/d to 243.4 Mb/d in the third quarter of 2018 from the comparative prior-year period, primarily a result of an increase in Apache’s Permian region on the success of the Midland and Delaware basin drilling programs, partially offset by a decrease from natural decline in the North Sea.

Natural Gas Revenues Gas revenues for the third quarter of 2018 totaled $241 million, a $3 millionincrease from the comparative 2017 quarter. A 7 percentdecrease in average realized prices decreased third-quarter revenues by $17 million compared to the prior-year quarter, while 9 percenthigher average daily production increased revenues by $20 million. Natural gas accounted for 12 percent of Apache’s oil and gas production revenues and 36 percent of its equivalent production during the third quarter of 2018.

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Worldwide natural gas production increased 84 MMcf/d to 1,025 MMcf/d in the third quarter of 2018 from the comparative prior-year period, primarily a result of an increase in Apache’s Permian region on the success of the Midland and Delaware basin drilling programs and the commencement of Alpine High production.

NGL Revenues NGL revenues for the third quarter of 2018 totaled $180 million, a $99 millionincrease from the comparative 2017 quarter. A 92 percentincrease in average realized prices increased third-quarter 2018 revenues by approximately $74 million compared to the prior-year quarter, while 16 percenthigher average daily production increased revenues by approximately $25 million. Approximately half of the increase in realized prices is the result of the reclassification of certain transportation charges from revenues to Gathering, Transmission, and Processing (GTP) expense as a result of the adoption of new revenue recognition accounting rules effective January 1, 2018. NGLs accounted for 9 percent of Apache’s oil and gas production revenues and 13 percent of its equivalent production during the third quarter of 2018.

Worldwide production of NGLs increased 8.5 Mb/d to 62.0 Mb/d in the third quarter of 2018 from the comparative prior-year period, primarily a result of the commencement of Alpine High production.

Year-to-Date 2018 compared to Year-to-Date 2017

Crude Oil Revenues Crude oil revenues for the first nine months of 2018 totaled $4.5 billion, a $1.2 billionincrease from the comparative 2017 period. A 38 percentincrease in average realized prices increased 2018 oil revenues by $1.2 billion compared to the prior-year period, while average daily production remained relatively flat. Crude oil accounted for 80 percent of oil and gas production revenues and 53 percent of worldwide production for the first nine months of 2018, compared to 78 percent and 53 percent, respectively, for the 2017 period. Crude oil prices realized in the first nine months of 2018 averaged $67.65 per barrel, compared with $49.15 per barrel in the comparative prior-year period.

Worldwide production decreased 0.7 Mb/d to 244.1 Mb/d in the first nine months of 2018 from the comparative prior-year period, primarily a result of a decrease from Apache’s exit from Canada, partially offset by an increase in its Permian region on the success of the Midland and Delaware basin drilling programs.

Natural Gas Revenues Gas revenues for the first nine months of 2018 totaled $675 million, a $51 milliondecrease from the comparative 2017 period. A 3 percentdecrease in average realized prices decreased 2018 natural gas revenues by $20 million compared to the prior-year period, while 4 percentlower average daily production decreased revenues by $31 million. Natural gas accounted for 12 percent of the Company’s oil and gas production revenues and 34 percent of Apache’s equivalent production for the first nine months of 2018, compared to 17 percent and 36 percent, respectively, for the 2017 period.

Worldwide natural gas production decreased 42.7 MMcf/d to 944 MMcf/d in the first nine months of 2018 from the comparative prior-year period, primarily a result of Apache’s exit from Canada, partially offset by an increase from Alpine High production.

NGL Revenues NGL revenues for the first nine months of 2018 totaled $446 million, a $217 millionincrease from the comparative 2017 period. A 79 percentincrease in average realized prices increased 2018 NGL revenues by $179 million compared to the prior-year period, while a 10 percentincrease in average daily production increased revenues by $38 million. The increase in realized prices is primarily the result of the reclassification of certain transportation charges from revenues to GTP expense as a result of the adoption of new revenue recognition rules effective January 1, 2018. NGLs accounted for nearly 8 percent of the Company’s oil and gas production revenues and 13 percent of Apache’s equivalent production for the first nine months of 2018, compared to 5 percent and 11 percent, respectively, for the 2017 period.

Worldwide production of NGLs increased5.1 Mb/d to 58.9 Mb/d in the first nine months of 2018 from the comparative prior-year period, primarily a result of an increase in Apache’s Permian region on the success of the Midland and Delaware basin drilling programs and the commencement of Alpine High production, more than offsetting a decrease from Apache’s exit from Canada.

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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,
	2018		2017		2018		2017		2018		2017		2018		2017
	(In millions)				(Per boe)				(In millions)				(Per boe)
Lease operating expenses(1)	$	382	$	353	$	8.69	$	8.62	$	1,087	$	1,059	$	8.63	$	8.37
Gathering, transmission, and processing(1)	92		44		2.10		1.03		260		151		2.06		1.19
Taxes other than income	58		46		1.31		1.12		162		117		1.29		0.93
Exploration	99		231		2.26		5.60		251		431		2.00		3.41
General and administrative	99		98		2.25		2.39		330		307		2.62		2.43
Transaction, reorganization, and separation	8		20		0.19		0.48		20		14		0.16		0.11
Depreciation, depletion, and amortization:
Oil and gas property and equipment(1)	575		524		13.10		12.76		1,666		1,598		13.23		12.63
Other assets	35		35		0.79		0.83		105		109		0.83		0.86
Asset retirement obligation accretion	27		30		0.62		0.75		81		103		0.64		0.82
Impairments	10		—		0.24		—		10		8		0.08		0.06
Financing costs, net	192		101		4.38		2.45		385		300		3.06		2.38

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

Lease Operating Expenses (LOE) LOE increased$29 million and $28 million for the third quarter and first nine months of 2018, respectively, on an absolute dollar basis relative to the comparable periods of 2017. On a per-unit basis, LOE increased1 percent to $8.69 per boe for the third quarter of 2018, and increased3 percent to $8.63 per boe for the first nine months of 2018 as compared to the prior-year periods. The increase on an absolute dollar basis for both comparative periods is primarily the result of general cost increases in a higher commodity price environment, partially offset by a decrease from the sale of Apache’s Canadian operations in the third quarter of 2017.

Gathering, Transmission, and Processing GTP costs totaled $92 million and $260 million in the third quarter and first nine months of 2018, respectively, an increase of $48 million from the third quarter of 2017 and $109 million from the first nine months of 2017. The increase is primarily the result of the reclassification of certain transportation charges from revenues to GTP expense as a result of the adoption of new revenue recognition accounting rules effective January 1, 2018, as well as the ramp-up of midstream operations at Alpine High, partially offset by Apache’s exit from Canada.

Taxes Other Than Income Taxes other than income totaled $58 million and $162 million for the third quarter and first nine months of 2018, an increase of $12 million and $45 million from the third quarter and first nine months of 2017, respectively. Third-quarter and year-to-date 2018 expense consists primarily of severance and ad valorem taxes, which combined increased $12 million and $30 million, respectively. The increase for both comparative periods is primarily the result of an increase in severance taxes on higher commodity prices and increased U.S. production driven by the ramp-up of operations at Alpine High. In addition, in the first nine months of 2017, Apache recognized a $14 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 2018decreased$132 million and $180 million, respectively, compared to the prior-year period.

The following table presents a summary of exploration expense:

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2018		2017		2018		2017
	(In millions)
Unproved leasehold impairments	$	39	$	160	$	76	$	214
Dry hole expense	21		38		57		136
Geological and geophysical expense	6		12		41		24
Exploration overhead and other	33		21		77		57
	$	99	$	231	$	251	$	431

Unproved leasehold impairments in the third quarter and first nine months of 2018decreased$121 million and $138 million, respectively, from the comparative prior-year periods, primarily a result of stabilizing commodity and leasehold prices. Dry hole expense decreased$17 million and $79 million in the third quarter and first nine months of 2018, respectively, from the comparative prior-year periods on lower exploration drilling activity. Geological and geophysical expense decreased$6 million and increased$17 million in the third quarter and first nine months of 2018, respectively, from the comparative prior-year periods. The increase in the first nine months of 2018 is primarily driven by 3-D seismic acquisition in Egypt for the Khalda Extension 3 and various other concessions.

General and Administrative (G&A) Expenses G&A expense for the third quarter and first nine months of 2018 were $1 million and $23 million higher than the comparative 2017 periods, respectively. The increase in G&A expense was primarily related to non-cash stock-based compensation expense, which was impacted by a change in vesting terms for certain retirement eligible employees.

Transaction, Reorganization, and Separation (TRS) Costs TRS costs for the third quarter of 2018 were $12 millionlower than the comparative 2017 period primarily a result of costs incurred during the third quarter of 2017 associated with the Canadian divestiture. TRS costs for the first nine months of 2018 were $6 millionhigher than the comparative 2017 period primarily a result of an increase in the market value of stock awards outstanding for former employees.

Depreciation, Depletion, and Amortization (DD&A) Oil and gas property DD&A expense of $575 million in the third quarter of 2018increased$51 million compared to the third quarter of 2017. For the first nine months of 2018, oil and gas property DD&A expense increased$68 million compared to the prior-year period. The Company’s oil and gas property DD&A rate increased$0.34 per boe and $0.60 per boe in the third quarter and first nine months of 2018, respectively, compared to the comparable prior-year periods. The primary factor driving higher absolute dollar expense was an increase in capital spending primarily in the Permian and Alpine High regions as a result of drilling and development activity. The increase on an absolute dollar basis was partially offset by the sale of Apache’s Canadian operations in the third quarter of 2017.

Impairments The Company recorded asset impairments totaling $10 million for each of the third quarter and first nine months of 2018 in connection with fair value assessments on North Sea unproved assets to be divested. The Company did not record any asset impairments in the third quarter of 2017. For the nine-month period ended September 30, 2017, the Company recorded asset impairments 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. 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,
	2018			2017			2018			2017
	(In millions)
Interest expense	$	113		$	113		$	335		$	344
Amortization of deferred loan costs	2			3			8			7
Capitalized interest	(11		)	(12		)	(36		)	(39		)
Loss on extinguishment of debt	94			—			94			1
Interest income	(6		)	(3		)	(16		)	(13		)
Financing costs, net	$	192		$	101		$	385		$	300

Net financing costs increased$91 million and $85 million in the third quarter and first nine months of 2018, respectively, compared to the same prior-year periods primarily a result of a $94 million loss on extinguishment of debt incurred in the third quarter of 2018.

Provision for Income Taxes The Company estimates its annual effective income tax rate 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.

During the third quarter of 2018, Apache’s effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets. During the third quarter of 2017, Apache’s effective income tax rate was primarily impacted by gains on the sale of oil and gas properties, a $30 million current tax benefit associated with U.S. federal income tax credits, a deferred tax asset associated with its realizable capital loss on the sale of Apache Canada Ltd. (ACL), and a decrease in the Company’s deferred tax liability associated with its investment in foreign subsidiaries. For more information regarding the sale of ACL, please refer to Note 2—Acquisitions and Divestitures.

Apache’s 2018 year-to-date effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets. Apache’s 2017 year-to-date effective income tax rate was 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, the current tax benefit associated with U.S. federal income tax credits, and the sale of ACL.

Apache recorded a full valuation allowance against its U.S. net deferred tax assets as of December 31, 2017. Apache will continue to maintain a full valuation allowance on its U.S. net deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance. However, given our current earnings and anticipated future earnings, we believe that there is a reasonable possibility that within the next 12 months, sufficient positive evidence may become available to allow us to reach a conclusion that a significant portion of the valuation allowance will no longer be needed. Release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to deferred income tax expense for the period the release is recorded. However, the exact timing and amount of the valuation allowance release are subject to change on the basis of the level of profitability that we are able to actually achieve.

On December 22, 2017, the Tax Cuts and Jobs Act (the Act) was signed into law. In 2018, the Internal Revenue Service (IRS) issued additional guidance related to the Act’s deemed repatriation of foreign earnings (i.e., transition inclusion). In light of this new guidance, the Company continues to reevaluate the tax impact of the transition inclusion in 2017. Tax benefit associated with the change in transition inclusion is likely to be fully offset by a change in the Company’s valuation allowance against its U.S. deferred tax assets. The Company has not revised any other 2017 provisional estimates under Staff Accounting Bulletin No. 118, but is continuing to gather information and awaits further guidance from the IRS, SEC and FASB on the Act.

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. The Company is currently under IRS audit for the 2014-2016 tax years and is also under audit in various states and foreign jurisdictions as part of its normal course of business.

31

Capital Resources and Liquidity

Operating cash flows are the Company’s primary source of liquidity. The Company may also elect to utilize available cash on hand, 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 on 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.

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, any repurchases of shares of the Company’s common stock, 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 year ended December 31, 2017.

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,
	2018			2017
	(In millions)
Sources of Cash, Cash Equivalents, and Restricted Cash:
Net cash provided by operating activities	$	2,734		$	1,760
Proceeds from sale of oil and gas properties	51			1,404
Fixed-rate debt borrowings	992			—
	3,777			3,164
Uses of Cash, Cash Equivalents, and Restricted Cash:
Capital expenditures(1)	$	2,750		$	1,855
Leasehold and property acquisitions	86			142
Payments on fixed-rate debt	1,370			70
Dividends paid	287			285
Distributions to noncontrolling interest	256			212
Other	103			35
	4,852			2,599
Increase (decrease) in cash, cash equivalents, and restricted cash	$	(1,075	)	$	565

(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.

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 flows 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.

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Net cash provided by operating activities for the first nine months of 2018 totaled $2.7 billion, an increase of $974 million from the first nine months of 2017. 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 Part I, Item 1, Financial Statements of this Quarterly Report on Form 10-Q.

Asset Divestitures The Company recorded proceeds from asset divestitures totaling $51 million and $1.4 billion in the first nine months of 2018 and 2017, 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.

Fixed-Rate Debt Borrowings On August 23, 2018, Apache closed an offering of $1.0 billion in aggregate principal amount of senior unsecured 4.375% notes due October 15, 2028. The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The net proceeds from the sale of the notes of $992 million were used to purchase certain outstanding notes in cash tender offers, repay notes that matured in September 2018, and for general corporate purposes.

Capital Expenditures Worldwide exploration and development (E&D) cash expenditures for the first nine months of 2018 totaled $2.3 billion, compared to $1.5 billion for the first nine months of 2017. Expenditures for the first nine months of 2018 were primarily in the Permian region as Apache continued development of its Alpine High play. Apache operated an average of 33 drilling rigs worldwide during the third quarter of 2018.

Apache’s cash expenditures in GTP facilities totaled $412 million and $384 million in the first nine months of 2018 and 2017, respectively, and are primarily comprised of investments in infrastructure for the Alpine High play. Cash from the Altus Midstream transaction is expected to fund future development of the Company’s Alpine High midstream assets upon anticipated closing of the transaction in the fourth quarter of 2018.

Leasehold and Property Acquisitions Apache completed leasehold and property acquisitions for cash consideration totaling $86 million and $142 million during the first nine months of 2018 and 2017, respectively.

Payments on Fixed-Rate Debt On August 24, 2018, the Company closed cash tender offers for certain outstanding notes. Apache accepted for purchase $731 million aggregate principal amount of notes for approximately $828 million, which included principal, the discount to par, and an early tender premium totaling $820 million, as well as accrued and unpaid interest of $8 million. The Company recorded a net loss of $94 million on extinguishment of debt, including $5 million of unamortized debt issuance costs and discount, in connection with the note purchases.

Apache also made repayments of current year note maturities totaling $550 million during the first nine months of 2018.

Dividends The Company paid $287 million and $285 million in dividends on its common stock for the nine-month periods ended September 30, 2018 and 2017, respectively.

33

Liquidity

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

	September 30, 2018		December 31, 2017
	(In millions)
Cash and cash equivalents	$	593	$	1,668
Total debt	8,203		8,484
Equity	8,946		8,791
Available committed borrowing capacity	3,832		3,500

Cash and cash equivalents The Company had $593 million in cash and cash equivalents as of September 30, 2018, compared to $1.7 billion at December 31, 2017. 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.

Debt As of September 30, 2018, outstanding debt, which consisted of unsecured notes and debentures, totaled $8.2 billion. Current debt as of September 30, 2018, included $150 million of 7.625% senior notes due July 1, 2019.

On August 23, 2018, Apache closed an offering of $1.0 billion in aggregate principal amount of senior unsecured 4.375% notes due October 15, 2028. The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers, repay notes that matured in September 2018, and for general corporate purposes.

In March 2018, the Company entered into a revolving credit facility that matures in March 2023 (subject to Apache’s two, one-year extension options) with commitments totaling $4.0 billion. The Company can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of September 30, 2018. The facility is for general corporate purposes and committed borrowing capacity fully supports Apache’s commercial paper program. As of September 30, 2018, letters of credit aggregating approximately £129.1 million and no borrowings were outstanding under this facility. In connection with entry into this facility, Apache terminated $3.5 billion and £900 million in commitments under two former credit facilities and wrote off $4 million of associated debt issuance costs, which is included in “Financing costs, net” in the Company’s consolidated statement of operations.

The Company’s $3.5 billion 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, 2018, the Company had no commercial paper outstanding.

The Company was in compliance with the terms of its credit facilities as of September 30, 2018.

Equity During the third quarter of 2018, the Company re-initiated share repurchase activity under its existing authorization, which had 6.9 million shares remaining at the end of the quarter. On October 30, 2018, the Company’s Board of Directors authorized the purchase of up to 40 million additional shares of the Company’s common stock. The Company is not obligated to acquire any specific number of shares.

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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 increased 40 percent to $69.12 per barrel in the third quarter of 2018 from $49.34 per barrel in the comparable period of 2017. The Company’s average natural gas price realizations have decreased 7 percent to $2.56 per Mcf in the third quarter of 2018 from $2.75 per Mcf in the comparable period of 2017. Based on average daily production for the third quarter of 2018, 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 periodically uses futures contracts, swaps, and options to mitigate commodity price risk. Apache does not hold or issue derivative instruments for trading purposes. As of September 30, 2018, the Company had open natural gas derivatives not designated as cash flow hedges in an asset position with a fair value of $61 million. A 10 percent increase in gas prices would decrease the asset by approximately $7 million, while a 10 percent decrease in prices would increase the asset by approximately $7 million. As of September 30, 2018, the Company had open oil derivatives not designated as cash flow hedges in a liability position with a fair value of $18 million. A 10 percent increase in oil prices would decrease the liability by approximately $7 million, while a 10 percent decrease in prices would increase the liability by approximately $6 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2018. See Note 4—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q for notional volumes and terms 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 $2 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of September 30, 2018.

35

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, 2018, 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, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

36

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, 2017 (filed with the SEC on February 23, 2018) 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, 2017, 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, 2017.

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

The following table presents information on shares of common stock repurchased by the Company during the quarter ended September 30, 2018:

Issuer Purchases of Equity Securities
Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs(1)
July 1 to July 31, 2018	—	$	—	—	7,827,352
August 1 to August 31, 2018	—	—		—	7,827,352
September 1 to September 30, 2018	924,131	46.38		924,131	6,903,221
Total	924,131	$	46.38

(1) On May 9, 2013, the Company announced that its Board of Directors authorized the repurchase of up to 30 million shares of the Company’s common stock. Additionally, on May 15, 2014, the Company announced that the Board of Directors authorized the repurchase of an additional 10 million shares, supplementing the May 2013 authorization. The Company may buy shares from time to time on the open market, in privately negotiated transactions, or a combination of both. The timing and amounts of any repurchases will be at the discretion of Apache’s management and will depend on a variety of factors, including the stock price, corporate and regulatory requirements, and other market and economic conditions. Repurchased shares will be available for general corporate purposes. On October 30, 2018, the Company’s Board of Directors authorized the purchase of up to 40 million additional shares of the Company’s common stock.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4. MINE SAFETY DISCLOSURES

None

ITEM 5. OTHER INFORMATION

None

37

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	–	Indenture, dated August 14, 2018, by and between Apache Corporation and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.5 to Registrant’s Post-Effective Amendment No. 1 to Form S-3 Registration Statement filed August 14, 2018, SEC File No. 333-219345).
*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.

38

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 1, 2018	/s/ STEPHEN J. RINEY
		Stephen J. Riney
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)
Dated:	November 1, 2018	/s/ REBECCA A. HOYT
		Rebecca A. Hoyt
		Senior Vice President, Chief Accounting Officer, and Controller
		(Principal Accounting Officer)

39

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 1, 2018

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 1, 2018

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, 2018, 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 1, 2018

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, 2018, 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 1, 2018

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 31, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2018
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 Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding		379,543,642

XML

STATEMENT OF CONSOLIDATED OPERATIONS (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
REVENUES AND OTHER:
Oil and gas production revenues	$ 1,976	$ 1,389	$ 5,645	$ 4,247
Derivative instrument gains (losses), net	(23)	(110)	(46)	(69)
Gain on divestitures	1	296	10	616
Other	29	0	50	43
Revenues	1,983	1,575	5,659	4,837
OPERATING EXPENSES:
Lease operating expenses	382	353	1,087	1,059
Gathering, transmission, and processing	92	44	260	151
Taxes other than income	58	46	162	117
Exploration	99	231	251	431
General and administrative	99	98	330	307
Transaction, reorganization, and separation	8	20	20	14
Depreciation, depletion and amortization			1,771	1,707
Asset retirement obligation accretion	27	30	81	103
Impairments	10	0	10	8
Financing costs, net	192	101	385	300
Total operating expenses	1,577	1,482	4,357	4,197
NET INCOME BEFORE INCOME TAXES	406	93	1,302	640
Current income tax provision	262	99	709	413
Deferred income tax benefit	(17)	(111)	(43)	(758)
NET INCOME INCLUDING NONCONTROLLING INTEREST	161	105	636	985
Net income attributable to noncontrolling interest	80	42	215	137
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$ 81	$ 63	$ 421	$ 848
NET INCOME PER COMMON SHARE:
Basic (in USD per share)	$ 0.21	$ 0.16	$ 1.10	$ 2.23
Diluted (in USD per share)	$ 0.21	$ 0.16	$ 1.09	$ 2.22
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic (in shares)	383	381	383	381
Diluted (in shares)	385	383	385	383
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	$ 575	$ 524	$ 1,666	$ 1,598
Other assets
OPERATING EXPENSES:
Depreciation, depletion and amortization	35	35	105	109
Oil
REVENUES AND OTHER:
Oil and gas production revenues	1,555	1,070	4,524	3,292
Natural Gas
REVENUES AND OTHER:
Oil and gas production revenues	241	238	675	726
Natural gas liquids
REVENUES AND OTHER:
Oil and gas production revenues	$ 180	$ 81	$ 446	$ 229

XML

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
NET INCOME INCLUDING NONCONTROLLING INTEREST	$ 161	$ 105	$ 636	$ 985
OTHER COMPREHENSIVE INCOME:
Currency translation adjustment	0	109	0	109
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTEREST	161	214	636	1,094
Comprehensive income attributable to noncontrolling interest	80	42	215	137
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$ 81	$ 172	$ 421	$ 957

XML

STATEMENT OF CONSOLIDATED CASH FLOWS (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interest	$ 636	$ 985
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized derivative instrument (gain) loss, net	(88)	42
Gain on divestitures	(10)	(616)
Exploratory dry hole expense and unproved leasehold impairments	133	350
Depreciation, depletion, and amortization	1,771	1,707
Asset retirement obligation accretion	81	103
Impairments	10	8
Deferred income tax benefit	(43)	(758)
Loss on extinguishment of debt	94	1
Other	147	166
Changes in operating assets and liabilities:
Receivables	(113)	(70)
Inventories	(7)	17
Drilling advances	(22)	(72)
Deferred charges and other	91	(60)
Accounts payable	110	2
Accrued expenses	(54)	(65)
Deferred credits and noncurrent liabilities	(2)	20
NET CASH PROVIDED BY OPERATING ACTIVITIES	2,734	1,760
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(2,338)	(1,471)
Leasehold and property acquisitions	(86)	(142)
Additions to gas gathering, transmission, and processing facilities	(412)	(384)
Proceeds from sale of Canadian assets, net of cash divested	0	661
Proceeds from sale of oil and gas properties	51	743
Other, net	(55)	(30)
NET CASH USED IN INVESTING ACTIVITIES	(2,840)	(623)
CASH FLOWS FROM FINANCING ACTIVITIES:
Fixed-rate debt borrowings	992	0
Payments on fixed-rate debt	(1,370)	(70)
Distributions to noncontrolling interest	(256)	(212)
Dividends paid	(287)	(285)
Other	(48)	(5)
NET CASH USED IN FINANCING ACTIVITIES	(969)	(572)
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS, AND RESTRICTED CASH	(1,075)	565
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF YEAR	1,668	1,377
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	593	1,942
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	344	341
Income taxes paid, net of refunds	$ 649	$ 315

XML

CONSOLIDATED BALANCE SHEET (Unaudited) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
CURRENT ASSETS:
Cash and cash equivalents	$ 593	$ 1,668
Receivables, net of allowance	1,457	1,345
Inventories	362	368
Drilling advances	229	207
Prepaid assets and other	144	137
Total current assets	2,785	3,725
Oil and gas, on the basis of successful efforts accounting:
Proved properties	41,518	39,197
Unproved properties and properties under development	1,704	1,783
Gathering, transmission and processing facilities	1,742	1,376
Other	1,081	1,046
Property and equipment, gross	46,045	43,402
Less: Accumulated depreciation, depletion, and amortization	(27,399)	(25,643)
Property and equipment, net	18,646	17,759
OTHER ASSETS:
Deferred charges and other	439	438
Total assets	21,870	21,922
CURRENT LIABILITIES:
Accounts payable	744	641
Current debt	150	550
Other current liabilities (Note 5)	1,313	1,373
Total current liabilities	2,207	2,564
LONG-TERM DEBT	8,053	7,934
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	502	545
Asset retirement obligation	1,867	1,792
Other	295	296
Total deferred credits and other noncurrent liabilities	2,664	2,633
COMMITMENTS AND CONTINGENCIES (Note 9)
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 415,660,982 and 414,125,879 shares issued, respectively	260	259
Paid-in capital	11,945	12,128
Accumulated deficit	(1,667)	(2,088)
Treasury stock, at cost, 34,092,692 and 33,171,015 shares, respectively	(2,930)	(2,887)
Accumulated other comprehensive income	4	4
APACHE SHAREHOLDERS’ EQUITY	7,612	7,416
Noncontrolling interest	1,334	1,375
TOTAL EQUITY	8,946	8,791
TOTAL LIABILITIES AND EQUITY	$ 21,870	$ 21,922

XML

CONSOLIDATED BALANCE SHEET (Unaudited) (Parenthetical) - $ / shares	Sep. 30, 2018	Dec. 31, 2017
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	415,660,982	414,125,879
Treasury stock, shares	34,092,692	33,171,015

XML

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (Unaudited) - USD ($) $ in Millions	Total	Common Stock	Paid-In Capital	Accumulated Deficit	Treasury Stock	Accumulated Other Comprehensive Income (Loss)	APACHE SHAREHOLDERS’ EQUITY	Noncontrolling Interest
Accumulated other comprehensive loss at December 31, 2016 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	985			848			848	137
Distributions to noncontrolling interest	(212)							(212)
Common dividends ($0.75 per share for Nine Months Ended September 30, 2017 and 2018)	(286)		(286)				(286)
Other	211	1	108	(7)		109	211
Accumulated other comprehensive loss at September 30, 2017 at Sep. 30, 2017	8,377	259	12,186	(2,544)	(2,887)	(3)	7,011	1,366
Accumulated other comprehensive loss at December 31, 2016 at Dec. 31, 2017	8,791	259	12,128	(2,088)	(2,887)	4	7,416	1,375
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	636			421			421	215
Distributions to noncontrolling interest	(256)							(256)
Common dividends ($0.75 per share for Nine Months Ended September 30, 2017 and 2018)	(287)		(287)				(287)
Other	62	1	104		(43)		62
Accumulated other comprehensive loss at September 30, 2017 at Sep. 30, 2018	$ 8,946	$ 260	$ 11,945	$ (1,667)	$ (2,930)	$ 4	$ 7,612	$ 1,334

XML

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (Unaudited) (Parenthetical) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Stockholders' Equity [Abstract]
Common stock, dividends, per share (in USD per share)	$ 0.25	$ 0.25	$ 0.75	$ 0.75

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2018

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, with the exception of recently adopted accounting pronouncements discussed below. 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 (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, 2017, which contains a summary of the Company’s significant accounting policies and other disclosures.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of September 30, 2018, 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, 2017, with the exception of Accounting Standards Update (ASU) 2014-09, “Revenue from Contracts with Customers (Topic 606)” (see “Revenue Recognition” section in this Note 1 below).

Use of Estimates

Preparation of financial statements in conformity with 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 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).

Recurring fair value measurements are presented in further detail in Note 4—Derivative Instruments and Hedging Activities and Note 8—Debt and Financing Costs.

Apache also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. For the third quarter and nine-month period ended September 30, 2018, the Company recorded asset impairments in connection with fair value assessments totaling $10 million. In the third quarter of 2018, Apache agreed to sell certain of its unproved properties offshore the U.K. in the North Sea (North Sea). As a result, the Company performed a fair value assessment of the properties and recorded a $10 million impairment on the carrying values of the associated capitalized exploratory well costs. The fair value of the impaired assets was determined using the negotiated sales price, a Level 1 fair value measurement.

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 in connection with fair value assessments totaling $8 million for a United Kingdom (U.K.) Petroleum Revenue Tax (PRT) decommissioning asset that is no longer expected to be realizable from future abandonment activities in the North Sea.

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. 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

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

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

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

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

When circumstances indicate that proved oil and gas properties may be impaired, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on Apache’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in 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 for the third quarters and first nine months of 2018 and 2017:

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2018		2017		2018		2017
	(In millions)
Oil and Gas Property:
Proved	$	—	$	—	$	—	$	—
Unproved	49		160		86		214

On the statement of consolidated operations, unproved leasehold impairments are recorded in exploration expense, and all other impairments of proved and unproved properties based on fair value assessments are recorded separately in impairments.

Revenue Recognition

On January 1, 2018, Apache adopted ASU 2014-09, “Revenue from Contracts with Customers (ASC 606),” using the modified retrospective method. The Company elected to evaluate all contracts at the date of initial application. While there was no impact to the opening balance of retained earnings as a result of the adoption, certain items previously netted in revenue are now recognized as “Gathering, transmission, and processing” in the Company’s statement of consolidated operations. The amounts reclassified are immaterial to the financial statements, and prior comparative periods have not been restated and continue to be reported under the accounting standards in effect for those periods. Adoption of the new standard is not anticipated to have a material impact on the Company’s net earnings on an ongoing basis.

The Company applies the provisions of ASC 606 for revenue recognition to contracts with customers. Sales of crude oil, natural gas, and NGLs are included in revenue when production is sold to a customer in fulfillment of performance obligations under the terms of agreed contracts. Performance obligations primarily comprise delivery of oil, gas, or NGLs at a delivery point, as negotiated within each contract. Each barrel of oil, million Btu (MMBtu) of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, the Company’s right to payment, and transfer of legal title. In each case, the term between delivery and when payments are due is not significant.

Apache markets its own United States (U.S.) natural gas and crude oil production based on market-priced contracts. Typically, these contracts are adjusted for quality, transportation, and other market-reflective differentials. Since the Company’s production may fluctuate as a result of operational issues, it is occasionally necessary to purchase third-party oil and gas to fulfill sales obligations and commitments. Sales proceeds related to third-party purchased oil and gas are determined to be revenue from a customer. Proceeds for these volumes totaled $124 million and $326 million for the third quarter and first nine months of 2018, respectively. Associated purchase costs for these volumes totaled $109 million and $308 million for the third quarter and first nine months of 2018, respectively. Proceeds and costs are both recorded as “Other” under “Revenues and Other” in the statement of consolidated operations.

Internationally, Apache sells its North Sea crude oil under contracts with a market-based index price. Natural gas from the North Sea Beryl field is processed through the SAGE gas plant. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. Apache’s gas production in Egypt is sold primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. The Company’s Egypt oil production is sold at prices equivalent to the export market.

The Company’s Egyptian operations are conducted pursuant to production sharing contracts under which contractor partners pay all operating and capital costs for exploring and developing the concessions. A percentage of the production, generally up to 40 percent, is available to contractor partners to recover these operating and capital costs over contractually defined periods. The balance of the production is split among the contractor partners and the Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. Additionally, the contractor partner’s income taxes, which remain the liability of the contractor partners under domestic law, are paid by EGPC on behalf of the contractor partners out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of Apache as contract partner are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Revenues related to Egypt’s tax volumes are considered revenue from a non-customer.

For the third quarter of 2018, revenues from customers and non-customers were $1.9 billion and $198 million, respectively. For the first nine months of 2018, revenues from customers and non-customers were $5.4 billion and $534 million, respectively.

Apache records trade accounts receivable for its unconditional rights to consideration arising under sales contracts with customers. The carrying value of such receivables, net of the allowance for doubtful accounts, represents estimated net realizable value. The Company routinely assesses the collectability of all material trade and other receivables. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. Receivables from contracts with customers, net of allowance for doubtful accounts, totaled $1.3 billion and $1.1 billion as of September 30, 2018 and December 31, 2017, respectively.

Apache has concluded that disaggregating revenue by geographic area and by product appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. Refer to Note 11—Business Segment Information for a disaggregation of revenue by each product sold.

Practical Expedients and Exemptions

Apache does not disclose the value of unsatisfied performance obligations for contracts with an original expected length of one year or less or contracts for which variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

Apache will utilize the practical expedient to expense incremental costs of obtaining a contract if the expected amortization period is one year or less. Costs to obtain a contract with expected amortization periods of greater than one year will be recorded as an asset and will be recognized in accordance with ASC 340, “Other Assets and Deferred Costs.” Currently, the Company does not have contract assets related to incremental costs to obtain a contract.

New Pronouncements Issued But Not Yet Adopted

In February 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-02, “Leases (Topic 842),” requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous GAAP. The guidance is effective for fiscal years beginning after December 15, 2018. Early adoption is permitted; however, the Company does not intend to early adopt. In January 2018, the FASB issued ASU 2018-01, which permits an entity an optional election to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases prior to the adoption of ASU 2016-02. In July 2018, the FASB issued ASU 2018-11, which adds a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the consolidated financial statements. Under this transition option, comparative reporting would not be required, and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. Apache intends to elect both transitional practical expedients.

In the normal course of business, the Company enters into various lease agreements for real estate, aircraft, and equipment related to its exploration and development activities that are currently accounted for as operating leases. To track these lease arrangements and facilitate compliance with this ASU, the Company is in the process of implementing a third-party lease accounting software solution and designing processes and internal controls. The Company continues to evaluate contracts, train departments affected by the standard, and monitor updates to the standard 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 June 2018, the FASB issued ASU 2018-07, “Improvements to Nonemployee Share-Based Payment Accounting,” to simplify the accounting for share-based transactions by expanding the scope of Topic 718 from only being applicable to share-based payments to employees to also include share-based payment transactions for acquiring goods and services from nonemployees. As a result, the same guidance that provides for employee share-based payments, including most of the requirements related to classification and measurement, applies to nonemployee share-based payment arrangements. ASU 2018-07 is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods. Early adoption is permitted. The Company anticipates adopting this guidance for the first quarter of 2019 and does not expect it to have a material impact on its consolidated financial statements.

In August 2018, the FASB issued ASU 2018-13, “Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement,” which changes the disclosure requirements for fair value measurements by removing, adding, and modifying certain disclosures. ASU 2018-13 is effective for financial statements issued for annual periods beginning after December 15, 2019, and interim periods within those annual periods. Early adoption is permitted. The company is currently evaluating the impact of adoption of this ASU on its related disclosures and does not expect it to have a material impact on its financial statements.

In August 2018, the FASB issued ASU 2018-14, “Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans,” which eliminates, modifies, and adds disclosure requirements for defined benefit plans. The ASU is effective for financial statements issued for fiscal years ending after December 15, 2020. Early adoption is permitted. The Company is currently evaluating the impact of adoption of this ASU on its related disclosures and does not expect it to have a material impact on its financial statements.

In August 2018, the FASB issued ASU 2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract.” This pronouncement clarifies the requirements for capitalizing implementation costs in cloud computing arrangements and aligns them with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. This pronouncement is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued. The Company is currently evaluating the impact of adoption of this ASU on its consolidated financial statements and does not expect it to have a material impact.

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ACQUISITIONS AND DIVESTITURES

9 Months Ended

Sep. 30, 2018

Business Combinations [Abstract]

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES

2018 Activity

U.S. Divestitures

On August 8, 2018, Apache and Kayne Anderson Acquisition Corp. (KAAC) announced an agreement pursuant to which Apache will contribute Apache’s Alpine High midstream assets into a newly formed limited partnership, Altus Midstream LP. Upon closing, KAAC will contribute to the partnership approximately $952 million in cash, less anticipated transaction expenses and any amount associated with potential KAAC share redemptions. The partnership will be jointly owned by Apache and KAAC. Apache will own an estimated 71 percent ownership interest in Altus Midstream LP, adjusted accordingly for any KAAC share redemptions, and expects to fully consolidate the entity in its consolidated financial statements, with the corresponding noncontrolling interest of third-party ownership reflected separately in the financial statements. The transaction is subject to approval by KAAC shareholders, as well as other customary closing conditions. Closing is expected in the fourth quarter of 2018. Upon closing, KAAC will be renamed Altus Midstream Company.

During the first nine months of 2018, Apache completed the sale of certain non-core assets, primarily in the Permian region, in multiple transactions for cash proceeds of $51 million. The Company recognized gains of approximately $10 million during the first nine months of 2018 upon the closing of these transactions.

Leasehold and Property Acquisitions

During the third quarter and first nine months of 2018, Apache completed $48 million and $86 million, respectively, of leasehold and property acquisitions primarily in its U.S. onshore and Egypt regions.

2017 Activity

Canada Divestitures

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.

During the third quarter of 2017, Apache announced the sale of its subsidiary Apache Canada Ltd. (ACL) and complete exit of its Canadian operations for aggregate cash proceeds of approximately $478 million. The Company recognized a $74 million gain upon closing of these transactions in the third quarter of 2017.

A summary of the 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.

U.S. Divestitures

During the first nine months of 2017, Apache completed the sale of certain non-core assets, consisting primarily of 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.

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 U.S. onshore regions.

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CAPITALIZED EXPLORATORY WELL COSTS

9 Months Ended

Sep. 30, 2018

Extractive Industries [Abstract]

Capitalized Exploratory Well Costs

CAPITALIZED EXPLORATORY WELL COSTS

The Company’s capitalized exploratory well costs were $300 million and $350 million at September 30, 2018 and December 31, 2017, respectively. The decrease is primarily attributable to successful transfers of well costs and dry hole write-offs, partially offset by additional drilling activities during the period. No suspended exploratory well costs previously capitalized for greater than one year at December 31, 2017 were charged to dry hole expense during the nine months ended September 30, 2018; however, during the third quarter of 2018, Apache announced an agreement to sell certain of its unproved properties in the North Sea. Exploratory well costs of approximately $70 million that have been capitalized greater than one year are included in the divestiture, which is anticipated to be completed prior to year-end.

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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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

9 Months Ended

Sep. 30, 2018

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. Apache has elected not to designate any of its derivative contracts as cash flow hedges.

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, 2018, Apache had derivative positions with 15 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, 2018, Apache had the following open crude oil derivative positions:

		Put Options(1)
Production Period	Settlement Index	Mbbls	Weighted Average Strike Price
October—December 2018	Dated Brent	3,680	$56.00
October—December 2018	NYMEX WTI	2,760	$53.00

(1) The remaining unamortized premium paid as of September 30, 2018, was $12 million.

		Collars			Call Options(2)
Production Period	Settlement Index	Mbbls	Weighted Average Floor Price	Weighted Average Ceiling Price	Mbbls	Strike Price
October—December 2018	NYMEX WTI	1,702	$45.00	$57.00	1,702	$60.03

(2) The remaining unamortized premium paid as of September 30, 2018, was $3 million.

As of September 30, 2018, Apache had the following open crude oil financial basis swap contracts:

Production Period	Settlement Index	Mbbls	Weighted Average Price Differential
October—December 2018	Midland-WTI/Cushing-WTI	1,380	$(9.23)
January—September 2019	Midland-WTI/Cushing-WTI	7,371	$(8.60)
October—December 2019	Midland-WTI/Cushing-WTI	1,380	$(3.72)

As of September 30, 2018, Apache had the following open natural gas derivative positions:

		Fixed-Price Swaps
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Fixed Price
October—December 2018	NYMEX Henry Hub	16,790	$2.96

As of September 30, 2018, Apache had the following open natural gas financial basis swap contracts:

Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential
October—December 2018	NYMEX Henry Hub/Waha	17,940	$(0.53)
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, 2018
Assets:
Commodity Derivative Instruments	$	—	$	84	$	—	$	84	$	(36	)	$	48
Liabilities:
Commodity Derivative Instruments	—		41		—		41		(36		)	5
December 31, 2017
Assets:
Commodity Derivative Instruments	$	—	$	67	$	—	$	67	$	(43	)	$	24
Liabilities:
Commodity Derivative Instruments	—		107		—		107		(43		)	64

(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, 2018		December 31, 2017
	(In millions)
Current Assets: Prepaid assets and other	$	46	$	8
Other Assets: Deferred charges and other	2		16
Total Assets	$	48	$	24
Current Liabilities: Other current liabilities	$	4	$	64
Noncurrent Liabilities: Other	1		—
Total Liabilities	$	5	$	64

Derivative Activity Recorded in the Statement of Consolidated Operations

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

	For the Quarter Ended September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(In millions)
Realized gain (loss):
Derivative settlements	$	7		$	23		$	(110	)	$	23
Amortization of call and put premium	(14		)	(50		)	(24		)	(50		)
Unrealized gain (loss)	(16		)	(83		)	88			(42		)
Derivative instrument gain (losses), net	$	(23	)	$	(110	)	$	(46	)	$	(69	)

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

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OTHER CURRENT LIABILITIES

9 Months Ended

Sep. 30, 2018

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, 2018 and December 31, 2017:

	September 30, 2018		December 31, 2017
	(In millions)
Accrued operating expenses	$	79	$	72
Accrued exploration and development	660		680
Accrued gathering, transmission, and processing	67		122
Accrued compensation and benefits	147		115
Accrued interest	99		145
Accrued income taxes	89		55
Current asset retirement obligation	38		43
Other	134		141
Total other current liabilities	$	1,313	$	1,373

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ASSET RETIREMENT OBLIGATION

9 Months Ended

Sep. 30, 2018

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, 2018:

	(In millions)
Asset retirement obligation at December 31, 2017	$	1,835
Liabilities incurred	27
Liabilities settled	(39		)
Accretion expense	81
Revisions in estimated liabilities	1
Asset retirement obligation at September 30, 2018	1,905
Less current portion	(38		)
Asset retirement obligation, long-term	$	1,867

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DEBT AND FINANCING COSTS

9 Months Ended

Sep. 30, 2018

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, 2018 and December 31, 2017:

	September 30, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Commercial paper and committed bank facilities	$	—	$	—	$	—	$	—
Notes and debentures	8,203		8,293		8,484		9,244
Total Debt	$	8,203	$	8,293	$	8,484	$	9,244

The Company’s debt is recorded at the carrying amount, net of related unamortized discount and deferred loan 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, 2018 and December 31, 2017:

	September 30, 2018			December 31, 2017
	(In millions)
Debt before unamortized discount and deferred loan costs	$	8,299		$	8,580
Unamortized discount	(45		)	(47		)
Debt issuance costs	(51		)	(49		)
Total debt	8,203			8,484
Current maturities	(150		)	(550		)
Long-term debt	$	8,053		$	7,934

As of September 30, 2018, current debt included $150 million of 7.625% senior notes due July 1, 2019. As of December 31, 2017, current debt included $150 million of 7.0% senior notes due February 1, 2018 that matured and were timely repaid and $400 million of 6.9% senior notes due September 15, 2018 that matured and were timely repaid.

On August 23, 2018, Apache closed an offering of $1.0 billion in aggregate principal amount of senior unsecured 4.375% notes due October 15, 2028. The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers, repay notes that matured in September 2018, and for general corporate purposes.

On August 24, 2018, the Company closed cash tender offers for certain outstanding notes. Apache accepted for purchase $731 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate of approximately $828 million reflecting principal, the discount to par, early tender premium, and accrued and unpaid interest. The Company recorded a net loss of $94 million on extinguishment of debt, including $5 million of unamortized debt issuance costs and discount, in connection with the note purchases.

In March 2018, the Company entered into a revolving credit facility that matures in March 2023 (subject to Apache’s two, one-year extension options) with commitments totaling $4.0 billion. The Company can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of September 30, 2018. The facility is for general corporate purposes and committed borrowing capacity fully supports Apache’s commercial paper program. As of September 30, 2018, letters of credit aggregating approximately £129.1 million and no borrowings were outstanding under this facility. In connection with entry into this facility, Apache terminated $3.5 billion and £900 million in commitments under two former credit facilities and wrote off $4 million of associated debt issuance costs, which is included in “Financing costs, net” in the Company’s consolidated statement of operations.

The Company’s $3.5 billion 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, 2018, the Company had no commercial paper outstanding.

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,
	2018			2017			2018			2017
	(In millions)
Interest expense	$	113		$	113		$	335		$	344
Amortization of deferred loan costs	2			3			8			7
Capitalized interest	(11		)	(12		)	(36		)	(39		)
Loss on extinguishment of debt	94			—			94			1
Interest income	(6		)	(3		)	(16		)	(13		)
Financing costs, net	$	192		$	101		$	385		$	300

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INCOME TAXES

9 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

The Company estimates its annual effective income tax rate 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.

During the third quarter of 2018, Apache’s effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets. During the third quarter of 2017, Apache’s effective income tax rate was primarily impacted by gains on the sale of oil and gas properties, a $30 million current tax benefit associated with U.S. federal income tax credits, 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. For more information regarding the sale of ACL, please refer to Note 2—Acquisitions and Divestitures.

Apache’s 2018 year-to-date effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets. Apache’s 2017 year-to-date effective income tax rate was 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, the current tax benefit associated with U.S. federal income tax credits, and the sale of ACL.

On December 22, 2017, the Tax Cuts and Jobs Act (the Act) was signed into law. In 2018, the Internal Revenue Service (IRS) issued additional guidance related to the Act’s deemed repatriation of foreign earnings (i.e., transition inclusion). In light of this new guidance, the Company continues to reevaluate the tax impact of the transition inclusion in 2017. Tax benefit associated with the change in transition inclusion is likely to be fully offset by a change in the Company’s valuation allowance against its U.S. deferred tax assets. The Company has not revised any other 2017 provisional estimates under Staff Accounting Bulletin No. 118, but is continuing to gather information and awaits further guidance from the IRS, SEC and FASB on the Act.

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. The Company is currently under IRS audit for the 2014-2016 tax years and is also under audit in various states and foreign jurisdictions as part of its normal course of business.

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COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2018

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, 2018, the Company has an accrued liability of approximately $39 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, 2017.

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, 2017.

Louisiana Restoration

As more fully described in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, Louisiana surface owners often file lawsuits or assert claims against oil and gas companies, including Apache, claiming that operators and working interest owners in the chain of title are liable for environmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to its original condition, regardless of the value of the underlying property. From time to time restoration lawsuits and claims are resolved by the Company for amounts that are not material to the Company, while new lawsuits and claims are asserted against the Company. With respect to each of the pending lawsuits and claims, the amount claimed is not currently determinable or is not material, except as noted. Further, the overall exposure related to these lawsuits and claims is not currently determinable. While an adverse judgment against Apache is possible, Apache intends to actively defend these lawsuits and claims.

Starting in November of 2013 and continuing into 2018, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including Apache. These cases have all been removed to federal court after having once been remanded back to state court. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. While 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, 2017.

Apollo Exploration Lawsuit

In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and areas of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The Court granted motions filed by Apache reducing the plaintiffs’ alleged damages to an amount that is not material to the Company. Apache believes that plaintiffs’ claims lack merit and 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, 2017.

Australian Operations Divestiture Dispute

By a Sale and Purchase Agreement dated April 9, 2015 (SPA), the Company and its subsidiaries divested their remaining Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, Apache filed suit against Quadrant for breach of the SPA. In its suit, Apache seeks approximately $80 million. In December 2017, Quadrant filed a defense of equitable set-off to Apache’s claim and a counterclaim seeking approximately $200 million in the aggregate. The Company believes that Quadrant’s claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity.

California Litigation

On July 17, 2017, in three separate actions, San Mateo County, California, Marin County, California, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil, gas, and coal companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz, California and Santa Cruz County, California and in a separate action on January 22, 2018, the City of Richmond, California, filed similar lawsuits against many of the same defendants. The lawsuits were removed to federal court and then consolidated. Although the federal court remanded the lawsuits back to state court, it stayed its order of remand and certified the jurisdictional inquiry for appeal to the 9^th Circuit Court of Appeals. Apache believes that the claims made against it are baseless and intends to vigorously defend these lawsuits.

Environmental Matters

As of September 30, 2018, 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, 2018, that have not been provided for or that 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.

Commitments

During the third quarter of 2018, the Company executed a 10-year firm transportation agreement associated with the third-party Permian Highway Pipeline project to transport a minimum of 500,000 MMBtu per day at a fixed rate per MMBtu. The fees will commence when the pipeline accepts first commercial delivery, which is expected to begin service in late 2020, assuming timely receipt of regulatory approvals. Apache has entered into no other material commitments since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017.

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CAPITAL STOCK

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

CAPITAL STOCK

CAPITAL STOCK

Net Income per Common Share

A reconciliation of the components of basic and diluted net income per common share for the quarters and nine months ended September 30, 2018 and 2017, is presented in the table below.

	For the Quarter Ended September 30,
	2018					2017
	Income		Shares	Per Share		Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	81	383	$	0.21	$	63	381	$	0.16
Effect of Dilutive Securities:
Stock options and other	$	—	2	$	—	$	—	2	$	—
Diluted:
Income attributable to common stock	$	81	385	$	0.21	$	63	383	$	0.16

	For the Nine Months Ended September 30,
	2018						2017
	Income		Shares	Per Share			Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	421	383	$	1.10		$	848	381	$	2.23
Effect of Dilutive Securities:
Stock options and other	$	—	2	$	(0.01	)	$	—	2	$	(0.01	)
Diluted:
Income attributable to common stock	$	421	385	$	1.09		$	848	383	$	2.22

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 4.9 million and 8.4 million for the quarters ended September 30, 2018 and 2017, respectively, and 5.8 million and 7.5 million for the nine months ended September 30, 2018 and 2017, respectively.

Common Stock Dividends

For the quarters ended September 30, 2018 and 2017, Apache paid $96 million and $95 million, respectively, in dividends on its common stock. For the nine months ended September 30, 2018 and 2017, the Company paid $287 million and $285 million, respectively.

Stock Repurchase Program

In 2013 and 2014, Apache’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. Shares may be purchased either in the open market or through privately negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through September 30, 2018, had repurchased a total of 33.1 million shares at an average price of $87.77 per share. During the third quarter of 2018, the Company repurchased a total of 0.9 million shares at an average price of $46.38 per share. On October 30, 2018, the Company’s Board of Directors authorized the purchase of up to 40 million additional shares of the Company’s common stock. The Company is not obligated to acquire any specific number of shares.

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BUSINESS SEGMENT INFORMATION

9 Months Ended

Sep. 30, 2018

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, 2018, the Company had production in three reporting segments: the U.S., Egypt, and offshore the U.K. in the 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(2,3)		North Sea		Other International			Total
	(In millions)
For the Quarter Ended September 30, 2018
Oil revenues	$	583	$	—	$	669	$	303	$	—		$	1,555
Natural gas revenues	125		—		86		30		—			241
Natural gas liquids revenues	171		—		4		5		—			180
Total Oil and Gas Production Revenues	$	879	$	—	$	759	$	338	$	—		$	1,976
Operating Income (Loss)(4)	$	147	$	—	$	438	$	114	$	(1	)	$	698
Other Income (Expense):
Gain on divestitures, net												1
Derivative instrument losses, net												(23		)
Other(5)												29
General and administrative												(99		)
Transaction, reorganization, and separation												(8		)
Financing costs, net												(192		)
Income Before Income Taxes												$	406
For the Nine Months Ended September 30, 2018
Oil revenues	$	1,743	$	—	$	1,887	$	894	$	—		$	4,524
Natural gas revenues	331		—		263		81		—			675
Natural gas liquids revenues	421		—		11		14		—			446
Total Oil and Gas Production Revenues	$	2,495	$	—	$	2,161	$	989	$	—		$	5,645
Operating Income (Loss)(4)	$	523	$	—	$	1,176	$	327	$	(3	)	$	2,023
Other Income (Expense):
Gain on divestitures, net												10
Derivative instrument losses, net												(46		)
Other(5)												50
General and administrative												(330		)
Transaction, reorganization, and separation												(20		)
Financing costs, net												(385		)
Income Before Income Taxes												$	1,302
Total Assets	$	14,389	$	—	$	4,404	$	3,033	$	44		$	21,870

	United States			Canada(1)			Egypt(2)		North Sea		Other International			Total
	(In millions)
For the Quarter Ended September 30, 2017
Oil revenues	$	381		$	14		$	442	$	233	$	—		$	1,070
Natural gas revenues	97			19			98		24		—			238
Natural gas liquids revenues	72			3			3		3		—			81
Total Oil and Gas Production Revenues	$	550		$	36		$	543	$	260	$	—		$	1,389
Operating Income (Loss)(6)	$	(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 revenues	$	1,133		$	110		$	1,351	$	698	$	—		$	3,292
Natural gas revenues	266			104			295		61		—			726
Natural gas liquids revenues	194			17			9		9		—			229
Total Oil and Gas Production Revenues	$	1,593		$	231		$	1,655	$	768	$	—		$	4,247
Operating Income (Loss)(6)	$	(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

(1) Apache exited its Canadian operations in the third quarter of 2017.

(2) Includes a noncontrolling interest in Egypt.

(3) Includes revenue from non-customers of $181 million, $16 million, and $1 million for oil, natural gas, and natural gas liquids, respectively, for the third quarter of 2018, and $485 million, $47 million, and $2 million, for oil, natural gas, and natural gas liquids, respectively, for the first nine months of 2018.

(4) Operating income (loss) consists of oil and gas production revenues less lease operating expenses, gathering, transmission, and processing costs, taxes other than income, exploration costs, depreciation, depletion, and amortization, asset retirement obligation accretion, and impairments. The operating income of U.S. and North Sea includes leasehold and unproved impairments totaling $39 million and $10 million, respectively, for the third quarter of 2018. The operating income of U.S. and North Sea includes leasehold and unproved impairments totaling $76 million and $10 million, respectively, for the first nine months of 2018.

(5) Included in Other are sales proceeds related to U.S. third-party purchased oil and gas totaling $124 million and $326 million for the third quarter and first nine months of 2018, respectively, which are determined to be revenue from customers.

(6) 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.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Use of Estimates

Use of Estimates

Preparation of financial statements in conformity with 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 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).

Recurring fair value measurements are presented in further detail in Note 4—Derivative Instruments and Hedging Activities and Note 8—Debt and Financing Costs.

Apache also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. For the third quarter and nine-month period ended September 30, 2018, the Company recorded asset impairments in connection with fair value assessments totaling $10 million. In the third quarter of 2018, Apache agreed to sell certain of its unproved properties offshore the U.K. in the North Sea (North Sea). As a result, the Company performed a fair value assessment of the properties and recorded a $10 million impairment on the carrying values of the associated capitalized exploratory well costs. The fair value of the impaired assets was determined using the negotiated sales price, a Level 1 fair value measurement.

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 in connection with fair value assessments totaling $8 million for a United Kingdom (U.K.) Petroleum Revenue Tax (PRT) decommissioning asset that is no longer expected to be realizable from future abandonment activities in the North Sea.

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

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

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

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

When circumstances indicate that proved oil and gas properties may be impaired, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on Apache’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in 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 for the third quarters and first nine months of 2018 and 2017:

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2018		2017		2018		2017
	(In millions)
Oil and Gas Property:
Proved	$	—	$	—	$	—	$	—
Unproved	49		160		86		214

On the statement of consolidated operations, unproved leasehold impairments are recorded in exploration expense, and all other impairments of proved and unproved properties based on fair value assessments are recorded separately in impairments.

Revenue Recognition

Revenue Recognition

On January 1, 2018, Apache adopted ASU 2014-09, “Revenue from Contracts with Customers (ASC 606),” using the modified retrospective method. The Company elected to evaluate all contracts at the date of initial application. While there was no impact to the opening balance of retained earnings as a result of the adoption, certain items previously netted in revenue are now recognized as “Gathering, transmission, and processing” in the Company’s statement of consolidated operations. The amounts reclassified are immaterial to the financial statements, and prior comparative periods have not been restated and continue to be reported under the accounting standards in effect for those periods. Adoption of the new standard is not anticipated to have a material impact on the Company’s net earnings on an ongoing basis.

The Company applies the provisions of ASC 606 for revenue recognition to contracts with customers. Sales of crude oil, natural gas, and NGLs are included in revenue when production is sold to a customer in fulfillment of performance obligations under the terms of agreed contracts. Performance obligations primarily comprise delivery of oil, gas, or NGLs at a delivery point, as negotiated within each contract. Each barrel of oil, million Btu (MMBtu) of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, the Company’s right to payment, and transfer of legal title. In each case, the term between delivery and when payments are due is not significant.

Apache markets its own United States (U.S.) natural gas and crude oil production based on market-priced contracts. Typically, these contracts are adjusted for quality, transportation, and other market-reflective differentials. Since the Company’s production may fluctuate as a result of operational issues, it is occasionally necessary to purchase third-party oil and gas to fulfill sales obligations and commitments. Sales proceeds related to third-party purchased oil and gas are determined to be revenue from a customer. Proceeds for these volumes totaled $124 million and $326 million for the third quarter and first nine months of 2018, respectively. Associated purchase costs for these volumes totaled $109 million and $308 million for the third quarter and first nine months of 2018, respectively. Proceeds and costs are both recorded as “Other” under “Revenues and Other” in the statement of consolidated operations.

Internationally, Apache sells its North Sea crude oil under contracts with a market-based index price. Natural gas from the North Sea Beryl field is processed through the SAGE gas plant. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. Apache’s gas production in Egypt is sold primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. The Company’s Egypt oil production is sold at prices equivalent to the export market.

The Company’s Egyptian operations are conducted pursuant to production sharing contracts under which contractor partners pay all operating and capital costs for exploring and developing the concessions. A percentage of the production, generally up to 40 percent, is available to contractor partners to recover these operating and capital costs over contractually defined periods. The balance of the production is split among the contractor partners and the Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. Additionally, the contractor partner’s income taxes, which remain the liability of the contractor partners under domestic law, are paid by EGPC on behalf of the contractor partners out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of Apache as contract partner are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Revenues related to Egypt’s tax volumes are considered revenue from a non-customer.

For the third quarter of 2018, revenues from customers and non-customers were $1.9 billion and $198 million, respectively. For the first nine months of 2018, revenues from customers and non-customers were $5.4 billion and $534 million, respectively.

Apache records trade accounts receivable for its unconditional rights to consideration arising under sales contracts with customers. The carrying value of such receivables, net of the allowance for doubtful accounts, represents estimated net realizable value. The Company routinely assesses the collectability of all material trade and other receivables. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. Receivables from contracts with customers, net of allowance for doubtful accounts, totaled $1.3 billion and $1.1 billion as of September 30, 2018 and December 31, 2017, respectively.

Apache has concluded that disaggregating revenue by geographic area and by product appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. Refer to Note 11—Business Segment Information for a disaggregation of revenue by each product sold.

Practical Expedients and Exemptions

Apache does not disclose the value of unsatisfied performance obligations for contracts with an original expected length of one year or less or contracts for which variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

Apache will utilize the practical expedient to expense incremental costs of obtaining a contract if the expected amortization period is one year or less. Costs to obtain a contract with expected amortization periods of greater than one year will be recorded as an asset and will be recognized in accordance with ASC 340, “Other Assets and Deferred Costs.” Currently, the Company does not have contract assets related to incremental costs to obtain a contract.

New Pronouncements Issued But Not Yet Adopted

New Pronouncements Issued But Not Yet Adopted

In February 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-02, “Leases (Topic 842),” requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous GAAP. The guidance is effective for fiscal years beginning after December 15, 2018. Early adoption is permitted; however, the Company does not intend to early adopt. In January 2018, the FASB issued ASU 2018-01, which permits an entity an optional election to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases prior to the adoption of ASU 2016-02. In July 2018, the FASB issued ASU 2018-11, which adds a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the consolidated financial statements. Under this transition option, comparative reporting would not be required, and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. Apache intends to elect both transitional practical expedients.

In the normal course of business, the Company enters into various lease agreements for real estate, aircraft, and equipment related to its exploration and development activities that are currently accounted for as operating leases. To track these lease arrangements and facilitate compliance with this ASU, the Company is in the process of implementing a third-party lease accounting software solution and designing processes and internal controls. The Company continues to evaluate contracts, train departments affected by the standard, and monitor updates to the standard 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 June 2018, the FASB issued ASU 2018-07, “Improvements to Nonemployee Share-Based Payment Accounting,” to simplify the accounting for share-based transactions by expanding the scope of Topic 718 from only being applicable to share-based payments to employees to also include share-based payment transactions for acquiring goods and services from nonemployees. As a result, the same guidance that provides for employee share-based payments, including most of the requirements related to classification and measurement, applies to nonemployee share-based payment arrangements. ASU 2018-07 is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods. Early adoption is permitted. The Company anticipates adopting this guidance for the first quarter of 2019 and does not expect it to have a material impact on its consolidated financial statements.

In August 2018, the FASB issued ASU 2018-13, “Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement,” which changes the disclosure requirements for fair value measurements by removing, adding, and modifying certain disclosures. ASU 2018-13 is effective for financial statements issued for annual periods beginning after December 15, 2019, and interim periods within those annual periods. Early adoption is permitted. The company is currently evaluating the impact of adoption of this ASU on its related disclosures and does not expect it to have a material impact on its financial statements.

In August 2018, the FASB issued ASU 2018-14, “Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans,” which eliminates, modifies, and adds disclosure requirements for defined benefit plans. The ASU is effective for financial statements issued for fiscal years ending after December 15, 2020. Early adoption is permitted. The Company is currently evaluating the impact of adoption of this ASU on its related disclosures and does not expect it to have a material impact on its financial statements.

In August 2018, the FASB issued ASU 2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract.” This pronouncement clarifies the requirements for capitalizing implementation costs in cloud computing arrangements and aligns them with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. This pronouncement is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued. The Company is currently evaluating the impact of adoption of this ASU on its consolidated financial statements and does not expect it to have a material impact.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

9 Months Ended

Sep. 30, 2018

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 for the third quarters and first nine months of 2018 and 2017:

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2018		2017		2018		2017
	(In millions)
Oil and Gas Property:
Proved	$	—	$	—	$	—	$	—
Unproved	49		160		86		214

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ACQUISITIONS AND DIVESTITURES (Tables)

9 Months Ended

Sep. 30, 2018

Business Combinations [Abstract]

Summary of Assets and Liabilities of Canada Divestitures

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, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of commodity derivative positions

As of September 30, 2018, Apache had the following open crude oil derivative positions:

		Put Options(1)
Production Period	Settlement Index	Mbbls	Weighted Average Strike Price
October—December 2018	Dated Brent	3,680	$56.00
October—December 2018	NYMEX WTI	2,760	$53.00

(1) The remaining unamortized premium paid as of September 30, 2018, was $12 million.

		Collars			Call Options(2)
Production Period	Settlement Index	Mbbls	Weighted Average Floor Price	Weighted Average Ceiling Price	Mbbls	Strike Price
October—December 2018	NYMEX WTI	1,702	$45.00	$57.00	1,702	$60.03

(2) The remaining unamortized premium paid as of September 30, 2018, was $3 million.

As of September 30, 2018, Apache had the following open crude oil financial basis swap contracts:

Production Period	Settlement Index	Mbbls	Weighted Average Price Differential
October—December 2018	Midland-WTI/Cushing-WTI	1,380	$(9.23)
January—September 2019	Midland-WTI/Cushing-WTI	7,371	$(8.60)
October—December 2019	Midland-WTI/Cushing-WTI	1,380	$(3.72)

As of September 30, 2018, Apache had the following open natural gas derivative positions:

		Fixed-Price Swaps
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Fixed Price
October—December 2018	NYMEX Henry Hub	16,790	$2.96

As of September 30, 2018, Apache had the following open natural gas financial basis swap contracts:

Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential
October—December 2018	NYMEX Henry Hub/Waha	17,940	$(0.53)
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, 2018
Assets:
Commodity Derivative Instruments	$	—	$	84	$	—	$	84	$	(36	)	$	48
Liabilities:
Commodity Derivative Instruments	—		41		—		41		(36		)	5
December 31, 2017
Assets:
Commodity Derivative Instruments	$	—	$	67	$	—	$	67	$	(43	)	$	24
Liabilities:
Commodity Derivative Instruments	—		107		—		107		(43		)	64

(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, 2018
Assets:
Commodity Derivative Instruments	$	—	$	84	$	—	$	84	$	(36	)	$	48
Liabilities:
Commodity Derivative Instruments	—		41		—		41		(36		)	5
December 31, 2017
Assets:
Commodity Derivative Instruments	$	—	$	67	$	—	$	67	$	(43	)	$	24
Liabilities:
Commodity Derivative Instruments	—		107		—		107		(43		)	64

(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, 2018		December 31, 2017
	(In millions)
Current Assets: Prepaid assets and other	$	46	$	8
Other Assets: Deferred charges and other	2		16
Total Assets	$	48	$	24
Current Liabilities: Other current liabilities	$	4	$	64
Noncurrent Liabilities: Other	1		—
Total Liabilities	$	5	$	64

Derivative Activity Recorded in the Statement of Consolidated Operations

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

	For the Quarter Ended September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(In millions)
Realized gain (loss):
Derivative settlements	$	7		$	23		$	(110	)	$	23
Amortization of call and put premium	(14		)	(50		)	(24		)	(50		)
Unrealized gain (loss)	(16		)	(83		)	88			(42		)
Derivative instrument gain (losses), net	$	(23	)	$	(110	)	$	(46	)	$	(69	)

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OTHER CURRENT LIABILITIES (Tables)

9 Months Ended

Sep. 30, 2018

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, 2018 and December 31, 2017:

	September 30, 2018		December 31, 2017
	(In millions)
Accrued operating expenses	$	79	$	72
Accrued exploration and development	660		680
Accrued gathering, transmission, and processing	67		122
Accrued compensation and benefits	147		115
Accrued interest	99		145
Accrued income taxes	89		55
Current asset retirement obligation	38		43
Other	134		141
Total other current liabilities	$	1,313	$	1,373

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ASSET RETIREMENT OBLIGATION (Tables)

9 Months Ended

Sep. 30, 2018

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, 2018:

	(In millions)
Asset retirement obligation at December 31, 2017	$	1,835
Liabilities incurred	27
Liabilities settled	(39		)
Accretion expense	81
Revisions in estimated liabilities	1
Asset retirement obligation at September 30, 2018	1,905
Less current portion	(38		)
Asset retirement obligation, long-term	$	1,867

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DEBT AND FINANCING COSTS (Tables)

9 Months Ended

Sep. 30, 2018

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, 2018 and December 31, 2017:

	September 30, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Commercial paper and committed bank facilities	$	—	$	—	$	—	$	—
Notes and debentures	8,203		8,293		8,484		9,244
Total Debt	$	8,203	$	8,293	$	8,484	$	9,244

Schedule of Debt

The following table presents the carrying value of the Company’s debt as of September 30, 2018 and December 31, 2017:

	September 30, 2018			December 31, 2017
	(In millions)
Debt before unamortized discount and deferred loan costs	$	8,299		$	8,580
Unamortized discount	(45		)	(47		)
Debt issuance costs	(51		)	(49		)
Total debt	8,203			8,484
Current maturities	(150		)	(550		)
Long-term debt	$	8,053		$	7,934

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,
	2018			2017			2018			2017
	(In millions)
Interest expense	$	113		$	113		$	335		$	344
Amortization of deferred loan costs	2			3			8			7
Capitalized interest	(11		)	(12		)	(36		)	(39		)
Loss on extinguishment of debt	94			—			94			1
Interest income	(6		)	(3		)	(16		)	(13		)
Financing costs, net	$	192		$	101		$	385		$	300

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CAPITAL STOCK (Tables)

9 Months Ended

Sep. 30, 2018

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 per common share for the quarters and nine months ended September 30, 2018 and 2017, is presented in the table below.

	For the Quarter Ended September 30,
	2018					2017
	Income		Shares	Per Share		Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	81	383	$	0.21	$	63	381	$	0.16
Effect of Dilutive Securities:
Stock options and other	$	—	2	$	—	$	—	2	$	—
Diluted:
Income attributable to common stock	$	81	385	$	0.21	$	63	383	$	0.16

	For the Nine Months Ended September 30,
	2018						2017
	Income		Shares	Per Share			Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	421	383	$	1.10		$	848	381	$	2.23
Effect of Dilutive Securities:
Stock options and other	$	—	2	$	(0.01	)	$	—	2	$	(0.01	)
Diluted:
Income attributable to common stock	$	421	385	$	1.09		$	848	383	$	2.22

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BUSINESS SEGMENT INFORMATION (Tables)

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Financial Segment Information

Financial information for each area is presented below:

	United States		Canada(1)		Egypt(2,3)		North Sea		Other International			Total
	(In millions)
For the Quarter Ended September 30, 2018
Oil revenues	$	583	$	—	$	669	$	303	$	—		$	1,555
Natural gas revenues	125		—		86		30		—			241
Natural gas liquids revenues	171		—		4		5		—			180
Total Oil and Gas Production Revenues	$	879	$	—	$	759	$	338	$	—		$	1,976
Operating Income (Loss)(4)	$	147	$	—	$	438	$	114	$	(1	)	$	698
Other Income (Expense):
Gain on divestitures, net												1
Derivative instrument losses, net												(23		)
Other(5)												29
General and administrative												(99		)
Transaction, reorganization, and separation												(8		)
Financing costs, net												(192		)
Income Before Income Taxes												$	406
For the Nine Months Ended September 30, 2018
Oil revenues	$	1,743	$	—	$	1,887	$	894	$	—		$	4,524
Natural gas revenues	331		—		263		81		—			675
Natural gas liquids revenues	421		—		11		14		—			446
Total Oil and Gas Production Revenues	$	2,495	$	—	$	2,161	$	989	$	—		$	5,645
Operating Income (Loss)(4)	$	523	$	—	$	1,176	$	327	$	(3	)	$	2,023
Other Income (Expense):
Gain on divestitures, net												10
Derivative instrument losses, net												(46		)
Other(5)												50
General and administrative												(330		)
Transaction, reorganization, and separation												(20		)
Financing costs, net												(385		)
Income Before Income Taxes												$	1,302
Total Assets	$	14,389	$	—	$	4,404	$	3,033	$	44		$	21,870

	United States			Canada(1)			Egypt(2)		North Sea		Other International			Total
	(In millions)
For the Quarter Ended September 30, 2017
Oil revenues	$	381		$	14		$	442	$	233	$	—		$	1,070
Natural gas revenues	97			19			98		24		—			238
Natural gas liquids revenues	72			3			3		3		—			81
Total Oil and Gas Production Revenues	$	550		$	36		$	543	$	260	$	—		$	1,389
Operating Income (Loss)(6)	$	(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 revenues	$	1,133		$	110		$	1,351	$	698	$	—		$	3,292
Natural gas revenues	266			104			295		61		—			726
Natural gas liquids revenues	194			17			9		9		—			229
Total Oil and Gas Production Revenues	$	1,593		$	231		$	1,655	$	768	$	—		$	4,247
Operating Income (Loss)(6)	$	(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

(1) Apache exited its Canadian operations in the third quarter of 2017.

(2) Includes a noncontrolling interest in Egypt.

(3) Includes revenue from non-customers of $181 million, $16 million, and $1 million for oil, natural gas, and natural gas liquids, respectively, for the third quarter of 2018, and $485 million, $47 million, and $2 million, for oil, natural gas, and natural gas liquids, respectively, for the first nine months of 2018.

(4) Operating income (loss) consists of oil and gas production revenues less lease operating expenses, gathering, transmission, and processing costs, taxes other than income, exploration costs, depreciation, depletion, and amortization, asset retirement obligation accretion, and impairments. The operating income of U.S. and North Sea includes leasehold and unproved impairments totaling $39 million and $10 million, respectively, for the third quarter of 2018. The operating income of U.S. and North Sea includes leasehold and unproved impairments totaling $76 million and $10 million, respectively, for the first nine months of 2018.

(5) Included in Other are sales proceeds related to U.S. third-party purchased oil and gas totaling $124 million and $326 million for the third quarter and first nine months of 2018, respectively, which are determined to be revenue from customers.

(6) 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.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Detail)			3 Months Ended		9 Months Ended
	Jan. 01, 2016	Dec. 31, 2015	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($) $ / MMBTU	Sep. 30, 2017 USD ($)	Dec. 31, 2017 USD ($)
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments			$ 10,000,000	$ 0	$ 10,000,000	$ 8,000,000
U.K. Petroleum Revenue Tax rate	0.00%	35.00%
Cost of purchased oil and gas			92,000,000	44,000,000	$ 260,000,000	151,000,000
Maximum percentage of production available to contract partners					40.00%
Revenue from contract with customers, excluding assessed tax			1,900,000,000		$ 5,400,000,000
Revenue from contract with customers			1,976,000,000	1,389,000,000	5,645,000,000	4,247,000,000
Revenue from non-customer			198,000,000		534,000,000
Receivables from contracts with customer, net			1,300,000,000		1,300,000,000		$ 1,100,000,000
Oil and Gas Properties, Proved
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments			0	0	0	0
Oil and Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments			49,000,000	$ 160,000,000	$ 86,000,000	$ 214,000,000
Dated Brent | Crude Oil | Minimum
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas pricing formula sliding scale | $ / MMBTU					1.50
Dated Brent | Crude Oil | Maximum
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas pricing formula sliding scale | $ / MMBTU					2.65
Oil and gas purchased
Schedule Of Significant Accounting Policies [Line Items]
Cost of purchased oil and gas			109,000,000		$ 308,000,000
Revenue from contract with customers			$ 124,000,000		$ 326,000,000

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ACQUISITIONS AND DIVESTITURES - Additional Information (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended					9 Months Ended
	Jun. 30, 2017	Aug. 31, 2017	Dec. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2016	Sep. 30, 2018	Sep. 30, 2017	Aug. 08, 2018
Business Acquisition [Line Items]
Leasehold and property acquisitions								$ 86	$ 142
Proceeds from sale of Canadian assets, net of cash divested								0	661
North America onshore regions
Business Acquisition [Line Items]
Leasehold and property acquisitions				$ 48	$ 75			86	142
Permian region
Business Acquisition [Line Items]
Proceeds from sale of non-core assets								51	783
Gains on sale of non-core assets								$ 10	594
Refundable deposits for sale of non-core assets							$ 40
Apache Canada Ltd. (ACL) | Disposed of by Sale
Business Acquisition [Line Items]
Proceeds from sale of Canadian assets, net of cash divested	$ 228	$ 478
Currency translation losses recorded in Accumulated Other Comprehensive Loss							$ 109
Pretax losses from discontinued operations					12				$ 141
Disposal Group, Midale and House Mountain | Disposed of by Sale
Business Acquisition [Line Items]
Gain (loss) on disposition of assets					$ 74	$ (52)
Altus Midstream LP. | Partnership Interest
Business Acquisition [Line Items]
Partnership ownership percentage										71.00%
KACC | Altus Midstream LP. | Scenario, Forecast | Subsequent Event
Business Acquisition [Line Items]
Proceeds from partnership contribution			$ 952

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ACQUISITIONS AND DIVESTITURES - Summary of Assets and Liabilities of 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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CAPITALIZED EXPLORATORY WELL COSTS (Details) - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Extractive Industries [Abstract]
Capitalized exploratory well costs	$ 300,000,000	$ 350,000,000
Capitalized exploratory well costs that have been capitalized for period greater than one year	$ 70,000,000	$ 0

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Instruments (Detail) bbl in Thousands, MMBTU in Thousands, $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($) MMBTU Counterparty $ / MMBTU $ / bbl bbl
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of derivative counterparties | Counterparty	15
Put Options | Crude Oil
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative remaining unamortized premium paid | $	$ 12
Put Options | October—December 2018 | Crude Oil | Dated Brent
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume (bbl) | bbl	3,680
Derivative, weighted average strike price (USD per bbl) | $ / bbl	56.00
Put Options | October—December 2018 | Crude Oil | NYMEX WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume (bbl) | bbl	2,760
Derivative, weighted average strike price (USD per bbl) | $ / bbl	53.00
Collars | October—December 2018 | Crude Oil | NYMEX WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume (bbl) | bbl	1,702
Derivative, weighted average floor price (USD per bbl)	45.00
Derivative, weighted average ceiling price (USD per bbl)	57.00
Call Options | Crude Oil
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative remaining unamortized premium paid | $	$ 3
Call Options | October—December 2018 | Crude Oil | NYMEX WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume (bbl) | bbl	1,702
Derivative, weighted average strike price (USD per bbl) | $ / bbl	60.03
Fixed-Price Swaps | October—December 2018 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, weighted average fixed price (USD per MMBtu)	2.96
Derivative, nonmonetary notional amount, energy measure | MMBTU	16,790
Finanical Basis Swaps | October—December 2018 | Crude Oil | Midland-WTI/Cushing-WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	1,380
Weighted Average Price Differential	(9.23)
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	17,940
Weighted Average Price Differential	(0.53)
Finanical Basis Swaps | January—September 2019 | Crude Oil | Midland-WTI/Cushing-WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	7,371
Weighted Average Price Differential	(8.60)
Finanical Basis Swaps | October—December 2019 | Crude Oil | Midland-WTI/Cushing-WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	1,380
Weighted Average Price Differential	(3.72)
Finanical Basis Swaps | January—March 2019 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	1,350
Weighted Average Price Differential	(0.54)
Finanical Basis Swaps | January—June 2019 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	32,580
Weighted Average Price Differential	(0.53)
Finanical Basis Swaps | January—December 2019 | Natural Gas | NYMEX Henry Hub
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	14,600
Weighted Average Price Differential	(0.45)

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Assets and Liabilities Measured at Fair Value (Details) - Commodity Derivative Instruments - Recurring - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative asset, fair value	$ 84	$ 67
Derivative asset, netting	(36)	(43)
Derivative asset	48	24
Derivative liability, fair value	41	107
Derivative liability, netting	(36)	(43)
Derivative liability	5	64
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	84	67
Derivative liability, fair value	41	107
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 - Assets and Liabilities and Locations on Balance Sheet (Details) - Recurring - Commodity Derivative Instruments - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Derivative asset	$ 48	$ 24
Derivative liability	5	64
Current Assets: Prepaid assets and other
Derivatives, Fair Value [Line Items]
Derivative asset	46	8
Other Assets: Deferred charges and other
Derivatives, Fair Value [Line Items]
Derivative asset	2	16
Current Liabilities: Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability	4	64
Noncurrent Liabilities: Other
Derivatives, Fair Value [Line Items]
Derivative liability	$ 1	$ 0

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Activities Recorded in Operations (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Realized gain (loss):
Unrealized gain (loss)			$ 88	$ (42)
Not Designated as Hedging Instrument
Realized gain (loss):
Derivative settlements	$ 7	$ 23	(110)	23
Amortization of call and put premium	(14)	(50)	(24)	(50)
Unrealized gain (loss)	(16)	(83)	88	(42)
Derivative instrument gain (losses), net	$ (23)	$ (110)	$ (46)	$ (69)

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OTHER CURRENT LIABILITIES (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Payables and Accruals [Abstract]
Accrued operating expenses	$ 79	$ 72
Accrued exploration and development	660	680
Accrued gathering, transmission, and processing	67	122
Accrued compensation and benefits	147	115
Accrued interest	99	145
Accrued income taxes	89	55
Current asset retirement obligation	38	43
Other	134	141
Total other current liabilities	$ 1,313	$ 1,373

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ASSET RETIREMENT OBLIGATION (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at the beginning of period			$ 1,835
Liabilities incurred			27
Liabilities settled			(39)
Accretion expense	$ 27	$ 30	81	$ 103
Revisions in estimated liabilities			1
Asset retirement obligation at the end of period	1,905		1,905
Less current portion	(38)		(38)		$ (43)
Asset retirement obligation, long-term	$ 1,867		$ 1,867		$ 1,792

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INCOME TAXES (Details) $ in Millions	3 Months Ended
	Sep. 30, 2017 USD ($)
Income Tax Disclosure [Abstract]
Current tax benefit	$ 30

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DEBT AND FINANCING COSTS - Summary of Carrying Amounts and Fair Values (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount	$ 8,203	$ 8,484
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value	8,293	9,244
Commercial paper and committed bank facilities | Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount	0	0
Commercial paper and committed bank facilities | Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value	0	0
Notes and debentures | Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount	8,203	8,484
Notes and debentures | Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value	$ 8,293	$ 9,244

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DEBT AND FINANCING COSTS - Schedule of Debt (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt before unamortized discount and deferred loan costs	$ 8,299	$ 8,580
Unamortized discount	(45)	(47)
Debt issuance costs	(51)	(49)
Total debt	8,203	8,484
Current maturities	(150)	(550)
Long-term debt	$ 8,053	$ 7,934

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DEBT AND FINANCING COSTS - Additional Information (Detail) £ in Millions			1 Months Ended	3 Months Ended		9 Months Ended
	Aug. 24, 2018 USD ($)	Aug. 23, 2018 USD ($)	Mar. 31, 2018 USD ($) contract	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2018 GBP (£)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 GBP (£)	Dec. 31, 2017 USD ($)
Debt Instrument [Line Items]
Debt instrument, face amount				$ 8,299,000,000		$ 8,299,000,000				$ 8,580,000,000
Loss on extinguishment of debt				94,000,000	$ 0	94,000,000		$ 1,000,000
Number of credit facilities terminated | contract			2
Write off of deferred loan costs			$ 4,000,000
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	270 days
7.625% senior notes due July 1, 2019
Debt Instrument [Line Items]
Debt instrument, face amount				$ 150,000,000		$ 150,000,000
Debt instrument, stated interest rate				7.625%		7.625%			7.625%
6.9% senior notes due September 15, 2018
Debt Instrument [Line Items]
Debt instrument, face amount										$ 400,000,000
Debt instrument, stated interest rate										6.90%
7.0% senior notes due February 1, 2018
Debt Instrument [Line Items]
Debt instrument, face amount										$ 150,000,000
Debt instrument, stated interest rate										7.00%
4.375% notes due 2028
Debt Instrument [Line Items]
Debt instrument, stated interest rate		4.375%
Debt tender offer, maximum aggregate purchase price		$ 1,000,000,000
Line of Credit | USD Credit Facility
Debt Instrument [Line Items]
Debt extinguished amount						$ 3,500,000,000
Line of Credit | Letter of Credit
Debt Instrument [Line Items]
Line of credit facility, committed amount				$ 2,080,000,000		2,080,000,000
Credit facility maximum borrowing capacity				3,000,000,000.0		3,000,000,000.0
Line of credit facility aggregate commitment amount | £									£ 129.1
Line of Credit | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, number of extension options | contract			2
Extended financing agreement term			1 year
Line of credit facility, committed amount				4,000,000,000		4,000,000,000
Credit facility maximum borrowing capacity				5,000,000,000.0		5,000,000,000.0
Letters of credit outstanding, amount				$ 0		$ 0
Line of Credit | GBP Credit Facility
Debt Instrument [Line Items]
Debt extinguished amount | £							£ 900.0
Senior Notes
Debt Instrument [Line Items]
Debt repurchased face amount	$ 731,440,000.00
Debt extinguished amount	828,000,000
Loss on extinguishment of debt	94,000,000
Unamortized debt issuance costs and discount	$ 5,000,000

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DEBT AND FINANCING COSTS - Components of Financing Costs, Net (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Debt Disclosure [Abstract]
Interest expense	$ 113	$ 113	$ 335	$ 344
Amortization of deferred loan costs	2	3	8	7
Capitalized interest	(11)	(12)	(36)	(39)
Loss on extinguishment of debt	94	0	94	1
Interest income	(6)	(3)	(16)	(13)
Financing costs, net	$ 192	$ 101	$ 385	$ 300

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COMMITMENTS AND CONTINGENCIES (Detail) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2018 USD ($) MMBTU	Dec. 31, 2017 USD ($)	Apr. 30, 2017 AUD ($)
Commitment And Contingencies [Line Items]
Accrued liability for legal contingencies	$ 39,000,000
Undiscounted reserve for environmental remediation	$ 4,000,000
Transportation agreement term	10 years
Transportation agreement, minimum energy volume required (in MMBtu) | MMBTU	500,000
Australian Operations Divestiture Dispute | Apache Australia Operation
Commitment And Contingencies [Line Items]
Gain contingency, unrecorded amount			$ 80
Divestiture of business, tax and other issues contingency amount		$ 200,000,000
Apollo Exploration Lawsuit
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages	$ 200,000,000
Apollo Exploration Lawsuit | Minimum
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages		$ 1,100,000,000.0

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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, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Basic:
Income attributable to common stock	$ 81	$ 63	$ 421	$ 848
Income (loss) attributable to common stock (in shares)	383	381	383	381
Basic net income (loss) per share (in USD per share)	$ 0.21	$ 0.16	$ 1.10	$ 2.23
Effect of Dilutive Securities:
Stock options and other (in shares)	2	2	2	2
Stock options and other (in USD per share)			$ (0.01)	$ (0.01)
Diluted:
Income attributable to common stock	$ 81	$ 63	$ 421	$ 848
Income (loss) attributable to common stock (in shares)	385	383	385	383
Diluted net income (loss) per share (in USD per share)	$ 0.21	$ 0.16	$ 1.09	$ 2.22

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CAPITAL STOCK - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended		64 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Oct. 30, 2018
Equity, Class of Treasury Stock [Line Items]
Options and restricted stock, anti-dilutive	4,900,000	8,400,000	5,800,000	7,500,000
Dividends, common stock	$ 96	$ 95	$ 287	$ 285
Authorized amount of common stock repurchase (in shares)	40,000,000		40,000,000		40,000,000
Common stock share repurchase, shares	900,000				33,100,000
Common stock share repurchase average price (in USD per share)	$ 46.38				$ 87.77
Subsequent Event
Equity, Class of Treasury Stock [Line Items]
Authorized amount of common stock repurchase (in shares)						40,000,000

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BUSINESS SEGMENT INFORMATION (Detail)	3 Months Ended		9 Months Ended
	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($) Segment	Sep. 30, 2017 USD ($)	Dec. 31, 2017 USD ($)
Segment Reporting [Abstract]
Number of reporting segments | Segment			3
Segment Reporting Information [Line Items]
Revenue from contract with customers	$ 1,976,000,000	$ 1,389,000,000	$ 5,645,000,000	$ 4,247,000,000
Operating Income (Loss)	698,000,000	126,000,000	2,023,000,000	671,000,000
Other Income (Expense):
Gain on divestitures	1,000,000	296,000,000	10,000,000	616,000,000
Derivative instrument losses, net	(23,000,000)	(110,000,000)	(46,000,000)	(69,000,000)
Other	29,000,000	0	50,000,000	43,000,000
General and administrative	(99,000,000)	(98,000,000)	(330,000,000)	(307,000,000)
Transaction, reorganization, and separation	(8,000,000)	(20,000,000)	(20,000,000)	(14,000,000)
Financing costs, net	(192,000,000)	(101,000,000)	(385,000,000)	(300,000,000)
NET INCOME BEFORE INCOME TAXES	406,000,000	93,000,000	1,302,000,000	640,000,000
Total Assets	21,870,000,000	21,835,000,000	21,870,000,000	21,835,000,000	$ 21,922,000,000
Revenue from non-customer	198,000,000		534,000,000
Asset impairments	10,000,000	0	10,000,000	8,000,000
Operating Segments | United States
Segment Reporting Information [Line Items]
Revenue from contract with customers	879,000,000	550,000,000	2,495,000,000	1,593,000,000
Operating Income (Loss)	147,000,000	(114,000,000)	523,000,000	(71,000,000)
Other Income (Expense):
Total Assets	14,389,000,000	13,105,000,000	14,389,000,000	13,105,000,000
Asset impairments	39,000,000	160,000,000	76,000,000	212,000,000
Operating Segments | Canada
Segment Reporting Information [Line Items]
Revenue from contract with customers	0	36,000,000	0	231,000,000
Operating Income (Loss)	0	(1,000,000)	0	(33,000,000)
Other Income (Expense):
Total Assets	0	0	0	0
Asset impairments				2,000,000
Operating Segments | Egypt
Segment Reporting Information [Line Items]
Revenue from contract with customers	759,000,000	543,000,000	2,161,000,000	1,655,000,000
Operating Income (Loss)	438,000,000	226,000,000	1,176,000,000	740,000,000
Other Income (Expense):
Total Assets	4,404,000,000	4,906,000,000	4,404,000,000	4,906,000,000
Operating Segments | North Sea
Segment Reporting Information [Line Items]
Revenue from contract with customers	338,000,000	260,000,000	989,000,000	768,000,000
Operating Income (Loss)	114,000,000	16,000,000	327,000,000	59,000,000
Other Income (Expense):
Total Assets	3,033,000,000	3,770,000,000	3,033,000,000	3,770,000,000
Asset impairments	10,000,000		10,000,000	8,000,000
Other International
Segment Reporting Information [Line Items]
Revenue from contract with customers	0	0	0	0
Operating Income (Loss)	(1,000,000)	(1,000,000)	(3,000,000)	(24,000,000)
Other Income (Expense):
Total Assets	44,000,000	54,000,000	44,000,000	54,000,000
Oil
Segment Reporting Information [Line Items]
Revenue from contract with customers	1,555,000,000	1,070,000,000	4,524,000,000	3,292,000,000
Other Income (Expense):
Revenue from non-customer	181,000,000		485,000,000
Oil | Operating Segments | United States
Segment Reporting Information [Line Items]
Revenue from contract with customers	583,000,000	381,000,000	1,743,000,000	1,133,000,000
Oil | Operating Segments | Canada
Segment Reporting Information [Line Items]
Revenue from contract with customers	0	14,000,000	0	110,000,000
Oil | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Revenue from contract with customers	669,000,000	442,000,000	1,887,000,000	1,351,000,000
Oil | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Revenue from contract with customers	303,000,000	233,000,000	894,000,000	698,000,000
Oil | Other International
Segment Reporting Information [Line Items]
Revenue from contract with customers	0	0	0	0
Natural Gas
Segment Reporting Information [Line Items]
Revenue from contract with customers	241,000,000	238,000,000	675,000,000	726,000,000
Other Income (Expense):
Revenue from non-customer	16,000,000		47,000,000
Natural Gas | Operating Segments | United States
Segment Reporting Information [Line Items]
Revenue from contract with customers	125,000,000	97,000,000	331,000,000	266,000,000
Natural Gas | Operating Segments | Canada
Segment Reporting Information [Line Items]
Revenue from contract with customers	0	19,000,000	0	104,000,000
Natural Gas | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Revenue from contract with customers	86,000,000	98,000,000	263,000,000	295,000,000
Natural Gas | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Revenue from contract with customers	30,000,000	24,000,000	81,000,000	61,000,000
Natural Gas | Other International
Segment Reporting Information [Line Items]
Revenue from contract with customers	0	0	0	0
Natural gas liquids
Segment Reporting Information [Line Items]
Revenue from contract with customers	180,000,000	81,000,000	446,000,000	229,000,000
Other Income (Expense):
Revenue from non-customer	1,000,000		2,000,000
Natural gas liquids | Operating Segments | United States
Segment Reporting Information [Line Items]
Revenue from contract with customers	171,000,000	72,000,000	421,000,000	194,000,000
Natural gas liquids | Operating Segments | Canada
Segment Reporting Information [Line Items]
Revenue from contract with customers	0	3,000,000	0	17,000,000
Natural gas liquids | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Revenue from contract with customers	4,000,000	3,000,000	11,000,000	9,000,000
Natural gas liquids | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Revenue from contract with customers	5,000,000	3,000,000	14,000,000	9,000,000
Natural gas liquids | Other International
Segment Reporting Information [Line Items]
Revenue from contract with customers	$ 0	$ 0	$ 0	$ 0