10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 

FORM 10-Q 

(Mark One)  

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

For the quarterly period ended June 30, 2019

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 No.)

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

(Address of principal executive offices) (Zip Code)

(713) 296-6000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $0.625 par value	APA	New York Stock Exchange
Common Stock, $0.625 par value	APA	Chicago Stock Exchange
Common Stock, $0.625 par value	APA	NASDAQ Global Select Market
7.75% Notes Due 2029	APA/29	New York Stock Exchange

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  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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	☒	Accelerated filer	☐
Non-accelerated filer	☐	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  ☒

Number of shares of registrant’s common stock outstanding as of July 31, 2019 375,958,977

	TABLE OF CONTENTS
	DESCRIPTION
Item		Page
	PART I - FINANCIAL INFORMATION
1.	FINANCIAL STATEMENTS	1
	STATEMENT OF CONSOLIDATED OPERATIONS	1
	STATEMENT OF CONSOLIDATED CASH FLOWS	2
	CONSOLIDATED BALANCE SHEET	3
	STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTEREST	4
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	6
2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	25
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	37
4.	CONTROLS AND PROCEDURES	38
	PART II - OTHER INFORMATION
1.	LEGAL PROCEEDINGS	39
1A.	RISK FACTORS	39
2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	39
5.	OTHER INFORMATION	39
6.	EXHIBITS	40

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, 2018, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

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

• our commodity hedging arrangements;

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

• production and reserve levels;

• drilling risks;

• economic and competitive conditions;

• the availability of capital resources;

• capital expenditure and other contractual obligations;

• currency exchange rates;

• weather conditions;

• inflation rates;

• the availability of goods and services;

• legislative, regulatory, or policy changes;

• terrorism or cyber attacks;

• occurrence of property acquisitions or divestitures;

• the integration of acquisitions;

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

• other factors disclosed under Items 1 and 2—Business and Properties—Estimated Proved Reserves and Future Net Cash Flows, Item 1A—Risk Factors, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A—Quantitative and Qualitative Disclosures About Market Risk and elsewhere in our most recently filed Annual Report on Form 10-K, other risks and uncertainties in our second-quarter 2019 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 June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues
Oil revenues	$	1,397		$	1,576		$	2,707		$	2,969
Natural gas revenues	118			212			354			434
Natural gas liquids revenues	83			148			191			266
	1,598			1,936			3,252			3,669
Derivative instrument losses, net	(8		)	(25		)	(38		)	(23		)
Gain on divestitures	17			2			20			9
Other	(4		)	16			4			21
	1,603			1,929			3,238			3,676
OPERATING EXPENSES:
Lease operating expenses	389			356			754			705
Gathering, processing, and transmission	76			82			164			168
Taxes other than income	46			49			97			104
Exploration	95			76			164			152
General and administrative	102			117			225			231
Transaction, reorganization, and separation	6			12			10			12
Depreciation, depletion, and amortization	602			608			1,248			1,161
Asset retirement obligation accretion	26			27			53			54
Impairments	240			—			240			—
Financing costs, net	173			94			270			193
	1,755			1,421			3,225			2,780
NET INCOME (LOSS) BEFORE INCOME TAXES	(152		)	508			13			896
Current income tax provision	187			249			373			447
Deferred income tax benefit	(23		)	(10		)	(42		)	(26		)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	(316		)	269			(318		)	475
Net income attributable to noncontrolling interest - Egypt	43			74			87			135
Net loss attributable to noncontrolling interest - Altus	(3		)	—			(2		)	—
Net income attributable to Altus Preferred Unit limited partners	4			—			4			—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(360	)	$	195		$	(407	)	$	340
NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	(0.96	)	$	0.51		$	(1.08	)	$	0.89
Diluted	$	(0.96	)	$	0.51		$	(1.08	)	$	0.88
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	377			382			376			382
Diluted	377			385			376			384

The accompanying notes to consolidated financial statements

are an integral part of this statement.

1

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

(Unaudited)

	For the Six Months Ended June 30,
	2019			2018
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) including noncontrolling interest	$	(318	)	$	475
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized derivative instrument losses (gains), net	66			(104		)
Gain on divestitures	(20		)	(9		)
Exploratory dry hole expense and unproved leasehold impairments	90			73
Depreciation, depletion, and amortization	1,248			1,161
Asset retirement obligation accretion	53			54
Impairments	240			—
Deferred income tax benefit	(42		)	(26		)
Loss on extinguishment of debt	75			—
Other	22			82
Changes in operating assets and liabilities:
Receivables	96			(101		)
Inventories	(16		)	(9		)
Drilling advances	(8		)	30
Deferred charges and other	(3		)	69
Accounts payable	(66		)	46
Accrued expenses	21			(20		)
Deferred credits and noncurrent liabilities	16			7
NET CASH PROVIDED BY OPERATING ACTIVITIES	1,454			1,728
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(1,386		)	(1,572		)
Leasehold and property acquisitions	(34		)	(38		)
Additions to Altus gathering, processing, and transmission facilities	(246		)	(284		)
Altus equity method interests	(438		)	—
Proceeds from sale of oil and gas properties	247			13
Other, net	25			(33		)
NET CASH USED IN INVESTING ACTIVITIES	(1,832		)	(1,914		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Fixed-rate debt borrowings	989			—
Payments on fixed-rate debt	(1,000		)	(150		)
Distributions to noncontrolling interest - Egypt	(164		)	(155		)
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	611			—
Dividends paid	(188		)	(191		)
Other	(35		)	(14		)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	213			(510		)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(165		)	(696		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	714			1,668
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	549		$	972
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	219		$	200
Income taxes paid, net of refunds	285			374

The accompanying notes to consolidated financial statements

are an integral part of this statement.

2

APACHE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)

In millions except share and per-share amounts	June 30, 2019			December 31, 2018
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ($377 and $450 related to Altus VIE)	$	549		$	714
Receivables (net of allowance of $102 and $92)	1,098			1,194
Other current assets (Note 5) ($8 and $7 related to Altus VIE)	1,144			779
	2,791			2,687
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of successful efforts accounting:
Proved properties	39,573			42,345
Unproved properties and properties under development	1,206			1,435
Gathering, processing, and transmission facilities ($1,452 and $1,251 related to Altus VIE)	2,057			1,856
Other ($38 and nil related to Altus VIE)	1,156			1,120
	43,992			46,756
Less: Accumulated depreciation, depletion, and amortization ($40 and $24 related to Altus VIE)	(26,236		)	(28,335		)
	17,756			18,421
OTHER ASSETS:
Equity method interests ($527 and $91 related to Altus VIE)	527			121
Deferred charges and other ($72 and $71 related to Altus VIE)	732			353
	$	21,806		$	21,582
LIABILITIES, NONCONTROLLING INTEREST, AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	644		$	709
Current debt ($23 and nil related to Altus VIE)	175			151
Other current liabilities (Note 7) ($44 and $85 related to Altus VIE)	1,443			1,341
	2,262			2,201
LONG-TERM DEBT	8,157			8,093
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	348			391
Asset retirement obligation ($33 and $29 related to Altus VIE)	1,850			1,866
Other ($94 and nil related to Altus VIE)	514			219
	2,712			2,476
COMMITMENTS AND CONTINGENCIES (Note 11)
REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 12)	521			—
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 416,920,316 and 415,692,116 shares issued, respectively	261			260
Paid-in capital	11,931			12,106
Accumulated deficit	(2,455		)	(2,048		)
Treasury stock, at cost, 40,964,193 and 40,995,894 shares, respectively	(3,190		)	(3,192		)
Accumulated other comprehensive income	4			4
APACHE SHAREHOLDERS’ EQUITY	6,551			7,130
Noncontrolling interest - Egypt	1,198			1,275
Noncontrolling interest - Altus	405			407
TOTAL EQUITY	8,154			8,812
	$	21,806		$	21,582

The accompanying notes to consolidated financial statements are an integral part of this statement.

3

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTEREST

(Unaudited)

	Redeemable Noncontrolling Interest — Altus Preferred Unit Limited Partners		Common Stock		Paid-In Capital			Accumulated Deficit			Treasury Stock			Accumulated Other Comprehensive Income		APACHE SHAREHOLDERS’ EQUITY			Noncontrolling Interest			TOTAL EQUITY
			(In millions)
For the Quarter Ended June 30, 2018
BALANCE AT MARCH 31, 2018	$	—	$	259	$	12,069		$	(1,943	)	$	(2,887	)	$	4	$	7,502		$	1,367		$	8,869
Net income attributable to common stock	—		—		—			195			—			—		195			—			195
Net income attributable to noncontrolling interest - Egypt	—		—		—			—			—			—		—			74			74
Distributions to noncontrolling interest - Egypt	—		—		—			—			—			—		—			(86		)	(86		)
Common dividends ($0.25 per share)	—		—		(95		)	—			—			—		(95		)	—			(95		)
Other	—		1		37			—			—			—		38			—			38
BALANCE AT JUNE 30, 2018	$	—	$	260	$	12,011		$	(1,748	)	$	(2,887	)	$	4	$	7,640		$	1,355		$	8,995
For the Quarter Ended June 30, 2019
BALANCE AT MARCH 31, 2019	$	—	$	261	$	12,009		$	(2,095	)	$	(3,190	)	$	4	$	6,989		$	1,620		$	8,609
Net loss attributable to common stock	—		—		—			(360		)	—			—		(360		)	—			(360		)
Net income attributable to noncontrolling interest - Egypt	—		—		—			—			—			—		—			43			43
Net loss attributable to noncontrolling interest - Altus	—		—		—			—			—			—		—			(3		)	(3		)
Issuance of Altus Preferred Units	517		—		—			—			—			—		—			—			—
Net income attributable to Altus Preferred Unit holders	4		—		—			—			—			—		—			—			—
Distributions to noncontrolling interest - Egypt	—		—		—			—			—			—		—			(57		)	(57		)
Common dividends ($0.25 per share)	—		—		(94		)	—			—			—		(94		)	—			(94		)
Other	—		—		16			—			—			—		16			—			16
BALANCE AT JUNE 30, 2019	$	521	$	261	$	11,931		$	(2,455	)	$	(3,190	)	$	4	$	6,551		$	1,603		$	8,154

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 AND NONCONTROLLING INTEREST – (Continued)

(Unaudited)

	Redeemable Noncontrolling Interest — Altus Preferred Unit Limited Partners		Common Stock		Paid-In Capital			Accumulated Deficit			Treasury Stock			Accumulated Other Comprehensive Income		APACHE SHAREHOLDERS’ EQUITY			Noncontrolling Interest			TOTAL EQUITY
			(In millions)
For the Six Months Ended June 30, 2018
BALANCE AT DECEMBER 31, 2017	$	—	$	259	$	12,128		$	(2,088	)	$	(2,887	)	$	4	$	7,416		$	1,375		$	8,791
Net income attributable to common stock	—		—		—			340			—			—		340			—			340
Net income attributable to noncontrolling interest - Egypt	—		—		—			—			—			—		—			135			135
Distributions to noncontrolling interest - Egypt	—		—		—			—			—			—		—			(155		)	(155		)
Common dividends ($0.50 per share)	—		—		(191		)	—			—			—		(191		)	—			(191		)
Other	—		1		74			—			—			—		75			—			75
BALANCE AT JUNE 30, 2018	$	—	$	260	$	12,011		$	(1,748	)	$	(2,887	)	$	4	$	7,640		$	1,355		$	8,995
For the Six Months Ended June 30, 2019
BALANCE AT DECEMBER 31, 2018	$	—	$	260	$	12,106		$	(2,048	)	$	(3,192	)	$	4	$	7,130		$	1,682		$	8,812
Net loss attributable to common stock	—		—		—			(407		)	—			—		(407		)	—			(407		)
Net income attributable to noncontrolling interest - Egypt	—		—		—			—			—			—		—			87			87
Net loss attributable to noncontrolling interest - Altus	—		—		—			—			—			—		—			(2		)	(2		)
Issuance of Altus Preferred Units	517		—		—			—			—			—		—			—			—
Net income attributable to Altus Preferred Unit holders	4		—		—			—			—			—		—			—			—
Distributions to noncontrolling interest - Egypt	—		—		—			—			—			—		—			(164		)	(164		)
Common dividends ($0.50 per share)	—		—		(188		)	—			—			—		(188		)	—			(188		)
Other	—		1		13			—			2			—		16			—			16
BALANCE AT JUNE 30, 2019	$	521	$	261	$	11,931		$	(2,455	)	$	(3,190	)	$	4	$	6,551		$	1,603		$	8,154

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, 2018, which contains a summary of the Company’s significant accounting policies and other disclosures.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of June 30, 2019, 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, 2018, with the exception of Accounting Standards Update (ASU) 2016-02, “Leases (Topic 842)” (see “Leases” section in this Note 1 below).

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated.

The Company consolidates all other investments in which, either through direct or indirect ownership, Apache has more than a 50 percent voting interest or controls the financial and operating decisions. Noncontrolling interests represent third-party ownership in the net assets of a consolidated Apache subsidiary and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in Apache’s Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate component of equity in Apache’s consolidated balance sheet.

Additionally, third-party investors own a minority interest of approximately 21 percent of Altus Midstream Company (ALTM), which is reflected as a separate noncontrolling interest component of equity in Apache’s consolidated balance sheet. Apache consolidates the activities of ALTM, which qualifies as a variable interest entity (VIE) under GAAP. Apache has concluded that it is the primary beneficiary of the VIE, as defined in the accounting standards, since Apache has the power, through its ownership, to direct those activities that most significantly impact the economic performance of ALTM and the obligation to absorb losses or the right to receive benefits that could be potentially significant to ALTM. This conclusion was based on a qualitative analysis that considered ALTM’s governance structure, the commercial agreements between ALTM, Altus Midstream LP (collectively with ALTM, Altus), and Apache, and the voting rights established between the members, which provide Apache with the ability to control the operations of Altus. On June 12, 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units (the Preferred Units) through a private offering that admitted additional limited partners with separate rights for the Preferred Unit holders. For further details on the terms of the Preferred Units and rights of the holders, refer to Note 12—Redeemable Noncontrolling Interest - Altus.

Investments in which Apache holds less than 50 percent of the voting interest are typically accounted for under the equity method of accounting, with the balance recorded separately as “Equity method interests” in Apache’s consolidated balance sheet and results of operations recorded as a component of “Other” under “Revenues and Other” in the Company’s statement of consolidated operations. Refer to Note 6—Equity Method Interests for more detail.

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

6

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, Note 10—Debt and Financing Costs, and Note 12—Redeemable Noncontrolling Interest - Altus.

Apache also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. In the second quarter of 2019, the Company entered into an agreement to sell certain of its assets in the Western Anadarko Basin in Oklahoma and Texas. As a result of this agreement, a separate impairment analysis was performed for each of the assets within the disposal group. The analyses were based on the agreed-upon proceeds less costs to sell for the transaction, a Level 1 fair value measurement. The carrying value of the net assets to be divested exceeded the fair value implied by the expected net proceeds, resulting in impairments totaling $240 million, including $86 million on the Company’s proved properties, $149 million on its unproved properties, and $5 million on other working capital. See Note 2—Acquisitions and Divestitures for more detail. The Company recorded no asset impairments in connection with fair value assessments in the second quarter and first six months of 2018.

Oil and Gas Property

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

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

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

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

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

The following table represents non-cash impairments of the carrying value of the Company’s proved and unproved property and equipment for the second quarters and first six months of 2019 and 2018:

	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(In millions)
Oil and Gas Property:
Proved	$	86	$	—	$	86	$	—
Unproved	188		21		211		37

Proved properties impaired during the second quarter of 2019 related to assets held for sale with an aggregate fair value of $379 million.

On the statement of consolidated operations, unproved leasehold impairments are typically recorded as a component of “Exploration” expense; however, in the second quarter of 2019, unproved impairments of $149 million were recorded in “Impairments” in connection with an agreement to sell certain non-core leasehold properties in Oklahoma and Texas.

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

Revenue Recognition

There have been no significant changes to the Company’s contracts with customers during the six months ended June 30, 2019. Apache recognizes revenue from its contracts with customers from the sale of its crude oil, natural gas, and natural gas liquids (NGLs) production as well as volumes purchased from third-parties. Each unit of quantity represents a single performance obligation that is satisfied at a point in time as control of the product has been transferred to the customer.

The contracted price is variable and is determined based on market-indexed prices adjusted for quality, transportation, and other market-reflective differentials. Sales proceeds related to third-party purchases volumes are considered revenue from a contract with a customer. Proceeds for these volumes totaled $18 million and $98 million for the second quarters of 2019 and 2018, respectively, and $42 million and $202 million for the first six months of 2019 and 2018, respectively. Associated purchase costs for these volumes totaled $15 million and $95 million for the second quarters of 2019 and 2018, respectively, and $37 million and $199 million for the first six months of 2019 and 2018, respectively. Proceeds and costs are both recorded as “Other” under “Revenues and Other” in the statement of consolidated operations.

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The following table represents revenues from customers and non-customers for the second quarters and first six months of 2019 and 2018:

	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(In millions)
Revenues from customers	$	1,496	$	1,853	$	3,054	$	3,535
Revenues from non-customers	120		181		240		336

Payment from contracts with customers is typically received on a short-term basis after physical delivery of the product. Receivables from contracts with customers, net of allowance for doubtful accounts, totaled $936 million and $1.0 billion as of June 30, 2019 and December 31, 2018, 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 14—Business Segment Information for a disaggregation of revenue by each product sold.

Leases

On January 1, 2019, Apache adopted ASU 2016-02, “Leases (Topic 842),” which requires lessees to recognize separate right-of-use (ROU) assets and lease liabilities for most leases classified as operating leases under previous GAAP. Prior to adoption, the Financial Accounting Standards Board (FASB) issued transition guidance permitting an entity the option to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases, as well as an option to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the financial statements. Apache elected both transitional practical expedients. Under these transition options, comparative reporting was not required, and the provisions of the standard were applied prospectively to leases in effect at the date of adoption.

As allowed under the standard, the Company also applied practical expedients to carry forward its historical assessments of whether existing agreements contain a lease, classification of existing lease agreements, and treatment of initial direct lease costs. Apache also elected to exclude short-term leases (those with terms of 12 months or less) from the balance sheet presentation and accounts for non-lease and lease components as a single lease component for all asset classes. Short-term lease expense was not material for the second quarter and first six months of 2019.

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

Operating lease expense associated with ROU assets is recognized on a straight-line basis over the lease term. Lease expense is reflected on the statement of consolidated operations commensurate with the leased activities and nature of the services performed. Gross fixed operating lease expense, inclusive of amounts billable to partners and other working interest owners, was $59 million and $114 million for the second quarter and first six months of 2019, respectively.

In addition, the Company periodically enters into finance leases that are similar to those leases classified as capital leases under previous GAAP. Finance lease assets are included in “Property and Equipment” on the consolidated balance sheet, and the associated finance lease liabilities are reflected within “Current debt” and “Long-term debt,” as applicable. Prior periods include the reclassification of $39 million finance lease obligations from “Other” within “Deferred Credits and Other Noncurrent Liabilities” to “Long-term debt” on the Company’s consolidated balance sheet to conform with this presentation. There was no material impact to the Company’s statement of consolidated operations and statement of consolidated cash flows for its treatment of finance leases. Depreciation on the Company’s finance lease assets was $2 million and $4 million for the second quarter and first six months of 2019, respectively. Interest on the Company’s finance lease assets was $1 million for both the second quarter and first six months of 2019.

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The following table represents the Company’s weighted average lease term and discount rate as of June 30, 2019:

	Operating Leases		Finance Leases
Weighted average remaining lease term	3.4 years		9.1 years
Weighted average discount rate	4.3	%	4.2	%

The undiscounted future minimum lease payments reconciled to the carrying value of the lease liabilities as of June 30, 2019 were as follows:

Net Minimum Commitments	Operating Leases(1)			Finance Leases(2)
	(In millions)
2019	$	101		$	16
2020	121			13
2021	47			3
2022	41			3
2023	24			3
Thereafter	41			40
Total future minimum lease payments	375			78
Less: imputed interest	(29		)	(15		)
Total lease liabilities	346			63
Current portion	(172		)	(25		)
Non-current portion	$	174		$	38

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

(2) Amounts represent the Company’s finance lease obligation related to physical power generators being leased on a one-year term with the right to purchase and a separate lease for the Company’s Midland, Texas regional office building.

The lease liability reflected in the table above represents the Company’s fixed minimum payments that are settled in accordance with the lease terms. Actual lease payments during the period may also include variable lease components such as common area maintenance, usage-based sales taxes and rate differentials, or other similar costs that are not determinable at the inception of the lease. Gross variable lease payments, inclusive of amounts billable to partners and other working interest owners, for the second quarter and first six months of 2019 were $24 million and $41 million, respectively.

New Pronouncements Issued But Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13, “Financial Instruments—Credit Losses.” The standard changes the impairment model for trade receivables, held-to-maturity debt securities, net investments in leases, loans, and other financial assets measured at amortized cost. The ASU requires the use of a new forward-looking “expected loss” model compared to the current “incurred loss” model, resulting in accelerated recognition of credit losses. This update is effective for the Company beginning in the first quarter of 2020, with early adoption permitted. The Company has developed and is in the process of executing a project plan for the implementation of the ASU and continues to evaluate and monitor standard setting activity. The Company does not believe the adoption and implementation of this ASU will have a material impact on its 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.

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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

2019 Activity

During the second quarter and first six months of 2019, Apache completed leasehold and property acquisitions for total cash consideration of $19 million and $34 million, respectively, primarily in its U.S. onshore regions.

In the second quarter of 2019, Apache completed the sale of certain non-core assets in Oklahoma that had a carrying value of $218 million for aggregate expected cash proceeds of approximately $231 million. The Company recognized a $13 million gain during the second quarter of 2019 in association with this sale. During the first six months of 2019, the Company also completed the sale of certain other non-core assets, primarily in the Permian region, in multiple transactions for total cash proceeds of $11 million. The Company recognized a total net gain of approximately $7 million upon closing of these transactions.

In May 2019, Apache separately entered into an agreement to sell non-core assets in Oklahoma and Texas for $367 million, subject to normal and customary closing adjustments, plus the assumption of asset retirement obligations of $49 million. As a result of the agreement, the Company performed a fair value assessment of the assets and recorded impairments of $240 million to the carrying value of proved and unproved oil and gas properties, other fixed assets, and working capital. The remaining balance of proved oil and gas properties totaling $379 million were classified as current assets held for sale, and the asset retirement obligations were classified as a current liability held for sale as of June 30, 2019. The transaction closed in the third quarter of 2019, and no material gain or loss is expected to be recognized.

2018 Activity

During the second quarter and first six months of 2018, Apache completed $26 million and $38 million, respectively, of leasehold and property acquisitions primarily in its U.S. onshore and Egypt regions. During the first six months of 2018, the Company also completed the sale of certain non-core assets, primarily in the Permian region, in multiple transactions for total cash proceeds of $13 million. The Company recognized a total net gain of approximately $9 million during the first six months upon closing of these transactions.

3.   CAPITALIZED EXPLORATORY WELL COSTS

The Company’s capitalized exploratory well costs were $124 million and $159 million at June 30, 2019 and December 31, 2018, 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, 2018 were charged to dry hole expense during the six months ended June 30, 2019. 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 proved reserves can be attributed to these projects.

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4.   DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

The Company is exposed to fluctuations in crude oil and natural gas prices, foreign currency exchange rates, and interest rates. The Company utilizes various types of derivative financial instruments to manage fluctuations in cash flows resulting from these fluctuations. 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 June 30, 2019, Apache had derivative positions with 7 counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, Apache may not realize the benefit of some of its derivative instruments resulting from changes in commodity prices, currency exchange rates, or interest rates.

Derivative Instruments

Commodity Derivative Instruments

As of June 30, 2019, Apache had the following open crude oil financial basis swap contracts:

Production Period	Settlement Index	Mbbls	Weighted Average Price Differential
July—September 2019	Midland-WTI/Cushing-WTI	2,484	$(8.60)
October—December 2019	Midland-WTI/Cushing-WTI	1,380	$(3.72)

As of June 30, 2019, Apache had the following open natural gas financial basis swap contracts:

Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential
July—December 2019	NYMEX Henry Hub/Waha	7,360	$(0.45)

Foreign Currency Derivative Instruments

Apache has open foreign currency costless collar contracts in GBP/USD for £12.5 million per each calendar month for 2019 with a weighted average floor and ceiling price of $1.20 and $1.35, respectively.

Altus Preferred Units Embedded Derivative

During the second quarter of 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units. Certain redemption features (the Redemption Option) embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. For further discussion of this derivative, see “Fair Value Measurements” below and Note 12—Redeemable Noncontrolling Interest - Altus.

Fair Value Measurements

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

The fair value of the Redemption Option, a Level 3 fair value measurement, was based on numerous factors including expected future interest rates using the Black-Karasinski model, imputed interest rate of Altus, the timing of periodic cash distributions, and dividend yields of the Preferred Units.

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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)
June 30, 2019
Assets:
Commodity Derivative Instruments	$	—	$	5	$	—	$	5	$	(4	)	$	1
Foreign Currency Derivative Instruments	—		—		—		—		—			—
Liabilities:
Commodity Derivative Instruments	—		27		—		27		(4		)	23
Preferred Units Embedded Derivative	—		—		94		94		—			94
December 31, 2018
Assets:
Commodity Derivative Instruments	$	—	$	69	$	—	$	69	$	(14	)	$	55
Liabilities:
Commodity Derivative Instruments	—		25		—		25		(14		)	11

(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:

	June 30, 2019		December 31, 2018
	(In millions)
Current Assets: Other current assets	$	1	$	55
Total Assets	$	1	$	55
Current Liabilities: Other current liabilities	$	23	$	11
Deferred Credits and Other Noncurrent Liabilities: Other	94		—
Total Liabilities	$	117	$	11

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 June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions)
Realized gain (loss):
Derivative settlements, realized gain (loss)	$	13		$	(75	)	$	28		$	(117	)
Amortization of put premium, realized loss	—			(5		)	—			(10		)
Unrealized gain (loss)	(21		)	55			(66		)	104
Derivative instrument losses, net	$	(8	)	$	(25	)	$	(38	)	$	(23	)

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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 losses (gains), net” in “Adjustments to reconcile net income (loss) to net cash provided by operating activities.”

5. OTHER CURRENT ASSETS

The following table provides detail of the Company’s other current assets as of June 30, 2019 and December 31, 2018:

	June 30, 2019		December 31, 2018
	(In millions)
Inventories	$	453	$	401
Drilling advances	226		218
Assets held for sale	379		—
Prepaid assets and other	86		160
Total other current assets	$	1,144	$	779

6. EQUITY METHOD INTERESTS

Apache, through its ownership of Altus, has the following equity method interests in Permian Basin long-haul pipeline entities. For each of the equity method interests, Altus has the ability to exercise significant influence based on certain governance provisions and its participation in activities and decisions that impact the management and economic performance of the equity method interests.

	June 30, 2019				December 31, 2018
	Interest		Amount		Interest		Amount
	($ in millions)
Gulf Coast Express Pipeline LLC	16.0	%	$	251	15.0	%	$	91
EPIC Crude Holdings, LP	15.0	%	105		—		—
Permian Highway Pipeline LLC	26.7	%	171		—		—
			$	527			$	91

Altus’ underlying equity in the separate net assets within the financial statements of the respective entities as of June 30, 2019 and December 31, 2018 were $14 million less and $6 million more, respectively, than its equity method interest balances. Unamortized differences in the basis of the initial investments and Apache’s interest in the separate net assets within the financial statements of the investee will be amortized into net income over the useful lives of the underlying pipeline assets when they are placed into service.

The following table presents the activity in Apache’s equity method interests for the six months ended June 30, 2019:

	Gulf Coast Express Pipeline LLC(1)		EPIC Crude Holdings, LP			Permian Highway Pipeline LLC		Total
	(In millions)
Balance at December 31, 2018	$	91	$	—		$	—	$	91
Acquisitions	15		52			161		228
Capital contributions	144		56			10		210
Income (loss) from equity method interests	1		(3		)	—		(2		)
Balance at June 30, 2019	$	251	$	105		$	171	$	527

(1) In the second quarter of 2019, Altus Midstream LP exercised its option to acquire an additional 1 percent interest in the Gulf Coast Express Pipeline project, resulting in a total ownership of 16 percent at June 30, 2019.

As of December 31, 2018, Apache also held an investment in Marine Well Containment Company. This investment was sold in the first quarter of 2019 for $30 million, with no gain or loss recorded on the sale.

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Exercise of Option in the Shin Oak Pipeline

Effective July 31, 2019, Altus Midstream Processing LP, a subsidiary of Altus Midstream, closed its option to acquire a 33.0 percent equity interest in the Shin Oak NGL pipeline project (Shin Oak) for approximately $441 million. Shin Oak comprises a 24-inch diameter mainline and related 20-inch lateral pipeline. The project, which is already in service, is expected to have ultimate capacity of approximately 550 MBbl/d and transports NGLs primarily from the Permian Basin to Mont Belvieu, Texas.

Shin Oak is owned and operated by Breviloba LLC (Breviloba), a subsidiary of Enterprise Products Partners, LP (Enterprise). Following closing of the option, Breviloba is 33.0 percent owned by Altus Midstream Processing LP and 67.0 percent owned by Enterprise.

7. OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities as of June 30, 2019 and December 31, 2018:

	June 30, 2019		December 31, 2018
	(In millions)
Accrued operating expenses	$	78	$	65
Accrued exploration and development	535		667
Accrued gathering, processing, and transmission - Altus	34		81
Accrued compensation and benefits	135		177
Accrued interest	117		137
Accrued income taxes	126		58
Current asset retirement obligation	66		66
Current operating lease liability	172		—
Liabilities held for sale	49		—
Other	131		90
Total other current liabilities	$	1,443	$	1,341

8. ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the six-month period ended June 30, 2019:

	(In millions)
Asset retirement obligation at December 31, 2018	$	1,932
Liabilities incurred	7
Liabilities settled	(21		)
Liabilities divested	(6		)
Liabilities held for sale	(49		)
Accretion expense	53
Asset retirement obligation at June 30, 2019	1,916
Less current portion	(66		)
Asset retirement obligation, long-term	$	1,850

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9. 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 second quarters of 2019 and 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.

Apache’s 2019 and 2018 year-to-date effective income tax rates were primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets.

Apache and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. The Company is currently under IRS audit for the 2014-2017 tax years and is also under audit in various states and foreign jurisdictions as part of its normal course of business.

10. DEBT AND FINANCING COSTS

The following table presents the carrying value of the Company’s debt as of June 30, 2019 and December 31, 2018:

	June 30, 2019			December 31, 2018
	(In millions)
Notes and debentures before unamortized discount and debt issuance costs(1)	$	8,367		$	8,299
Finance lease obligations	63			40
Unamortized discount	(43		)	(44		)
Debt issuance costs	(55		)	(51		)
Total debt	8,332			8,244
Current maturities	(175		)	(151		)
Long-term debt	$	8,157		$	8,093

(1) The fair value of the Company’s notes and debentures was $8.6 billion and $7.8 billion as of June 30, 2019 and December 31, 2018, respectively. Apache uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

As of June 30, 2019, current debt included $150 million of 7.625% senior notes due July 1, 2019 and $25 million of finance lease obligations. On July 1, 2019, Apache’s 7.625% senior notes in original principal amount of $150 million matured and were repaid. As of December 31, 2018, current debt included $150 million of 7.625% senior notes due July 1, 2019 and $1 million of finance lease obligations.

On June 19, 2019, Apache closed offerings of $1.0 billion in aggregate principal amount of senior unsecured notes, comprised of $600 million in aggregate principal amount of 4.250% notes due January 15, 2030 and $400 million in aggregate principal amount of 5.350% notes due July 1, 2049. The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers and for general corporate purposes.

On June 21, 2019, the Company closed cash tender offers for certain outstanding notes. Apache accepted for purchase $932 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate of approximately $1.0 billion reflecting principal, the net premium to par, early tender premium, and accrued and unpaid interest. The Company recorded a net loss of $75 million on extinguishment of debt, including $7 million of unamortized debt issuance costs and discount, in connection with the note purchases.

In March 2018, the Company entered into a revolving credit facility with commitments totaling $4.0 billion. In March 2019, the term of this facility was extended by one year to March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exercise of an extension option. The Company can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of June 30, 2019. The facility is for general corporate purposes, and committed

16

borrowing capacity fully supports Apache’s commercial paper program. As of June 30, 2019, letters of credit aggregating approximately £3.1 million and no borrowings were outstanding under this facility.

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 June 30, 2019, the Company had no commercial paper outstanding.

In November 2018, Altus Midstream LP entered into a revolving credit facility for general corporate purposes that matures in November 2023 (subject to Altus Midstream LP’s two, one-year extension options). The agreement for this facility, as amended, provides aggregate commitments from a syndicate of banks of $650 million until the consolidated net income of Altus Midstream LP and its restricted subsidiaries, as adjusted pursuant to the agreement, for the immediately preceding fiscal quarter equals or exceeds $175 million on an annualized basis (such period, the Initial Period). Following the Initial Period, the aggregate commitments equal $800 million. All aggregate commitments include a letter of credit subfacility of up to $100 million and a swingline loan subfacility of up to $100 million. After the Initial Period, Altus Midstream LP may increase commitments up to an aggregate $1.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. As of June 30, 2019 and December 31, 2018, no borrowings or letters of credit were outstanding under this facility. The Altus Midstream LP credit facility is unsecured and is not guaranteed by Apache or any of Apache’s other subsidiaries.

Financing Costs, Net

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

	For the Quarter Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions)
Interest expense	$	109		$	110		$	216		$	222
Amortization of deferred loan costs	1			1			3			6
Capitalized interest	(9		)	(13		)	(17		)	(25		)
Loss on extinguishment of debt	75			—			75			—
Interest income	(3		)	(4		)	(7		)	(10		)
Financing costs, net	$	173		$	94		$	270		$	193

11. 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 June 30, 2019, 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 9—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, 2018.

Argentine Environmental Claims and Argentina Tariff

No material change in the status of the YPF Sociedad Anónima indemnities matter has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018. Regarding the Pioneer Natural Resources Company indemnities matter, Company subsidiaries, on one hand, and Pioneer Natural Resources Company and TDF Holdings Company LDC, on the other, have settled and voluntarily dismissed certain indemnity-related claims against each other in a case captioned Apache Corporation, et al. v. Pioneer Natural Resources Co., et al., Cause No. 2014-64407, pending in the 189^th Judicial District of Harris County, Texas. Company subsidiaries retain certain rights to enforce certain Argentina-related indemnification obligations

17

against Pioneer pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer.

Louisiana Restoration 

As more fully described in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018, 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 2019, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including Apache. These cases have all been removed to federal courts in Louisiana. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable 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, 2018.

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 recently entered its order granting summary judgment in favor of Apache and finding that the plaintiffs had presented no evidence of damages. The plaintiffs have appealed. 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, 2018.

Australian Operations Divestiture Dispute

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

California Litigation

On July 17, 2017, in three separate actions, San Mateo County, California, Marin County, California, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil, gas, and coal companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County and in a separate action on January 22, 2018, the City of Richmond, filed similar lawsuits against many of the same defendants. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants. Apache believes that the claims made against it are baseless and intends to vigorously defend these lawsuits.

18

Castex Lawsuit

In a case styled Apache Corporation v. Castex Offshore, Inc, et. al., Cause No. 2015-48580, in the 113rd Judicial District Court of Harris County, Texas, Castex filed claims for alleged damages which they recently disclosed to be approximately $200 million, relating to overspend on the Belle Isle Gas Facility upgrade, and the drilling of five sidetracks on the Potomac #3 Well. After a jury trial, a verdict of approximately $60 million was entered against Apache. Apache intends to appeal.

Environmental Matters

As of June 30, 2019, the Company had an undiscounted reserve for environmental remediation of approximately $3 million. The Company is not aware of any environmental claims existing as of June 30, 2019 that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

12. REEDEMABLE NONCONTROLLING INTEREST - ALTUS

Preferred Units Issuance

On June 12, 2019, Altus Midstream LP, an indirectly controlled subsidiary of Apache, issued and sold Series A Cumulative Redeemable Preferred Units (the Preferred Units) for an aggregate issue price of $625 million in a private offering exempt from the registration requirements of the Securities Act of 1933 (the Closing). Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. Pursuant to the partnership agreement of Altus Midstream LP:

• The Preferred Units bear quarterly distributions at a rate of 7 percent per annum, increasing after the fifth anniversary of Closing and upon the occurrence of specified events. Altus Midstream LP may pay distributions in-kind for the first six quarters after the Preferred Units are issued.

• The Preferred Units are redeemable at Altus Midstream LP’s option at any time in cash at a redemption price (the Redemption Price) equal to the greater of an 11.5 percent internal rate of return (increasing after the fifth anniversary of Closing to 13.75 percent) and a 1.3x multiple of invested capital. The Preferred Units will be redeemable at the holder’s option upon a change of control or liquidation of Altus Midstream LP and certain other events, including certain asset dispositions.

• The Preferred Units will be exchangeable for shares of ALTM’s Class A common stock at the holder’s election after the seventh anniversary of Closing or upon the occurrence of specified events. Each Preferred Unit will be exchangeable for a number of shares of ALTM’s Class A common stock equal to the Redemption Price divided by the volume-weighted average trading price of ALTM’s Class A common stock on the NASDAQ Capital Market for the 20 trading days immediately preceding the second trading day prior to the applicable exchange date, less a 6 percent discount.

• Each outstanding Preferred Unit has a liquidation preference equal to the Redemption Price payable before any amounts are paid in respect of Altus Midstream LP’s common units and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation.

• Preferred Units holders have rights to approve certain partnership business, financial, and governance-related matters.

• Altus Midstream LP is restricted from declaring or making cash distributions on its common units until all required distributions on the Preferred Units have been paid. In addition, before the fifth anniversary of Closing, aggregate cash distributions on, and redemptions of, Altus Midstream LP’s common units are limited to $650 million of cash from ordinary course operations if permitted under its credit facility. Cash distributions on, and redemptions of, Altus Midstream LP’s common units also are subject to satisfaction of leverage ratio requirements specified in its partnership agreement.

Classification

The Preferred Units are accounted for on the Company’s consolidated balance sheets as a redeemable noncontrolling interest classified as temporary equity based on the terms of the Preferred Units, including the redemption rights with respect thereto.

Initial Measurement

Altus recorded the net transaction price of $611 million, calculated as the negotiated transaction price of $625 million, less issue discounts of $4 million and transaction costs totaling $10 million.

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Certain redemption features embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. Altus bifurcated and recognized at fair value an embedded derivative related to the Preferred Units of $94 million for a redemption option of the Preferred Unit holders. The derivative is reflected in “Other” within “Deferred Credits and Other Noncurrent Liabilities” on the Company’s consolidated balance sheet. The fair value of the embedded derivative, a Level 3 fair value measurement, was based on numerous factors including expected future interest rates using the Black-Karasinski model, imputed interest rate of Altus, the timing of periodic cash distributions, and dividend yields of the Preferred Units. See Note 4—Derivative Instruments and Hedging Activities for more detail.

The net transaction price was allocated to the preferred redeemable noncontrolling interest and the embedded features according to the associated initial fair value measurements as follows:

	June 12, 2019
	(In millions)
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners	$	517
Preferred Units embedded derivative	94
	$	611

Subsequent Measurement

Altus applies a two-step approach to subsequent measurement of the redeemable noncontrolling interest related to the Preferred Units by first allocating a portion of the net income of Altus Midstream LP in accordance with the terms of the partnership agreement. An additional adjustment to the carrying value of the Preferred Unit redeemable noncontrolling interest at each period end may be recorded, if applicable. The amount of such adjustment is determined based upon the accreted value method to reflect the passage of time until the Preferred Units are exchangeable at the option of the holder. Pursuant to this method, the net transaction price is accreted using the effective interest method to the Redemption Price calculated at the seventh anniversary of Closing. The total adjustment is limited to an amount such that the carrying amount of the Preferred Unit redeemable noncontrolling interest at each period end is equal to the greater of (a)(i) the carrying amount of the Preferred Units, plus (ii) the fair value of the embedded derivative liability or (b) the accreted value of the net transaction price.

Activity related to the Preferred Units during the six months ended June 30, 2019 is as follows:

	Units Outstanding	Financial Position(2)
	(In millions, except unit data)
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners: beginning of period	—	$	—
Issuance of Preferred Units, net	625,000	517
Allocation of Altus Midstream LP net income(1)	N/A	3
Accreted value adjustment	N/A	1
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners: end of period	625,000	521
Preferred Units embedded derivative		94
		$	615

(1) Subsequent to the balance sheet date, Altus Midstream LP provided notice to the Preferred Unit holders of record at June 30, 2019 of the amount of the initial distribution on the Preferred Units for the period from Closing to June 30, 2019. The holders also were notified that Altus Midstream LP elected to pay the entire amount of the approximate $2 million distribution in-kind in additional Preferred Units (PIK Units) on August 14, 2019. In total, 2,187.5 PIK Units will be issued in satisfaction of the initial required distribution.

(2) As at June 30, 2019, the aggregate Redemption Price was $628 million, based on an internal rate of return of 11.5 percent.

N/A - not applicable.

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13. CAPITAL STOCK

Net Income (Loss) per Common Share

A reconciliation of the components of basic and diluted net income (loss) per common share for the quarters and six months ended June 30, 2019 and 2018, is presented in the table below.

 

	For the Quarter Ended June 30,
	2019							2018
	Loss			Shares	Per Share			Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock	$	(360	)	377	$	(0.96	)	$	195	382	$	0.51
Effect of Dilutive Securities:
Stock options and other	—			—	—			—		3	—
Diluted:
Income (loss) attributable to common stock	$	(360	)	377	$	(0.96	)	$	195	385	$	0.51

	For the Six Months Ended June 30,
	2019							2018
	Loss			Shares	Per Share			Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock	$	(407	)	376	$	(1.08	)	$	340	382	$	0.89
Effect of Dilutive Securities:
Stock options and other	—			—	—			—		2	(0.01		)
Diluted:
Income (loss) attributable to common stock	$	(407	)	376	$	(1.08	)	$	340	384	$	0.88

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 5.0 million and 5.9 million for the quarters ended June 30, 2019 and 2018, respectively, and 5.3 million and 6.4 million for the six months ended June 30, 2019 and 2018, respectively. The impact to net income (loss) attributable to common stock of an assumed conversion of the redeemable noncontrolling Preferred Units interests in Altus Midstream LP were anti-dilutive for the three- and six-month periods ended June 30, 2019.

Common Stock Dividends

For the quarters ended June 30, 2019 and 2018, Apache paid $94 million and $96 million, respectively, in dividends on its common stock. For the six months ended June 30, 2019 and 2018, the Company paid $188 million and $191 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 from time to time either in the open market or through privately negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through June 30, 2019, had repurchased a total of 40 million shares at an average price of $79.18 per share. During the fourth quarter of 2018, the Company’s Board of Directors authorized the purchase of up to 40 million additional shares of the Company’s common stock. The Company is not obligated to acquire any specific number of shares and has not purchased any shares during 2019.

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14. BUSINESS SEGMENT INFORMATION

As of June 30, 2019, Apache is engaged in exploration and production (Upstream) activities across three operating segments: Egypt, the North Sea, and the U.S. Apache also has exploration interests in Suriname that may, over time, result in a reportable discovery and development opportunity. Apache’s Upstream business explores for, develops, and produces natural gas, crude oil and natural gas liquids. During the fourth quarter of 2018, Apache established a new reporting segment for its U.S. midstream business separate from its upstream oil and gas development activities. The midstream business is operated by Altus, which owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas, anchored by midstream service contracts to Apache’s production from its Alpine High resource play. Altus primarily generates revenue by providing fee-based natural gas gathering, compression, processing, and transportation services. Financial information for each segment is presented below:

	Egypt(1)		North Sea		U.S.			Altus			Intersegment Eliminations & Other			Total(2)
	Upstream							Midstream
	(In millions)
For the Quarter Ended June 30, 2019
Oil revenues	$	523	$	337	$	537		$	—		$	—		$	1,397
Natural gas revenues	70		18		30			—			—			118
Natural gas liquids revenues	3		5		75			—			—			83
Oil and gas production revenues	596		360		642			—			—			1,598
Midstream service affiliate revenues	—		—		—			24			(24		)	—
Operating Expenses:
Lease operating expenses	132		92		166			—			(1		)	389
Gathering, processing, and transmission	10		11		64			14			(23		)	76
Taxes other than income	—		—		42			4			—			46
Exploration	30		1		59			—			5			95
Depreciation, depletion, and amortization	174		99		320			9			—			602
Asset retirement obligation accretion	—		18		8			—			—			26
Impairments	—		—		240			—			—			240
	346		221		899			27			(19		)	1,474
Operating Income (Loss)(3)	$	250	$	139	$	(257	)	$	(3	)	$	(5	)	124
Other Income (Expense):
Gain on divestitures														17
Derivative instrument losses, net														(8		)
Other(4)														(4		)
General and administrative														(102		)
Transaction, reorganization, and separation														(6		)
Financing costs, net														(173		)
Loss Before Income Taxes														$	(152	)

22

	Egypt(1)		North Sea		U.S.			Altus			Intersegment Eliminations & Other			Total(2)
	Upstream							Midstream
	(In millions)
For the Six Months Ended June 30, 2019
Oil revenues	$	1,037	$	637	$	1,033		$	—		$	—		$	2,707
Natural gas revenues	151		50		153			—			—			354
Natural gas liquids revenues	7		11		173			—			—			191
Oil and gas production revenues	1,195		698		1,359			—			—			3,252
Midstream service affiliate revenues	—		—		—			58			(58		)	—
Operating Expenses:
Lease operating expenses	250		164		342			—			(2		)	754
Gathering, processing, and transmission	22		23		145			30			(56		)	164
Taxes other than income	—		—		91			6			—			97
Exploration	62		2		92			—			8			164
Depreciation, depletion, and amortization	361		198		673			16			—			1,248
Asset retirement obligation accretion	—		37		15			1			—			53
Impairments	—		—		240			—			—			240
	695		424		1,598			53			(50		)	2,720
Operating Income (Loss)(3)	$	500	$	274	$	(239	)	$	5		$	(8	)	532
Other Income (Expense):
Gain on divestitures														20
Derivative instrument losses, net														(38		)
Other(4)														4
General and administrative														(225		)
Transaction, reorganization, and separation														(10		)
Financing costs, net														(270		)
Income Before Income Taxes														$	13
Total Assets(5)	$	4,035	$	2,568	$	12,710		$	2,434		$	59		$	21,806
For the Quarter Ended June 30, 2018
Oil revenues	$	649	$	320	$	607		$	—		$	—		$	1,576
Natural gas revenues	89		27		96			—			—			212
Natural gas liquids revenues	4		5		139			—			—			148
Oil and gas production revenues	742		352		842			—			—			1,936
Midstream service affiliate revenues	—		—		—			12			(12		)	—
Operating Expenses:
Lease operating expenses	106		78		172			—			—			356
Gathering, processing, and transmission	11		10		62			11			(12		)	82
Taxes other than income	—		—		47			2			—			49
Exploration	32		3		40			—			1			76
Depreciation, depletion, and amortization	192		96		315			5			—			608
Asset retirement obligation accretion	—		19		8			—			—			27
Impairments	—		—		—			—			—			—
	341		206		644			18			(11		)	1,198
Operating Income (Loss)(3)	$	401	$	146	$	198		$	(6	)	$	(1	)	738
Other Income (Expense):
Gain on divestitures														2
Derivative instrument losses, net														(25		)
Other(4)														16
General and administrative														(117		)
Transaction, reorganization, and separation														(12		)
Financing costs, net														(94		)
Income Before Income Taxes														$	508

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	Egypt(1)		North Sea		U.S.		Altus			Intersegment Eliminations & Other			Total(2)
	Upstream						Midstream
	(In millions)
For the Six Months Ended June 30, 2018
Oil revenues	$	1,218	$	591	$	1,160	$	—		$	—		$	2,969
Natural gas revenues	177		51		206		—			—			434
Natural gas liquids revenues	7		9		250		—			—			266
Oil and gas production revenues	1,402		651		1,616		—			—			3,669
Midstream service affiliate revenues	—		—		—		24			(24		)	—
Operating Expenses:
Lease operating expenses	204		172		329		—			—			705
Gathering, processing, and transmission	23		20		127		22			(24		)	168
Taxes other than income	—		—		99		5			—			104
Exploration	60		17		73		—			2			152
Depreciation, depletion, and amortization	378		191		584		8			—			1,161
Asset retirement obligation accretion	—		37		16		1			—			54
Impairments	—		—		—		—			—			—
	665		437		1,228		36			(22		)	2,344
Operating Income (Loss)(3)	$	737	$	214	$	388	$	(12	)	$	(2	)	1,325
Other Income (Expense):
Gain on divestitures													9
Derivative instrument losses, net													(23		)
Other(4)													21
General and administrative													(231		)
Transaction, reorganization, and separation													(12		)
Financing costs, net													(193		)
Income Before Income Taxes													$	896
Total Assets(5)	$	4,471	$	3,148	$	13,311	$	939		$	41		$	21,910

(1) Includes revenue from non-customers for the second quarters and six-month periods of 2019 and 2018 of:

	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(In millions)
Oil	$	111	$	165	$	218	$	304
Natural gas	9		15		21		30
Natural gas liquids	—		1		1		2

(2) Includes a noncontrolling interest in Egypt for the 2019 and 2018 periods, and Altus for the 2019 period.

(3) The operating income of U.S. and Egypt includes leasehold and other asset impairments totaling $277 million and $2 million, respectively, for the second quarter of 2019. The operating income of U.S. and Egypt includes leasehold and other asset impairments totaling $298 million and $4 million, respectively, for the first six months of 2019. The operating income of U.S. includes leasehold impairments totaling $21 million and $37 million for the second quarter and first six months of 2018, respectively.

(4) Included in Other are sales proceeds related to U.S. third-party purchased oil and gas which are determined to be revenue from customers. Proceeds for these volumes totaled $18 million and $98 million for the second quarters of 2019 and 2018, respectively, and $42 million and $202 million for the first six months of 2019 and 2018, respectively.

(5) Intercompany balances are excluded from total assets.

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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, 2018.

Overview

Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. The Company’s upstream business 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. Apache’s midstream business is operated by Altus Midstream Company through its subsidiary Altus Midstream LP (collectively, Altus), which owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas, anchored by midstream service contracts to Apache’s production from its Alpine High resource play. Altus primarily generates revenue by providing fee-based natural gas gathering, compression, processing, and transportation services.

Apache’s U.S. assets are complemented by its international assets in Egypt and the North Sea, each of which adds to the Company’s inventory of exploration and development opportunities and generates cash flows in excess of current capital investments, facilitating the Company’s ability to develop its onshore Permian properties while maintaining financial flexibility in a volatile commodity price environment. Apache’s diverse regional portfolio and asset inventory includes, at scale, both conventional and unconventional resources covering oil, rich gas with NGLs, and lean gas. This range of assets provides optionality to fund a capital program capable of delivering a sustainable combination of long-term returns with a moderate pace of growth. Consistent with this strategy, Apache is closely monitoring oil, NGL, and natural gas fundamentals and will allocate capital within its portfolio in response to price signals.

The Company generated $1.5 billion in cash from operating activities during the first half of 2019, a decrease of 16 percent from the comparative prior-year period, driven by reduced revenues from lower realized commodity prices. Apache continuously monitors changes in its operating environment and has the ability, with its dynamic capital allocation process, to adjust the Company’s capital investment program to levels commensurate with cash from operating activities and to maximize value for Apache’s shareholders over the long term. In light of the lower commodity price environment at the end of 2018, Apache curtailed its 2019 upstream development program, with capital costs incurred for the second quarter and first six months of 2019 reflecting reductions of 17 percent and 18 percent, respectively, from the comparative 2018 periods.

Apache reported a second quarter loss of $360 million, or $0.96 per common share, compared to income of $195 million, or $0.51 per common share, in the second quarter of 2018. The decrease in net income compared to the prior-year quarter is primarily the result of lower commodity price realizations and asset impairments on divested properties. Daily production in the second quarter of 2019 averaged 455 Mboe/d, a decrease of 2 percent from the comparative prior-year quarter driven primarily by natural decline in Egypt, the Company’s exit from the Woodford-SCOOP and STACK plays in central Oklahoma, and shut-in production on gas properties at Alpine High resulting from localized low gas price realizations.

Operating Highlights

Key operational highlights for the quarter include:

United States

• U.S. onshore equivalent production increased 3 percent from the second quarter of 2018, a reflection of the success of the Midland Basin drilling program and the commencement and continued production ramp-up at Alpine High.

• Second quarter equivalent production from the Permian region, which accounts for 86 percent of Apache’s total U.S. production, increased 12 percent from the second quarter of 2018, which was driven by continued production ramp-up at Alpine High and strong performance in the Midland Basin.

• Production increases were negatively impacted by natural gas prices at the Waha hub where Permian Basin production exceeded West Texas takeaway capacity. Gas prices traded at historic lows, and at times were negative, for portions of the second quarter of 2019. This gas pricing prompted the Company to curtail production for a majority of its Alpine High lean gas and a portion of its rich gas volumes. Deferrals will continue until Waha prices improve, which is anticipated when the third-party operated Gulf Coast Express (GCX) pipeline enters service in late September.

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• Altus Midstream’s first two cryogenic processing plants entered service on-budget and on schedule in May and July, respectively. The first plant has already exceeded nameplate capacity, the second plant is currently ramping inlet volumes, and a third plant under construction is scheduled for start-up around year-end 2019.

International

• The Egypt region’s gross equivalent production decreased 6 percent and net production decreased 15 percent from the second quarter of 2018 primarily a result of natural decline and the lower number of wells brought on-line during the period. The region’s extensive 3 million-acre broadband seismic acquisition program is nearly two-thirds complete, and this initiative should generate significant drilling opportunities on both new and legacy acreage holdings.

• The North Sea region averaged 3 rigs and drilled 2 gross wells during the second quarter of 2019. The region’s daily production increased 10 percent from the second quarter 2018, primarily the result of production from the Garten field which came on-line in November 2018. Continued activity in the region is focused on bringing the Storr exploration discovery on-line in the fourth quarter, as well as a second well at Garten.

• The Company continues to progress its exploration efforts in Suriname. A drillship has been contracted, and the Company anticipates spudding its first well on the 100 percent-owned Block 58 during the third quarter of 2019.

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Results of Operations

Oil and Gas Revenues

The table below presents the second-quarter and year-to-date 2019 and 2018 revenues by geographic region and each region’s percent contribution to revenues.

	For the Quarter Ended June 30,								For the Six Months Ended June 30,
	2019				2018				2019				2018
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution
	($ in millions)
Total Oil Revenues:
United States	$	537	38	%	$	607	39	%	$	1,033	38	%	$	1,160	39	%
Egypt (1)	523		38	%	649		41	%	1,037		38	%	1,218		41	%
North Sea	337		24	%	320		20	%	637		24	%	591		20	%
Total (1)	$	1,397	100	%	$	1,576	100	%	$	2,707	100	%	$	2,969	100	%
Total Natural Gas Revenues:
United States	$	30	25	%	$	96	45	%	$	153	43	%	$	206	47	%
Egypt (1)	70		60	%	89		42	%	151		43	%	177		41	%
North Sea	18		15	%	27		13	%	50		14	%	51		12	%
Total (1)	$	118	100	%	$	212	100	%	$	354	100	%	$	434	100	%
Total Natural Gas Liquids (NGL) Revenues:
United States	$	75	90	%	$	139	94	%	$	173	91	%	$	250	94	%
Egypt (1)	3		4	%	4		3	%	7		3	%	7		3	%
North Sea	5		6	%	5		3	%	11		6	%	9		3	%
Total (1)	$	83	100	%	$	148	100	%	$	191	100	%	$	266	100	%
Total Oil and Gas Revenues:
United States	$	642	40	%	$	842	43	%	$	1,359	42	%	$	1,616	44	%
Egypt (1)	596		37	%	742		39	%	1,195		37	%	1,402		38	%
North Sea	360		23	%	352		18	%	698		21	%	651		18	%
Total (1)	$	1,598	100	%	$	1,936	100	%	$	3,252	100	%	$	3,669	100	%

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

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Production

The table below presents the second-quarter and year-to-date 2019 and 2018 production and the relative increase or decrease from the prior period.

	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2019	Increase (Decrease)		2018	2019	Increase (Decrease)		2018
Oil Volume – b/d
United States	103,010	(2	)%	105,163	105,878	3	%	102,470
Egypt(1)(2)	83,761	(13	)%	96,185	87,667	(8	)%	95,730
North Sea	50,055	8	%	46,150	52,279	13	%	46,249
Total	236,826	(4	)%	247,498	245,824	1	%	244,449
Natural Gas Volume – Mcf/d
United States	594,238	8	%	547,777	668,858	29	%	518,324
Egypt(1)(2)	277,552	(19	)%	340,991	296,425	(13	)%	342,438
North Sea	50,121	16	%	43,297	53,488	27	%	42,174
Total	921,911	(1	)%	932,065	1,018,771	13	%	902,936
NGL Volume – b/d
United States	61,974	5	%	59,036	60,428	10	%	55,182
Egypt(1)(2)	898	(20	)%	1,127	1,023	(1	)%	1,033
North Sea	1,673	52	%	1,104	1,748	54	%	1,135
Total	64,545	5	%	61,267	63,199	10	%	57,350
BOE per day(3)
United States	264,024	3	%	255,495	277,782	14	%	244,039
Egypt(1)(2)	130,917	(15	)%	154,144	138,094	(10	)%	153,836
North Sea(4)	60,082	10	%	54,470	62,942	16	%	54,413
Total	455,023	(2	)%	464,109	478,818	6	%	452,288

(1) Gross oil, natural gas, and NGL production in Egypt for the second quarter and six-month period of 2019 and 2018 were as follows:

	For the Quarter Ended June 30,		For the Six Months Ended June 30,
	2019	2018	2019	2018
Oil (b/d)	198,534	206,296	201,245	204,264
Natural Gas (Mcf/d)	729,378	801,727	742,474	780,121
NGL (b/d)	1,840	1,719	1,952	1,598

(2) Includes production volumes per day attributable to a noncontrolling interest in Egypt for the second quarter and six-month period of 2019 and 2018 of:

	For the Quarter Ended June 30,		For the Six Months Ended June 30,
	2019	2018	2019	2018
Oil (b/d)	27,939	32,066	29,239	31,921
Natural Gas (Mcf/d)	92,639	113,846	98,990	114,377
NGL (b/d)	299	376	341	344

(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 second quarter of 2019 and 2018 were 64,156 boe/d and 56,516 boe/d, respectively, and 63,669 boe/d and 55,113 boe/d for the first six months of 2019 and 2018, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

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Pricing

The table below presents second-quarter and year-to-date 2019 and 2018 pricing and the relative increase or decrease from the prior period.

	For the Quarter Ended June 30,						For the Six Months Ended June 30,
	2019		Increase (Decrease)		2018		2019		Increase (Decrease)		2018
Average Oil Price - Per barrel
United States	$	57.25	(10	)%	$	63.27	$	53.90	(14	)%	$	62.54
Egypt	68.60		(7	)%	74.14		65.36		(7	)%	70.26
North Sea	68.43		(6	)%	73.05		66.35		(5	)%	69.58
Total	63.71		(8	)%	69.35		60.65		(9	)%	66.90
Average Natural Gas Price - Per Mcf
United States	$	0.55	(72	)%	$	1.94	$	1.26	(43	)%	$	2.20
Egypt	2.80		(2	)%	2.85		2.82		(1	)%	2.85
North Sea	3.99		(41	)%	6.82		5.18		(23	)%	6.71
Total	1.41		(44	)%	2.50		1.92		(28	)%	2.65
Average NGL Price - Per barrel
United States	$	13.57	(48	)%	$	26.03	$	15.96	(36	)%	$	25.10
Egypt	32.90		(19	)%	40.80		35.56		(8	)%	38.72
North Sea	33.67		(25	)%	44.71		37.27		(15	)%	43.75
Total	14.37		(46	)%	26.64		16.87		(34	)%	25.72

Second-Quarter 2019 compared to Second-Quarter 2018

Crude Oil Revenues Crude oil revenues for the second quarter of 2019 totaled $1.4 billion, a $179 million decrease from the comparative 2018 quarter. An 8 percent decrease in average realized prices decreased second-quarter 2019 revenues by $129 million compared to the prior-year quarter, while 4 percent lower average daily production decreased revenues by $50 million. Crude oil accounted for 87 percent of oil and gas production revenues and 52 percent of worldwide production in the second quarter of 2019. Crude oil prices realized in the second quarter of 2019 averaged $63.71 per barrel, compared with $69.35 per barrel in the comparative prior-year quarter.

Worldwide oil production decreased 10.7 Mb/d to 236.8 Mb/d in the second quarter of 2019 from the comparative prior-year period, primarily a result of lower gross production due to natural decline in Egypt, partially offset by an increase in the North Sea from the Garten field coming on-line in November 2018.

Natural Gas Revenues Gas revenues for the second quarter of 2019 totaled $118 million, a $94 million decrease from the comparative 2018 quarter. A 44 percent decrease in average realized prices decreased second-quarter 2019 revenues by $92 million compared to the prior-year quarter, while 1 percent lower average daily production decreased revenues by $2 million. Natural gas accounted for 7 percent of Apache’s oil and gas production revenues and 34 percent of its equivalent production during the second quarter of 2019.

Worldwide natural gas production decreased 10 MMcf/d to 922 MMcf/d in the second quarter of 2019 from the comparative prior-year period, primarily a result of lower gross production due to general decline in Egypt and the sale of the Company’s Woodford-SCOOP and STACK plays. These decreases are partially offset by increased production from the Alpine High development.

Production increases were negatively impacted by natural gas prices at the Waha hub where Permian Basin production exceeded West Texas takeaway capacity. Gas prices traded at historic lows, and at times were negative, for portions of the second quarter of 2019. This gas pricing prompted the Company to curtail production for a majority of its Alpine High lean gas and a portion of its rich gas volumes. Deferrals will continue until Waha prices improve, which is anticipated when the third-party operated GCX pipeline enters service in late September.

NGL Revenues NGL revenues for the second quarter of 2019 totaled $83 million, a $65 million decrease from the comparative 2018 quarter. A 46 percent decrease in average realized prices decreased second-quarter 2019 revenues by $68 million compared to the prior-year quarter, while 5 percent higher average daily production increased revenues by $3 million. NGLs accounted for

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6 percent of Apache’s oil and gas production revenues and 14 percent of its equivalent production during the second quarter of 2019.

Worldwide production of NGLs increased 3.3 Mb/d to 64.5 Mb/d in the second quarter of 2019 from the comparative prior-year period, primarily a result of the Alpine High development partially offset by a decrease from the sale of the Company’s Woodford-SCOOP and STACK plays.

Year-to-Date 2019 compared to Year-to-Date 2018

Crude Oil Revenues Crude oil revenues for the first six months of 2019 totaled $2.7 billion, a $262 million decrease from the comparative 2018 period. A 9 percent decrease in average realized prices decreased 2019 oil revenues by $277 million compared to the prior-year period, while 1 percent higher average daily production increased revenues by $15 million. Crude oil accounted for 83 percent of oil and gas production revenues and 51 percent of worldwide production for the first six months of 2019, compared to 81 percent and 54 percent, respectively, for the 2018 period. Crude oil prices realized in the first six months of 2019 averaged $60.65 per barrel, compared with $66.90 per barrel in the comparative prior-year period.

Worldwide oil production increased 1.4 Mb/d to 245.8 Mb/d in the first six months of 2019 from the comparative prior-year period, primarily a result of an increase in the North Sea from the Garten field coming on-line in November 2018 and an increase in the Permian region on the success of the Midland Basin drilling program, partially offset by lower gross production in Egypt due to natural decline.

Natural Gas Revenues Gas revenues for the first six months of 2019 totaled $354 million, an $80 million decrease from the comparative 2018 period. A 28 percent decrease in average realized prices decreased 2019 natural gas revenues by $120 million compared to the prior-year period, while 13 percent higher average daily production increased revenues by $40 million. Natural gas accounted for 11 percent of its oil and gas production revenues and 35 percent of its equivalent production for the first six months of 2019, compared to 12 percent and 33 percent, respectively, for the 2018 period.

Worldwide natural gas production increased 115.8 MMcf/d to 1.0 Bcf/d in the first six months of 2019 from the comparative prior-year period, primarily a result of the Alpine High development, partially offset by lower gross production in Egypt due to natural decline.

NGL Revenues NGL revenues for the first six months of 2019 totaled $191 million, a $75 million decrease from the comparative 2018 period. A 34 percent decrease in average realized prices decreased 2019 NGL revenues by $92 million compared to the prior-year period, while 10 percent higher average daily production increased revenues by $17 million. NGLs accounted for nearly 6 percent of oil and gas production revenues and 14 percent of its equivalent production for the first six months of 2019, compared to 7 percent and 13 percent, respectively, for the 2018 period.

Worldwide production of NGLs increased 5.8 Mb/d to 63.2 Mb/d in the first six months of 2019 from the comparative prior-year period, primarily a result of the Alpine High development partially offset by the sale of the Company’s Woodford-SCOOP and STACK plays.

Altus Revenues

Midstream services revenues totaled $24 million and $12 million, respectively, for the second quarters of 2019 and 2018 and $58 million and $24 million, respectively, for the first six months of 2019 and 2018. Midstream services revenues were generated through fee-based contractual arrangements between Apache and Altus and eliminated upon consolidation. The increase during the quarter was primarily driven by higher throughput volumes from Alpine High coupled with the start-up of cryogenic plants during the second quarter of 2019 and an NGL pipeline placed in service during the third quarter of 2018.

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Operating Expenses

The table below presents a comparison of the Company’s expenses on an absolute dollar basis. The Company’s discussion may reference expenses on a boe basis, on an absolute dollar basis or both, depending on context. All operating expenses include costs attributable to a noncontrolling interest in Altus and Egypt.

	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(In millions)
Lease operating expenses	$	389	$	356	$	754	$	705
Gathering, processing, and transmission	76		82		164		168
Taxes other than income	46		49		97		104
Exploration	95		76		164		152
General and administrative	102		117		225		231
Transaction, reorganization, and separation	6		12		10		12
Depreciation, depletion, and amortization:
Oil and gas property and equipment	562		573		1,169		1,091
GPT assets	25		21		48		41
Other assets	15		14		31		29
Asset retirement obligation accretion	26		27		53		54
Impairments	240		—		240		—
Financing costs, net	173		94		270		193

Lease Operating Expenses (LOE) LOE increased $33 million and $49 million for the second quarter and first six months of 2019, respectively, on an absolute dollar basis relative to the comparable periods of 2018. The increase is primarily associated with higher production, which is reflected in only a 1 percent rise on a per-unit basis when comparing the first half of 2019 to the prior year period. Current year results were also impacted by higher fuel and labor costs in the Company’s international regions associated with unplanned maintenance and rising comparable costs in local currency.

Gathering, Processing, and Transmission (GPT) GPT expenses include transmission and processing costs paid to third-party carriers and to Altus for Apache’s upstream oil and gas production. GPT expenses also include midstream operating costs incurred by Altus. The following table presents a summary of these expenses:

	For the Quarter Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions)
Third-party processing and transmission costs	$	62		$	71		$	134		$	146
Midstream service affiliate costs	23			12			56			24
Upstream processing and transmission costs	85			83			190			170
Midstream operating expenses	14			11			30			22
Intersegment eliminations	(23		)	(12		)	(56		)	(24		)
Total GPT costs	$	76		$	82		$	164		$	168

GPT costs decreased $6 million and $4 million for the second quarter and first six months of 2018, respectively. Third-party processing and transmission costs decreased $9 million and $12 million from the second quarter and first six months of 2018, respectively, primarily driven by a decrease in pricing and the Company’s exit from the Woodford-SCOOP and STACK plays in central Oklahoma. Midstream operating expenses increased $3 million and $8 million from the second quarter and first six months of 2018, respectively, primarily a result of increased operations and production at Alpine High.

Midstream service affiliate costs increased $11 million and $32 million from the second quarter and first six months of 2018, respectively, as a result of increased Alpine High volumes. These affiliate costs are eliminated upon consolidation.

Taxes other than Income Taxes other than income decreased $3 million and $7 million from the second quarter and first six months of 2018, respectively, primarily the result of a decrease in severance taxes on lower commodity prices.

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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 second quarter and first six months of 2019 increased $19 million and $12 million, respectively, compared to the prior-year periods.

The following table presents a summary of exploration expense:

	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(In millions)
Unproved leasehold impairments	$	39	$	21	$	62	$	37
Dry hole expense	18		16		28		36
Geological and geophysical expense	18		17		38		35
Exploration overhead and other	20		22		36		44
	$	95	$	76	$	164	$	152

Unproved leasehold impairments increased $18 million and $25 million from the second quarter and first six months of 2018, respectively, primarily a result of relinquishing offshore Gulf of Mexico leasehold acreage. Dry hole expense increased $2 million and decreased $8 million in the second quarter and first six months of 2019, respectively, from the prior-year periods. The decrease between the year-to-date periods is a result of unsuccessful international exploration in the 2018 period.

General and Administrative (G&A) Expenses G&A expense for the second quarter and first six months of 2019 were $15 million and $6 million lower than the comparative 2018 periods. The decrease in G&A expense was primarily related to lower cash-based stock compensation expense resulting from a decrease in the Company’s stock price. The prior year periods also reflect a non-recurring charge to accelerate vesting on outstanding stock awards for certain retirement eligible employees.

Transaction, Reorganization, and Separation (TRS) Costs The Company recorded $6 million and $10 million of expenses during the second quarter and first six months of 2019, compared to $12 million for each of the second quarter and first six months of 2018, primarily related to company reorganization, including separation costs and other associated costs.

Depreciation, Depletion, and Amortization (DD&A) Oil and gas property DD&A expense decreased $11 million and increased $78 million compared to the second quarter and first six months of 2018, respectively, primarily a result of changes in production. The Company’s oil and gas property DD&A rate decreased $0.06 per boe and increased $0.15 per boe in the second quarter and first six months of 2019, respectively, from the prior-year periods. GPT depreciation increased $4 million and $7 million from the second quarter and first six months of 2018, respectively, associated with capital spending on Altus infrastructure. Other asset depreciation remained flat compared with the second quarter and first six months of 2018.

Impairments The Company recorded asset impairments in connection with fair value assessments in the second quarter and first six months of 2019 totaling $240 million as a result of anticipated sales proceeds for certain non-core assets in the Western Anadarko Basin in Oklahoma and Texas. The Company did not record any asset impairments in connection with fair value assessments in the second quarter and first six months of 2018. For more information regarding asset impairments, please refer to “Fair Value Measurements” and “Oil and Gas Property” 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.

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

	For the Quarter Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions)
Interest expense	$	109		$	110		$	216		$	222
Amortization of debt issuance costs	1			1			3			6
Capitalized interest	(9		)	(13		)	(17		)	(25		)
Loss on extinguishment of debt	75			—			75			—
Interest income	(3		)	(4		)	(7		)	(10		)
Financing costs, net	$	173		$	94		$	270		$	193

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Net financing costs increased $79 million and $77 million compared with the second quarter and first six months of 2018, respectively, primarily a result of a $75 million loss on extinguishment of debt incurred in the second quarter of 2019. Interest expense decreased $1 million and $6 million compared to the second quarter and first six months of 2018, respectively, as a result of the Company’s debt refinancing in the fourth 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 second quarters of 2019 and 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.

Apache’s 2019 and 2018 year-to-date effective income tax rates were primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets.

The Company continues to record a full valuation allowance against its U.S. net deferred tax assets and will continue to maintain a full valuation allowance until there is sufficient evidence to support the reversal of all or some portion of this allowance.

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 2014-2017 tax years and is also under audit in various states and foreign jurisdictions as part of its normal course of business.

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. In the first six months of 2019, Apache recognized negative reserve revisions of approximately 5 percent of its year-end 2018 estimated proved reserves as a result of lower prices. The Company does not expect additional negative revisions for the remainder of the year.

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 development program, repayment of debt maturities, payment of dividends, and any amount that may ultimately be paid in connection with commitments and contingencies.

For additional information, please see Part I, Items 1 and 2, “Business and Properties,” and Item 1A, “Risk Factors,” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.

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Sources and Uses of Cash

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

	For the Six Months Ended June 30,
	2019			2018
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	1,454		$	1,728
Proceeds from sale of oil and gas properties	247			13
Fixed-rate debt borrowings	989			—
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	611			—
	3,301			1,741
Uses of Cash and Cash Equivalents:
Capital expenditures(1)	$	1,632		$	1,856
Leasehold and property acquisitions	34			38
Altus equity method interests	438			—
Payments on fixed-rate debt	1,000			150
Dividends paid	188			191
Distributions to noncontrolling interest - Egypt	164			155
Other	10			47
	3,466			2,437
Decrease in cash and cash equivalents	$	(165	)	$	(696	)

(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.

Sources of Cash and Cash Equivalents

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.

Net cash provided by operating activities for the first six months of 2019 totaled $1.5 billion, a decrease of $274 million from the first six months of 2018. The decrease primarily reflects lower commodity prices compared to the prior-year period, partially offset by higher production volumes.

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 non-core asset divestitures totaling $247 million and $13 million in the first six months of 2019 and 2018, 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 June 19, 2019, Apache closed offerings of $1.0 billion in aggregate principal amount of senior unsecured notes, comprised of $600 million in aggregate principal amount of 4.250% notes due January 15, 2030 (2030 notes) and $400 million in aggregate principal amount of 5.350% notes due July 1, 2049 (2049 notes). The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The aggregate net proceeds of $989 million from the sale of the notes, comprised of net proceeds from the sale of the 2030 notes of $595 million and the 2049 notes of $394 million, were used to purchase certain outstanding notes in cash tender offers and for general corporate purposes.

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Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners On June 12, 2019, Altus Midstream LP, an indirectly controlled subsidiary of Apache, issued and sold Series A Cumulative Redeemable Preferred Units for an aggregate issue price of $625 million in a private offering. Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. For more information, please refer to Note 12—Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q.

Uses of Cash and Cash Equivalents

Capital Expenditures Worldwide exploration and development (E&D) cash expenditures for the first six months of 2019 totaled $1.4 billion, compared to $1.6 billion for the first six months of 2018. Expenditures were primarily in the Permian region as Apache continues development of its Alpine High play and other core holdings. Apache operated an average of 22 drilling rigs during the second quarter of 2019.

Apache’s cash expenditures in GPT facilities totaled $246 million and $284 million in the first six months of 2019 and 2018, respectively, and are nearly all comprised investments in midstream infrastructure for the Alpine High play, which were contributed to Altus Midstream LP upon closing of the Altus transaction in the fourth quarter of 2018.

Apache also completed leasehold and property acquisitions for cash totaling $34 million and $38 million during the first six months of 2019 and 2018, respectively. Acquisition investments continued to focus on adding new leasehold positions to the Company’s U.S. onshore regions.

Altus Equity Method Interests Altus made acquisitions and contributions of $438 million in the first six months of 2019 for equity interests in multiple Permian Basin long-haul pipeline entities. The Company had no equity method interest cash activity in the first six months of 2018. For more information regarding the Company’s equity method interests, please see Note 6—Equity Method Interests in the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q.

Payments on Fixed-Rate Debt On June 21, 2019, the Company closed cash tender offers for certain outstanding notes. Apache accepted for purchase $932 million aggregate principal amount of notes for approximately $1.0 billion, which included principal, the net premium to par, and an early tender premium totaling $28 million, as well as accrued and unpaid interest of $14 million. The Company recorded a net loss of $75 million on extinguishment of debt, including $7 million of unamortized debt issuance costs and discounts, in connection with the note purchases.

Dividends For the six-month periods ended June 30, 2019 and 2018, the Company paid $188 million and $191 million, respectively, in dividends on its common stock.

Egypt Noncontrolling Interest Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in Apache’s oil and gas business in Egypt. Apache made cash distributions totaling $164 million and $155 million to Sinopec in the first six months of 2019 and 2018, respectively.

Liquidity

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

	June 30, 2019		December 31, 2018
	(In millions)
Cash and cash equivalents	$	549	$	714
Total debt	8,332		8,244
Equity	8,154		8,812
Available committed borrowing capacity	3,996		3,857
Available committed borrowing capacity - Altus	650		450

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Cash and cash equivalents The Company had $549 million in cash and cash equivalents as of June 30, 2019, of which approximately $377 million was held by Altus. 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 June 30, 2019, outstanding debt, which consisted of notes, debentures and finance lease obligations, totaled $8.3 billion. Current debt as of June 30, 2019, included $150 million of 7.625% senior notes due July 1, 2019 and $25 million of finance lease obligations. On July 1, 2019, Apache’s 7.625% senior notes in original principal amount of $150 million matured and were repaid.

On June 19, 2019, Apache closed offerings of $1.0 billion in aggregate principal amount of senior unsecured notes, comprised of $600 million in aggregate principal amount of 4.250% notes due January 15, 2030 and $400 million in aggregate principal amount of 5.350% notes due July 1, 2049. The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers and for general corporate purposes.

In March 2018, the Company entered into a revolving credit facility with commitments totaling $4.0 billion. In March 2019, the term of this facility was extended by one year to March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exercise of an extension option. The Company can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of June 30, 2019. The facility is for general corporate purposes, and committed borrowing capacity fully supports Apache’s commercial paper program. As of June 30, 2019, letters of credit aggregating approximately £3.1 million and no borrowings were outstanding under this facility.

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 June 30, 2019, the Company had no commercial paper outstanding.

In November 2018, Altus Midstream LP entered into a revolving credit facility for general corporate purposes that matures in November 2023 (subject to Altus Midstream LP’s two, one-year extension options). The agreement for this facility, as amended, provides aggregate commitments from a syndicate of banks of $650 million until the consolidated net income of Altus Midstream LP and its restricted subsidiaries, as adjusted pursuant to the agreement, for the immediately preceding fiscal quarter equals or exceeds $175 million on an annualized basis (such period, the Initial Period). Following the Initial Period, the aggregate commitments equal $800 million. All aggregate commitments include a letter of credit subfacility of up to $100 million and a swingline loan subfacility of up to $100 million. After the Initial Period, Altus Midstream LP may increase commitments up to an aggregate $1.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. As of June 30, 2019, no borrowings or letters of credit were outstanding under this facility. The Altus Midstream LP credit facility is unsecured and is not guaranteed by Apache or any of Apache’s other subsidiaries.

The Company was in compliance with the terms of its credit facilities as of June 30, 2019.

Off-Balance Sheet Arrangements Apache enters into customary agreements in the oil and gas industry for drilling rig commitments, firm transportation agreements, and other obligations as described in “Contractual Obligations” in Item 7, Part II of the Form 10-K for the year ended December 31, 2018. There have been no material changes to the contractual obligations described therein.

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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 decreased 8 percent to $63.71 per barrel in the second quarter of 2019 from $69.35 per barrel in the comparable period of 2018. The Company’s average natural gas price realizations have decreased 44 percent to $1.41 per Mcf in the second quarter of 2019 from $2.50 per Mcf in the comparable period of 2018. Based on average daily production for the second quarter of 2019, 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 $8 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 June 30, 2019, the Company had open natural gas derivatives not designated as cash flow hedges in an asset position with a fair value of $5 million. A 10 percent increase or decrease in gas prices would not have a material impact on fair value. As of June 30, 2019, the Company had open oil derivatives not designated as cash flow hedges in a liability position with a fair value of $27 million. A 10 percent increase in oil prices would increase the liability by approximately $16 million, while a 10 percent decrease in prices would decrease the liability by approximately $16 million. These fair value changes assume volatility based on prevailing market parameters at June 30, 2019. 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.

Interest Rate Risk

At June 30, 2019, Apache had approximately $8.3 billion net carrying value of notes and debentures outstanding, all of which was fixed-rate debt, with a weighted average interest rate of 4.93 percent. On July 1, 2019, Apache’s 7.625% senior notes in original principal amount of $150 million matured and were repaid. Although near-term changes in interest rates may affect the fair value of Apache’s fixed-rate debt, they do not expose the Company to the risk of earnings or cash flow loss associated with that debt. Apache is also exposed to interest rate risk related to its interest-bearing cash and cash equivalents balances and amounts outstanding under its commercial paper program and credit facilities. As of June 30, 2019, the Company’s cash and cash equivalents totaled approximately $549 million, approximately 88 percent of which was invested in money market funds and short-term investments with major financial institutions. A change in the interest rate applicable to the Company’s short-term investments would have a de minimis impact on earnings and cash flows but could impact interest costs associated with future debt issuances or any future borrowings under its commercial paper program, revolving credit facilities, and money market lines of credit.

Foreign Currency Risk

The Company’s cash activities 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, substantially 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. 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 $5 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of June 30, 2019.

The Company has outstanding foreign exchange contracts with a total notional amount of £75 million that are used to reduce its exposure to fluctuating foreign exchange rates for the British pound. A 10 percent strengthening of the British pound against the U.S. dollar would result in a foreign currency net gain of $6 million, while a 10 percent weakening of the British pound against the U.S. dollar would result in a loss of $4 million.

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ITEM 4 – CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

John J. Christmann IV, the Company’s Chief Executive Officer and President, in his capacity as principal executive officer, and Stephen J. Riney, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of June 30, 2019, 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

During the quarter ended June 30, 2019, the Company completed the implementation of SAP, an enterprise resource planning (ERP) system for Apache’s Egyptian operations to align with the pre-existing interface utilized in its other regions. The Company believes the implementation of the system and related changes to internal controls will enhance internal controls over financial reporting. The Company has updated its internal controls, as applicable, to facilitate modifications to its business processes and accounting procedures and will continue to evaluate the operating effectiveness of related key controls during subsequent periods. The Company does not believe that the ERP implementation has had an adverse effect on its internal control over financial reporting.

There were no other changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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, 2018 (filed with the SEC on February 28, 2019) and Note 11—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, 2018, 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, 2018. Given the nature of its business, Altus Midstream Company may be subject to different and additional risks than those described in our annual report on Form 10-K for the fiscal year ended December 31, 2018 and this quarterly report on Form 10-Q. For a description of these risks, please refer to the annual report on Form 10-K and the quarterly reports on Form 10-Q filed by Altus Midstream Company.

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

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 from time to time either in the open market or through privately negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through June 30, 2019, had repurchased a total of 40 million shares at an average price of $79.18 per share. During the fourth quarter of 2018, the Company’s Board of Directors authorized the purchase of up to 40 million additional shares of the Company’s common stock. The Company is not obligated to acquire any specific number of shares and has not purchased any shares during 2019.

ITEM 5. OTHER INFORMATION

Effective July 29, 2019, the Board of Directors and Management Development and Compensation Committee of the Company approved certain amendments (the “Amendments”) to the Company’s Income Continuance Plan, as amended and restated July 14, 2010, effective January 1, 2009 (the “Income Continuance Plan”), Executive Termination Policy, effective February 18, 2015 (the “Executive Termination Policy”), and 2011 Omnibus Equity Compensation Plan and 2016 Omnibus Compensation Plan (together, the “Omnibus Plans”), including awards of Non-Qualified Stock Options (the “Option Awards”) and Restricted Stock Units, both time-based vesting and performance-based vesting (the “RSU Awards”, and together with the Option Agreements, the “Grant Agreements”) under the Omnibus Plans. The Amendments are intended to better align the Company’s plans and policies with current market practices.

Income Continuance Plan

The Amendments to the Income Continuance Plan, include, but are not limited to, (1) providing a 36 month benefit period for each executive officer of the Company (which includes a lump sum payment equal to 12 times monthly severance payments), (2) providing for additional severance benefits and payments that replicate the amount of Company retirement plan contributions that would have been made during the severance period, (3) adding protections to prevent an acquirer from reducing annual compensation in a manner that reduces the monthly severance payments, (4) calculating the payment made upon a Change of Control (as defined in the Amended and Restated Income Continuance Plan, effective as of July 29, 2019 (the “A&R Income Continuance Plan”) and described below) using the greater of the target bonus or the average bonus for the three years preceding such Change of Control, and (5) amending the definition of Change of Control, as set forth below.

The definition of Change of Control as set forth in the A&R Income Continuance Plan was amended by removing the “white knight” exception and adding the following events as Change of Control triggers: a merger or similar combinations, a sale of all or substantially all assets of the Company, and a change in the majority of the Company’s directors that is not approved by the Company’s incumbent Board of Directors.

The description of the A&R Income Continuance Plan is qualified in its entirety by reference to the A&R Income Continuance Plan, which is attached hereto as Exhibit 10.1.

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Executive Termination Policy

In light of the Amendments to the Income Continuance Plan, the Executive Termination Policy was amended to remove the additional year of severance for the Company’s Chief Executive Officer and to make clear that the benefits provided to the executive officers under the Executive Termination Policy, effective as of July 29, 2019 (the “A&R Executive Termination Policy”), will be available only during the period preceding a Change of Control (as defined in the A&R Income Continuance Plan) and, thereafter, during the period beginning on the date that is 24 months following a Change of Control. The A&R Income Continuance Plan will control during the period beginning on the date of a Change of Control and ending on the date that is 24 months following a Change of Control.

The description of the A&R Executive Termination Policy is qualified in its entirety by reference to the A&R Executive Termination Policy, which is attached hereto as Exhibit 10.2.

Omnibus Compensation Plan and Grant Agreements

The Amendments to the Omnibus Plans (the “Plan Amendments”) include adding a second prong to the definition of involuntary termination which mirrors the third prong of the definition of involuntary termination in the A&R Income Continuance Plan and conforming the definition of Change of Control to mirror the definition of Change of Control in the A&R Income Continuance Plan. The Grant Agreements also include similar changes.

The descriptions of the Plan Amendments and the Amendments to the Grant Agreements are qualified in their entirety by reference to the A&R Income Continuance Plan.

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	–	Form of 4.250% Notes due 2030, dated June 5, 2019 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed June 10, 2019, SEC File No. 001-4300).
4.2	–	Form of 5.350% Notes due 2049, dated June 5, 2019 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K filed June 10, 2019, SEC File No. 001-4300).
*10.1	–	Apache Corporation Income Continuance Plan, as amended and restated effective as of July 29, 2019.
*10.2	–	Apache Corporation Executive Termination Policy, as amended and restated effective as of July 29, 2019.
*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.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

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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:	August 1, 2019	/s/ STEPHEN J. RINEY
		Stephen J. Riney
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)
Dated:	August 1, 2019	/s/ REBECCA A. HOYT
		Rebecca A. Hoyt
		Senior Vice President, Chief Accounting Officer, and Controller
		(Principal Accounting Officer)

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EX-10.1

Exhibit 10.1

APACHE CORPORATION

INCOME CONTINUANCE PLAN

(As Amended and Restated Effective as of July 29, 2019)

The Company desires to provide income continuance benefits to the following groups of its employees in case there is a change of control affecting the Company, for the reasons indicated:

(i)Those 40 years of age and older, a protected class under federal and state age discrimination laws, because it has been determined that they typically have more difficulty in finding new employment than younger persons;

(ii)Those who have been continuously employed by the Company for 10 years or more, because they have demonstrated their personal commitment to the success of the Company;

(iii)Those whose special skills, experience or potential justify their inclusion in order to acquire or retain their services; and

(iv)Those who are officers of the Company.

The Company adopted this Plan on January 10, 1986 in order to protect the income and other employee benefits of the Company’s Employees and in order to induce the Employees to remain in the employ of the Company for the ultimate benefit of the Company and its shareholders.

The Plan is intended to create a binding legal relationship between the Company and each Employee, and a copy of the Plan together with applicable conditions will be given to each Employee. It is also intended that this Plan comply with the requirements of Code §409A, and it shall be interpreted in this light.

Section 1.Definitions.

(a)“Benefit Period” shall mean (i), for each officer of the Company, 24 months following such officer’s Termination Date and (ii), for all other eligible Employees, a period of time following such Employee’s Termination Date equal to half the number of months of his or her continuous service with the Company on his or her Termination Date, up to a maximum Benefit Period of 24 months for each Employee who is not an officer. If an Employee would receive less than 24 months under the preceding sentence, the Benefit Period may be extended for such Employee to a maximum of 24 months, if the Company concludes the extension is reasonably required in order to induce an individual to accept employment or in order to retain an existing employee.

(b)“Change of Control” shall mean (i) any individual, entity, or group (including within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) (a “Person”) becomes the beneficial owner (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (A) the then-outstanding shares of common stock of the Company (the “Outstanding Company Common Stock”) or (B) the combined voting power of the then-outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”); provided, however, that, for purposes of this Section 1(b), the following acquisitions shall not constitute a Change of Control: (I) any acquisition of Outstanding Company Common Stock or Outstanding Company Voting Securities directly from

the Company that is approved by the Incumbent Board (defined below), (II) any acquisition of Outstanding Company Common Stock or Outstanding Company Voting Securities by the Company, (III) any acquisition of Outstanding Company Common Stock or Outstanding Company Voting Securities by any employee benefit plan (or related trust) sponsored or maintained by the Company or any affiliate thereof, or (IV) any acquisition of Outstanding Company Common Stock or Outstanding Company Voting Securities in a transaction that is part of a Business Combination that complies with Sections 1(b)(iii)(A), 1(b)(iii)(B), and 1(b)(iii)(C) below; (ii) individuals who, as of the date hereof, constitute the board of directors (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual was a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the board of directors; (iii) consummation of a reorganization, merger, statutory share exchange, or consolidation or similar transaction involving the Company, a sale or other disposition of all or substantially all of the assets of the Company (including by sale, reorganization, merger, statutory share exchange, or consolidation or similar transaction involving the shares of all or substantially all of the Company’s subsidiaries), or the acquisition of assets or securities of another entity by the Company or any of its subsidiaries (each, a “Business Combination”), in each case unless, following such Business Combination, (A) all or substantially all of the individuals and entities that were the beneficial owners of the Outstanding Company Common Stock and the Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of the then-outstanding shares of common stock (or, for a non-corporate entity, equivalent securities) and the combined voting power of the then-outstanding voting securities entitled to vote generally in the election of directors (or, for a non-corporate entity, equivalent governing body), as the case may be, of the entity resulting from such Business Combination (including, without limitation, an entity that, as a result of such transaction, owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership immediately prior to such Business Combination, and (B) no Person (excluding any entity resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such entity resulting from such Business Combination) beneficially owns, directly or indirectly, 20% or more of, respectively, the then-outstanding shares of common stock (or, for a non-corporate entity, equivalent securities) of the entity resulting from such Business Combination or the combined voting power of the then-outstanding voting securities of such entity, except to the extent that such ownership existed prior to the Business Combination, and (C) at least a majority of the members of the board of directors (or, for a non-corporate entity, equivalent governing body) of the entity resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement and at the time of the action of the board of directors providing for such Business Combination; or (iv) approval by the stockholders of the Company of a complete liquidation or dissolution of the Company.

Notwithstanding the foregoing, (x) in the case of any item of compensation to which the foregoing definition would otherwise apply with the effect that the tax under Code §409A would apply or be imposed on such compensation, but where such tax would not apply or be imposed if the meaning of the term “Change of Control” met the requirements of Code §409A(a)(2)(A)(v), then the term “Change of Control” herein shall mean, but only with respect to the income so affected, a transaction,

- 2 -

circumstance, or event that constitutes a “Change of Control” (as defined above) and that also constitutes a “change in control event” within the meaning of Treasury Regulation §1.409A-3(i)(5), and (y) for purposes of the Apache Corporation Deferred Delivery Plan and any other Company or Company affiliate plan, arrangement, or agreement that incorporates the definition of “Change of Control” herein (except this Plan and the Company’s 2011 Omnibus Equity Compensation Plan and 2016 Omnibus Compensation Plan and the awards under any of them), if the “Change of Control” as set forth herein as of the 2019 Restatement Date would result in any item of compensation being subject to the tax under Code §409A but where such tax would not apply or be imposed if the meaning of the term “Change of Control” as in effect immediately prior to 2019 Restatement Date applied, then the definition of “Change of Control” as in effect immediately prior to the 2019 Restatement Date shall continue to apply to the Apache Corporation Deferred Delivery Plan and any other Company or Company affiliate plan, arrangement, or agreement that incorporates the definition of “Change of Control” herein (except this Plan and the Company’s 2011 Omnibus Equity Compensation Plan and 2016 Omnibus Compensation Plan and the awards thereunder). For the avoidance of doubt, subclause (y) of the immediately preceding sentence does not apply to this Plan or the Company’s 2011 Omnibus Equity Compensation Plan or 2016 Omnibus Compensation Plan or any awards under any of them.

(c)“COBRA Premium” shall mean 100% of the applicable premium, as defined in Code §4980B(f)(4).

(d)“Code” shall mean the Internal Revenue Code of 1986, as amended, or any successor. References to a particular section of the Code shall also refer to any successor section.

(e)“Committee” shall mean the administrative committee provided for in Section 4.

(f)“Company” shall mean Apache Corporation, a Delaware corporation, and any successor thereto.

(g)“Effective Date” shall mean the date on which a Change of Control takes place.

(h)“Employee” shall mean each regular exempt or non-exempt employee of the Company on the Effective Date or the Termination Date who:

(i)is 40 years of age or older; or

(ii)has been continuously employed by the Company for 10 years or more; or

(iii)has been designated by the board of directors as having special skills, experience or potential which warrant extension of the Plan to them; or

(iv)is an officer of the Company.

(i)“ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended, or any successor. References to a particular section of the ERISA shall also refer to any successor section.

(j)“Exchange Act” shall mean the Securities Exchange Act of 1934, as amended, or any successor. References to a particular section of the Exchange Act shall also refer to any successor section.

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(k)“Executive Officer” shall mean an officer of the Company who has filed a Form 3, 4, or 5 as required by Section 16 of the Exchange Act within the 12 months preceding a Change of Control.

(l)“Incumbent Board” shall have the meaning given such term in the definition of Change of Control.

(m)“Lump Sum Payment” shall mean an amount equal to 12 times the applicable Executive Officer’s Monthly Compensation.

(n)“Monthly Compensation” shall mean one-twelfth of the total of all cash compensation, including wages, salary, and any other incentive compensation, bonuses, commissions and non-salary and non-wage cash compensation, that was paid as consideration for the Employee’s services during the year immediately preceding the Termination Date, or that would have been so paid at the Employee’s usual rate of cash compensation if the Employee had worked a full year; provided, that for purposes of determining the amount of the Monthly Compensation with respect to bonuses, such bonuses shall be valued at the greater of (i) the target bonus for the year in which the Termination Date occurs or (ii) the average bonus paid to the Employee for each of the three years immediately preceding the year in which the Termination Date occurs; and provided further that cash compensation shall not include or be deemed or interpreted to include any cash settled stock awards or cash valued by reference to the publicly traded stock price of the Company or any of its subsidiaries, including, for the avoidance of doubt, cash paid under the Company’s long-term incentive plan. Notwithstanding the foregoing, to the extent that any element of compensation used in calculating Monthly Compensation is decreased with respect to an Employee after a Change of Control or within six months prior to a Change of Control, the amount of such element as in effect immediately prior to such decrease with respect to such Employee shall be used in such calculation.

(o)“Participant” shall mean an Employee who has become entitled to the benefits under the Plan pursuant to Section 2.

(p)“Plan” shall mean the Income Continuance Plan of the Company, as amended.

(q)“Pro Rata Bonus” shall mean an amount equal to the annual bonus the applicable Employee would have received for the year in which the Separation from Service occurred, calculated as if he or she had not experienced such Separation from Service, with such amount prorated for the portion of the year in which such Separation from Service occurred.

(r)“Retirement Plan Contribution Amount” means the amount of employer contributions that would have been made to the Company’s (or its successor’s) qualified retirement plans on the Employee’s behalf during the Benefit Period if the Employee had not experienced a Separation from Service, calculated as if the Employee’s compensation for such plan’s purposes and employee contributions thereto, if applicable, remained at the level as in effect immediately prior to the Termination Date.

(s)“Separation from Service” and “Separate from Service” shall mean a separation from service within the meaning of Code §409A(a)(2)(A)(i). A Participant who has a Separation from Service “Separates from Service.” For purposes of this Plan, a Separation from Service occurs when the Company and the Participant both expect the Participant’s level of services to permanently drop by more than 50% from his or her average level of services during the preceding 36 months (or, if less, the duration of his or her employment with the Company).

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(t)“Specified Employee” shall have the same meaning as in Code §409A(a)(2)(B)(i) and is determined using the default rules contained in the regulations and other guidance of general applicability issued pursuant to Code §409A.

(u)“Termination Date” shall mean:

(i)If an Employee’s Separation from Service is involuntary, his or her Termination Date is the date on which an authorized written or oral statement is conveyed to the Employee indicating that the Employee’s employment is terminated; or

(ii)If an Employee’s Separation from Service is voluntary, his or her Termination Date is the date on which the Employee delivers a written notice to the Company or its successor advising of termination of employment.

(v)“2019 Restatement Date” shall mean the effective date of this amendment and restatement of the Plan.

Section 2.Eligibility for Benefits.

The benefits described in this Plan shall come into effect only if the Employee is “terminated” on or within 24 months after the Change of Control. For this purpose, an Employee is considered “terminated” in the following circumstances.

(a)Involuntary Termination. Each of the following three conditions is satisfied.

(i)The Company or its successor terminates an Employee for any reason on or after the Change of Control.

(ii)The termination constitutes a Separation from Service.

(iii)The termination does not result from an act of the Employee that (A) constitutes common-law fraud, a felony, or a gross malfeasance of duty, and (B) is materially detrimental to the best interests of the Company or its successor.

(b)Voluntary Termination with Cause. Either the facts and circumstances indicate that each of the following five conditions is satisfied or that the Participant’s termination is properly characterized as involuntary pursuant Treasury Regulation §1.409A-1(n)(2), other IRS guidance of general applicability, or an IRS private letter ruling applicable to the Participant.

(i)The Employee Separates from Service of his or her own volition.

(ii)The Employee’s Separation from Service occurs during the 24-month period beginning on the date of the Change of Control.

(iii)One or more of the following conditions occurs without the Employee’s consent on or after the Change of Control:

(A)There is a material diminution in the Employee’s base compensation, compared to his or her rate of base compensation on the date of the Change of Control.

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(B)There is a material diminution in the Employee’s authority, duties, or responsibilities.

(C)There is a material diminution in the authority, duties, or responsibilities of the Employee’s supervisor, such as a requirement that the Employee (or his or her supervisor) report to a corporate officer or employee instead of reporting directly to the board of directors.

(D)There is a material diminution in the budget over which the Employee retains authority.

(E)There is a material change in the geographic location at which the Employee must perform his or her services, including, for example, the assignment of the Employee to a regular workplace that is more than 50 miles from his or her regular workplace on the date of the Change of Control.

(iv)The Employee must notify the Company of the existence of one or more adverse conditions specified in paragraph (iii) within 90 days of the initial existence of the adverse condition. The notice must be provided in writing to the Company or its successor, attention: Vice President, Human Resources. The notice may be provided by personal delivery or it may be sent by email, inter-office mail, regular mail (whether or not certified), fax, or any similar method. The Company’s Vice President, Human Resources or his or her delegate shall acknowledge receipt of the notice within 5 business days; the acknowledgement shall be sent to the Employee by certified mail.

(v)The Company does not remedy the adverse condition within 30 days of being notified of the adverse condition.

Section 3.Benefits.

(a)Monthly Compensation; Lump Sum Payment; Pro Rata Bonus; Retirement Plan Contribution Amount.

(i)Timing of Payments, General. Except as provided for Specified Employees in paragraph (ii) or as reduced in paragraph (iii), each month the Participant will be paid his or her Monthly Compensation. The first payment of the Monthly Compensation will be made on the first 15th of the month that occurs after the Participant’s Separation from Service or as soon thereafter as is administratively practicable, and subsequent payments thereof will be made on the 15th of each succeeding month. The number of payments of Monthly Compensation the Participant receives is equal to the number of months in his or her Benefit Period. In addition, except as provided for Specified Employees in paragraph (ii) or as reduced in paragraph (iii), the Participant will also be paid his or her Pro Rata Bonus, Retirement Plan Contribution Amount, and, if and only if the Participant is an Executive Officer, the Lump Sum Payment. The Pro Rata Bonus, the Retirement Plan Contribution Amount, and, if applicable, the Lump Sum Payment shall be paid in a single lump sum in cash within 60 days after his or her Separation from Service.

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(ii)Exceptions for Specified Employees. This paragraph applies to the payments to a Participant who is a Specified Employee. The Specified Employee shall be paid as described in subsection (a)(i) with the following exceptions for his or her first six payments of Monthly Compensation and his or her Pro Rata Bonus, Retirement Plan Contribution Amount, and, if applicable, the Lump Sum Payment.

(A)No Deferral of Compensation. The payments under this Plan generally cease to be subject to a substantial risk of forfeiture when the Participant Separates from Service. If the payments cease to be subject to a substantial risk of forfeiture in one year and the Participant Separates from Service on or before October 15 of that year, the first six payments of Monthly Compensation and the Pro Rata Bonus, the Retirement Plan Contribution Amount, and, if applicable, the Lump Sum Payment will be made at the times specified in subsection (a)(i). If the payments cease to be subject to a substantial risk of forfeiture in one year and the Participant Separates from Service after October 15 of that year, regular payments will be made at the times specified in subsection (a)(i) through February 15 in the year after the Separation from Service and the remainder of the first six payments of Monthly Compensation (and, if not already paid, the Pro Rata Bonus, the Retirement Plan Contribution Amount, and, if applicable, the Lump Sum Payment) will be paid on March 15 (or if March 15 is not a business day, the payment shall be made on the immediately preceding business day).

For example, if the Participant terminates on December 31, he or she will receive the regular payments of Monthly Compensation on January 15 and February 15 (along with the Pro Rata Bonus, the Retirement Plan Contribution Amount, and, if applicable, the Lump Sum Payment, within 60 days after December 31) and will receive four months’ worth of Monthly Compensation payments on March 15. His or her next payment of Monthly Compensation will be on July 15.

For purposes of Treasury Regulation §§ 1.409A-1(b)(4)(i)(F) and 1.409A-2(b)(2), each payment from this Plan is considered a separate payment.

(B)Limited Payments during First Six Months. This subparagraph applies only if subparagraph (A) does not apply to the Specified Employee, such as when his or her benefits cease to be subject to a substantial risk of forfeiture in a year earlier than the year of his or her Separation from Service. Each month, the sum of (1) the monthly payment under this paragraph (ii) (which shall include the amount of the Pro Rata Bonus, the Retirement Plan Contribution Amount, and, if applicable, the Lump Sum Payment for the month in which each such amount is paid), (2) the amount of any gross-up under paragraphs (b)(iii) or (b)(iv), and (3) any payment from any other separation pay plan (other than those described in Treasury Regulation §1.409A-1(b)(9)(ii), (iv), or (v)) is limited to the lesser of one-third of the Participant’s annual compensation for the year preceding the year in which he or she Separated from Service or one-third of the annual limit in effect under Code §401(a)(17) for the calendar year containing the Separation from Service. For this purpose, “annual compensation” means the Participant’s annualized compensation based upon the annual rate of pay for services provided to the Company for the year preceding the year in which the Participant Separated from Service, adjusted for any increase during that year that was expected to continue indefinitely had the Participant not Separated from Service. If any monthly payments are limited by the foregoing, the reductions in each payment shall be aggregated and that exact sum shall be paid to the Specified Employee six months after his or her Separation from Service.

(iii)Reduction in Payments. The payments described in this subsection shall be reduced by the amount of any severance pay required by foreign law.

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(b)Continued Health Coverage.

(i)General. The Participant shall continue to be covered by the Company’s medical plan, dental plan, vision plan, and employee assistance program after Separating from Service for the number of months in his or her Benefit Period. The Participant and his or her family members may also be able to continue their coverage even after the Benefit Period ends, pursuant to the continuation coverage rules under those plans. The benefits offered during the Benefit Period shall contain at least one alternative that is at least as valuable as the benefits offered immediately before the Change of Control. In addition, the Participant shall have the same coverage options as are available to current employees of the Company. The Participant may change his or her coverage from one alternative to another, and may add or drop coverage for his or her dependents or spouse, subject to the same rules as a current employee of the Company.

(ii)Premiums. The Company may not charge a Participant for coverage under the employee assistance program. The Company may charge a premium for coverage under the medical, dental, and vision plans, but the maximum premium for the alternative(s) that are at least as valuable as the benefits offered immediately before the Change of Control shall not exceed what was charged under the schedule of premiums that was in effect immediately before the Change of Control. For example, if the premium was $64 per month for employee-only coverage and $200 per month for family coverage on the date of the Change of Control, and a male Participant marries a woman with children two months into their Benefit Period, their premium will be $200 per month for the remainder of their Benefit Period for coverage that is at least as valuable as the family coverage benefits immediately before the Change of Control.

(iii)Cafeteria Plan. Except as provided in paragraph (iv), the Company shall ensure that it maintains a cafeteria plan that allows each Participant in this Plan to reduce their pay described in subsection (a) to pay their share of the premiums for medical, dental, and vision coverage generally on a pre-tax basis. If the cafeteria plan fails one of its nondiscrimination tests, a highly-paid Participant’s supposedly pre-tax deductions from his or her pay will generally be included in his or her taxable income. In this case, the Company shall pay the Participant a gross-up so that the highly-paid Participant’s after-tax income equals what it would have if his or her deduction from his or her pay were made on a pre-tax basis.

(iv)After-Tax Premiums. Each year, beginning with the year containing the Change of Control, the Committee shall determine whether each self-funded health plan is discriminatory. If a self-funded plan is discriminatory, each Participant who was a highly-compensated individual (within the meaning of Code §105(h)(5)) shall pay the COBRA Premium for coverage with after-tax deductions from his or her pay described in subsection (a), and for purposes of Code §105 a separate self-funded health plan shall be considered to have been established for such highly-compensated individuals for that year. If sufficient deductions were not properly withheld, the Participant is responsible for reimbursing the Company for the underwithholding. The Company shall pay a gross-up to each Participant who was a highly-compensated individual (within the meaning of Code §105(h)(5)) so that his or her after-tax income equals what it would have if he or she only had to pay the amount described in paragraph (ii) for coverage and this amount was withheld on a pre-tax basis from his or her pay. In addition, the Committee may project during a year whether a self-funded plan will be discriminatory, and pay a gross-up to each Participant who is expected to be a highly-compensated individual (within the meaning of Code §105(h)(5)) for that year so that his or her after-tax income equals what it would have if he or she only had to pay the amount described in paragraph (ii) for coverage and this amount were withheld on a pre-tax basis from his or her pay. To the extent that any insured plan

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is determined to be discriminatory pursuant to the Code or similar law (whether as a result of new guidance promulgated pursuant to the Patient Protection and Affordable Care Act of 2010, as amended, or otherwise), the foregoing in this paragraph (iv) shall apply with respect to such insured plan to the extent reasonably practicable.

(v)Gross-Up. If a Participant receives a gross-up under paragraph (iii) or (iv), the gross-up shall be paid as quickly as possible and no later than the end of the calendar year following the calendar year in which the Participant’s right to the gross-up arose. However, if the gross-up is due to a tax audit or litigation addressing the existence or amount of a tax liability, the gross-up shall be paid as soon as administratively convenient after the litigation or audit is completed, and no later than the end of the calendar year following the calendar year in which the audit is completed or there is a final and non-appealable settlement or other resolution of the litigation.

(c)Continued Life Insurance. The Company shall continue to provide term- life insurance for each Participant until (i) the Participant stops paying the premiums or (ii) the Benefit Period expires. The amount of the available coverage shall be at least as much as was provided to the Participant on the date of the Change of Control. The Participant-paid portion of the premiums shall be no larger than the premiums charged to current employees of the Company who perform the same types of tasks, at the same level, as the Participant performed immediately before the Change of Control.

(d)Legal Expenses.

(i)Expenses That Are Not Subject to Code §409A. The Plan shall reimburse the Participant (or, if the Participant has died, his or her beneficiary, spouse, and dependents – collectively, the “claimant” in this subsection) for all reasonable expenses, including attorneys’ fees, that the claimant incurs before the end of the calendar year containing the second anniversary of the Participant’s Separation from Service and that are incurred in any dispute, claim, mediation, arbitration, or preceding and that are incurred to seek to enforce the claimant’s rights against the Company or its successor under this Plan, regardless of whether the action is successful and regardless of who commenced such dispute, claim, mediation, arbitration, or proceeding. The Plan shall reimburse the claimant as soon as practicable following claimant’s submission of third-party invoices for such expenses and no later than the end of the calendar year containing the third anniversary of the Participant’s Separation from Service.

(ii)Expenses That Are Subject to Code §409A. The Plan shall reimburse the claimant for all reasonable expenses, including attorneys’ fees, that he or she incurs after the calendar year containing the second anniversary of the Participant’s Separation from Service and before the third anniversary of the Participant’s death and that are incurred in enforcing the claimant’s rights against the Company or its successor under this Plan, regardless of the whether the action is successful. All reimbursements and in-kind benefits provided under this Plan that are subject to Code §409A shall be made in accordance with the requirements of Code §409A, including, without limitation, where applicable, the requirement that (A) the amount of expenses eligible for reimbursement, or in-kind benefits provided, during a calendar year may not affect the expenses eligible for reimbursement, or in-kind benefits to be provided, in any other calendar year; (B) the reimbursement of eligible fees and expenses shall be made no later than the last day of the calendar year following the year in which the applicable fees and expenses were incurred; and (C) the right to reimbursement or in-kind benefits is not subject to liquidation or exchange for another benefit.

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(e)Noncompliance with Code §409A. To the extent that the Company takes any action that causes a violation of Code §409A or fails to take reasonable actions required to comply with Code §409A, the Company shall pay an additional amount (the “gross-up”) to the individual(s) who are subject to the penalty tax under Code §409A(a)(1) that is sufficient to put him or her in the same after-tax position he or she would have been in had there been no violation of Code §409A. The Company shall not pay a gross-up if the cause of the violation of Code §409A is because the recipient failed to take reasonable actions (such as failing to timely provide the information required for tax withholding or failing to timely provide other information reasonably requested by the Committee - with the result that the delay in payment violates Code §409A). Any gross-up will be made as soon as administratively convenient after the Committee determines the gross-up is owed, and no later than the end of the calendar year immediately following the calendar year in which the additional taxes are remitted. However, if the gross-up is due to a tax audit or litigation addressing the existence or amount of a tax liability, the gross-up will be paid as soon as administratively convenient after the litigation or audit is completed, and no later than the end of the calendar year following the calendar year in which the audit is completed or there is a final and non­appealable settlement or other resolution of the litigation.

(f)Death of Participant.

(i)Payments to Beneficiary. If the Participant dies during the Benefit Period, his or her Beneficiary shall be paid all remaining payments under subsection (a), (d), and (e), on the same schedule as they would have been paid to the Participant had he or she lived. See subsection (g) for possible delays. The amount paid to the Beneficiary will be reduced by the cost of health coverage of the surviving spouse and dependents. If the Beneficiary dies before receiving all such payments, any remaining payments shall be paid to the Beneficiary’s estate.

(ii)Health Coverage. If the Participant dies during the Benefit Period, his or her spouse and dependents shall continue to receive the benefits identified in subsection (b), at the price specified in subsection (b), for the remaining duration of the Benefit Period. A surviving spouse or dependent who is not covered by such plans when the Participant dies may elect to be covered by such plans whenever the Participant could have elected coverage for them had he or she not died. Any gross-up under subsection (b)(iii) or (b)(iv) shall be made to the surviving spouse, if any, and otherwise to the dependents. (See Section 9 for payments to a minor.)

(iii)Beneficiary Designation. Each Participant shall designate one or more persons, trusts, or other entities as his or her Beneficiary to receive any amounts identified in paragraph (i). In the absence of an effective beneficiary designation as to part or all of a Participant’s interest in the Plan, such amount will be distributed to the Participant’s surviving spouse, if any, otherwise to the personal representative of the Participant’s estate.

(iv)Special Rules for Spouses. A beneficiary designation may be changed by the Participant at any time and without the consent of any previously designated Beneficiary. However, if the Participant is married, his or her spouse will be his or her Beneficiary unless such spouse has consented to the designation of a different Beneficiary. To be effective, the spouse’s consent must be in writing, witnessed by a notary public, and filed with the Committee. If the Participant has designated his or her spouse as a primary or contingent Beneficiary, and the Participant and spouse later divorce (or their marriage is annulled), then the former spouse will be treated as having pre­ deceased the Participant for purposes of interpreting a beneficiary designation that was completed prior to the divorce or annulment; this provision will apply only if the Committee is informed of the divorce or annulment before payment to the former spouse is authorized.

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(v)Disclaiming. Any individual or legal entity who is a Beneficiary may disclaim all or any portion of his or her interest in the Plan, provided that the disclaimer satisfies the requirements of Code §2518(b) and applicable state law. The legal guardian of a minor or legally incompetent person may disclaim for such person. The personal representative (or the individual or legal entity acting in the capacity of the personal representative according to applicable state law) may disclaim on behalf of a Beneficiary who has died. The amount disclaimed will be distributed as if the disclaimant had predeceased the individual whose death caused the disclaimant to become a Beneficiary.

(g)Administrative Delays in Payments. The Committee may delay any payment from this Plan for as short a period as is administratively necessary. For example, a delay may be imposed upon all payments from the Plan when there is a change of recordkeeper or trustee, and a delay may be imposed on payments to any recipient until they have provided the information needed for tax withholding and tax reporting, as well as any other information reasonably requested by the Committee. However, no delay may last long enough for the Plan to be considered a “pension plan” within the meaning of ERISA §3(2).

(h)Technical Note. If a Participant or Beneficiary has a taxable year different from the calendar year, the deadlines under Article II shall be adjusted to the latest date, as specified in IRS guidance of general applicability, that would permit compliance with Code §409A.

(i)Cash Payment and Withholding. All payments from the Plan will be made in cash. The Plan will withhold any taxes or other amounts that it is required to withhold pursuant to any applicable law. The Plan will also withhold any amounts (such as medical premiums) that the recipient authorizes the Plan or the Company to withhold.

(j)Parachute Payments. Notwithstanding anything to the contrary, in the event that any payment or benefit received or to be received by a Participant (including, without limitation, any payment or benefit received in connection with a Change of Control or the termination of Participant’s employment after a Change of Control, whether pursuant to the terms of this Plan or any other plan, program, arrangement, or agreement) (all such payments and benefits received or to be received, together, the “Total Receipts”) would be subject (in whole or part), to any excise tax imposed under Code §4999 (the “Excise Tax”), then, after taking into account any reduction in the Total Receipts provided by reason of Code §280G in such other plan, program, arrangement, or agreement, the Company will reduce the payments and benefits comprising Total Receipts to the extent necessary, but only to the extent necessary, so that no portion of the Total Receipts is subject to the Excise Tax (but in no event to less than zero); provided, however, that the payments and benefits comprising Total Receipts will be reduced only if (a) the net amount of such Total Receipts, as so reduced (and after subtracting the net amount of federal, state, municipal, and local income and employment taxes on such reduced Total Receipts and after taking into account any phase-out of itemized deductions and personal exemptions attributable to such reduced Total Receipts), is greater than or equal to (b) the net amount of such Total Receipts without such reduction (but after subtracting the net amount of federal, state, municipal, and local income and employment taxes on such Total Receipts and the amount of Excise Tax to which Executive would be subject in respect of such unreduced Total Receipts and after taking into account any phase-out of itemized deductions and personal exemptions attributable to such unreduced Total Receipts). In the case of a reduction in the payments and benefits comprising Total Receipts, the payments and benefits comprising Total Receipts will be reduced in the following order: (1) payments that are payable in cash that are valued at full value under Treasury Regulation §1.280G-1, Q&A24(a) will be reduced (if necessary, to zero), with amounts that are payable last reduced first; (2) payments

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and benefits due in respect of any equity valued at full value under Treasury Regulation Section 1.280G-1, Q&A24(a), with the highest values reduced first (as such values are determined under Treasury Regulation §1.280G-1, Q&A 24), will next be reduced; (3) payments that are payable in cash that are valued at less than full value under Treasury Regulation §1.280G-1, Q&A 24, with amounts that are payable last reduced first, will next be reduced; (4) payments and benefits due in respect of any equity valued at less than full value under Treasury Regulation §1.280G-1, Q&A 24, with the highest values reduced first (as such values are determined under Treasury Regulation §1.280G-1, Q&A 24), will next be reduced; and (5) all other non-cash benefits not otherwise described in clause (2) or (4) will be next reduced pro-rata. Any reductions made pursuant to each of clauses (1) through (4) above will be made in the following manner: first, a pro-rata reduction of cash payment and payments and benefits due in respect of any equity not subject to Code §409A, and second, a pro-rata reduction of cash payments and payments and benefits due in respect of any equity subject to Code §409A as deferred compensation.

Section 4.Administration.

(a)Composition of the Committee.

(i)Current. As of the 2019 Restatement Date, the Committee is comprised of the members of the Retirement Plan Advisory Committee.

(ii)Before a Change of Control. Before a Change of Control, the board of directors of the Company shall appoint an administrative Committee consisting of no fewer than three individuals who may be, but need not be, Participants, officers, directors, or employees of the Company. The Company’s board of directors may remove Committee members at will. In the absence of any Committee members, the Company shall become the sole Committee member.

(iii)After a Change of Control. This paragraph applies on and after the date of a Change of Control. The only individuals who are able to serve on the Committee after the date of the Change of Control are those who are not then employed by the Company, its successor, or any related legal entities. No Committee members may be added on or after the day of the Change of Control, except that, if the Committee is comprised solely of individuals, (A) the Committee may appoint a legal entity as a Committee member, who may generally resign by giving 60 days’ notice to the other Committee members, and (B) if the number of Committee members drops below three, the remaining member(s) may not resign until having appointed a legal entity or another individual as a Committee member. If all Committee members leave the Committee (if, for example, all Committee members die before the last one appoints a new Committee member or if the sole Committee member is a legal entity that goes out of business), the Committee shall automatically consist of the three Participants with the largest monthly payments from the Plan who are not then employed by the Company, its successor, or any related legal entities.

(iv)Plan Administrator. The Committee is the Plan’s “administrator” within the meaning of ERISA §3(16)(A). The sole named fiduciaries of the Plan are the Committee and the trustees of any trusts from which Plan benefits may be paid.

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(b)Committee Duties. The Committee shall administer the Plan and shall have all discretion and powers necessary for that purpose, including, but not by way of limitation, full discretion and power to interpret the Plan, to determine the eligibility, status, and rights of all persons under the Plan and, in general, to decide any dispute and all questions arising in connection with the Plan. The Committee shall direct the Company, the trustee of any rabbi trust established to pay Plan benefits, or both, as the case may be, concerning payments in accordance with the provisions of the Plan. The Committee shall maintain all Plan records except records of any trust. The Committee shall publish, file, or disclose -- or cause to be published, filed, or disclosed -- all reports and disclosures required by federal or state laws. The Committee may authorize one or more of its members or agents to sign instructions, notices, and determinations on its behalf.

(c)Organization of Committee. The Committee shall adopt such rules as it deems desirable for the conduct of its affairs and for the administration of the Plan. It may appoint agents (who need not be members of the Committee) to whom it may delegate such powers as it deems appropriate, except that any dispute shall be determined by the Committee. The Committee may make its determinations with or without meetings. It may authorize one or more of its members or agents to sign instructions, notices, and determinations on its behalf. If a Committee decision or action affects a relatively small percentage of Plan Participants including a Committee member, such Committee member will not participate in the Committee decision or action. The action of a majority of the disinterested Committee members constitutes the action of the Committee.

(d)Indemnification. The Committee and all of the agents and representatives of the Committee shall be indemnified and saved harmless by the Company against any claims, and the expenses of defending against such claims, resulting from any action or conduct relating to the administration of the Plan, except claims judicially determined to be attributable to gross negligence or willful misconduct.

(e)Agent for Process. The Company’s Vice President, General Counsel, and Secretary shall be the agents of the Plan for service of all process.

(f)Determination of Committee Final. The decisions made by the Committee are final and conclusive on all persons.

(g)No Bonding. Neither the Committee nor any committee member is required to give any bond or other security in any jurisdiction in connection with the administration of the Plan, unless the Company determines otherwise before a Change of Control or any applicable federal or state law so requires.

Section 5.Terms of Plan; Termination.

This Plan is terminable at any time by the majority vote of the Incumbent Board upon six months’ prior written notice delivered to all Employees, provided that the Company or its successor shall be prohibited from terminating the plan, or delivering notice of termination of the Plan, after or within six months prior to a Change of Control.

Section 6.Amendment.

This Plan can be amended at any time by the Company on the following conditions:

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(a)No amendment shall be adopted by the Company or its successor subsequent to the Effective Date, except to alleviate any material negative tax consequences to one or more actual or expected recipients of Plan benefits.

(b)Immediately after adopting any amendment, the Company shall provide to Employees a written statement of this Plan, as amended, and no amendments shall be effective as to any Employee, until the Employee has received the statement. An Employee will be deemed to have received the written statement of the Plan if it is delivered in person or after 48 hours of dispatch by mail or other suitable means of delivery to the last known address of the Employee.

Section 7.Other Plans and Contracts.

It is the intention of the Company that the benefits provided for in this Plan are in addition to, and not in lieu of any other rights, privileges or benefits to which the Employee may now or hereafter be entitled under any contract, arrangement, plan or other policy applicable to any Employee with the Company or any other employer, except the benefits suspended under the Company’s Termination Policy during the Benefit Period under this Plan.

Section 8.Claims Procedure.

(a)General. Each claim for benefits will be processed in accordance with the procedures established by the Committee. The procedures will comply with the guidelines specified in this section. Claims for reimbursement under the medical, dental, and vision plans, the employee assistance program, and claims for life insurance shall be determined under the procedures specified in those plans; however, this Plan’s procedures shall determine eligibility for continued participation in such plans. The Committee may delegate its duties under this section.

(b)Representatives. A claimant may appoint a representative to act on his or her behalf. The Plan will only recognize a representative if the Plan has received a written authorization signed by the claimant and on a form prescribed by the Committee, with the following exceptions. The Plan will recognize a claimant’s legal representative, once the Plan is provided with documentation of such representation. If the claimant is a minor child, the Plan will recognize the claimant’s parent or guardian as the claimant’s representative. Once an authorized representative is appointed, the Plan will direct all information and notification regarding the claim to the authorized representative and the claimant will be copied on all notifications regarding decisions, unless the claimant provides specific written direction otherwise.

(c)Extension of Deadlines. The claimant may agree to an extension of any deadline that is mentioned in this section that applies to the Plan. The Committee or the relevant decision-maker may agree to an extension of any deadline that is mentioned in this section that applies to the claimant.

(d)Fees. The Plan may not charge any fees to a claimant for utilizing the claims process described in this section.

(e)Filing a Claim. A claim is made when the claimant files a claim in accordance with the procedures specified by the Committee. Any communication regarding benefits that is not made in accordance with the Plan’s procedures will not be treated as a claim.

- 14 -

(f)Initial Claims Decision. The Plan will decide a claim within a reasonable time up to 90 days after receiving the claim. The Plan will have a 90-day extension, but only if the Plan is unable to decide within 90 days for reasons beyond its control, the Plan notifies the claimant of the special circumstances requiring the need for the extension by the 90th day after receiving the claim, and the Plan notifies the claimant of the date by which the Plan expects to make a decision.

(g)Notification of Initial Decision. The Plan will provide the claimant with written notification of the Plan’s full or partial denial of a claim, reduction of a previously approved benefit, or termination of a benefit. The notification will include a statement of the reason(s) for the decision; references to the plan provision(s) on which the decision was based; a description of any additional material or information necessary to perfect the claim and why such information is needed; a description of the procedures and deadlines for appeal; a description of the right to obtain information about the appeal procedures; and a statement of the claimant’s right to sue.

(h)Appeal. The claimant may appeal any adverse or partially adverse decision. To appeal, the claimant must follow the procedures specified by the Committee. The appeal must be filed within 60 days of the date the claimant received notice of the initial decision. If the appeal is not timely and properly filed, the initial decision will be the final decision of the Plan. The claimant may submit documents, written comments, and other information in support of the appeal. The claimant will be given reasonable access at no charge to, and copies of, all documents, records, and other relevant information.

(i)Appellate Decision. The Plan will decide the appeal of a claim within a reasonable time of no more than 60 days from the date the Plan receives the claimant’s appeal. The 60-day deadline will be extended by an additional 60 days, but only if the Committee determines that special circumstances require an extension, the Plan notifies the claimant of the special circumstances requiring the need for the extension by the 60th day after receiving the appeal, and the Plan notifies the claimant of the date by which the Plan expects to make a decision. If an appeal is missing any information from the claimant that is needed to decide the appeal, the Plan will notify the claimant of the missing information and grant the claimant a reasonable period to provide the missing information. If the missing information is not timely provided, the Plan will deny the claim. If the missing information is timely provided, the 60-day deadline (or 120-day deadline with the extension) for the Plan to make its decision will be increased by the length of time between the date the Plan requested the missing information and the date the Plan received it.

(j)Notification of Decision. The Plan will provide the claimant with written notification of the Plan’s appellate decision (positive or adverse). The notification of any adverse or partially adverse decision must include a statement of the reason(s) for the decision; reference to the plan provision(s) on which the decision was based; a description of the procedures and deadlines for a second appeal, if any; a description of the right to obtain information about the second-appeal procedures; a statement of the claimant’s right to sue; and a statement that the claimant is entitled to receive, free of charge and upon request, reasonable access to and copies of all documents, records, and other information relevant to the claim.

(k)Arbitration. The claimant and the Plan may voluntarily enter into a binding arbitration to resolve any claim, in which case (i) the Plan and/or Company pays all the arbitration fees and costs, (ii) the Plan agrees that any statute of limitations or other defense based on timeliness is tolled during the time between the date the claimant completes and submits the forms that begin the arbitration process and the date of the arbitrator’s decision (which will only apply if the claimant

- 15 -

files suit after receiving an adverse decision from the arbitrator), and (iii) the Plan provides the claimant, upon request, sufficient information relating to the arbitration to enable the claimant to make an informed judgment about whether to submit the dispute to arbitration, including a statement that the claimant’s decision to choose or not choose arbitration will have no effect on the claimant’s rights to any other benefits under the Plan, and information about the applicable rules, the claimant’s right to representation, the process for selecting the arbitrator, and the circumstances, if any, that may affect the arbitrator’s impartiality.

Section 9.Distributions Due Infants or Incompetents.

If any person entitled to a distribution under the Plan is an infant, or if the Committee determines that any such person is incompetent by reason of physical or mental disability, whether or not legally adjudicated as incompetent, the Committee has the power to cause the distributions becoming due to such person to be made to another for his or her benefit, without responsibility of the Committee to see to the application of such distributions. Distributions made pursuant to such power will operate as a complete discharge of the Company, the trustee, the Plan, and the Committee.

Section 10.Use and Form of Words.

When any words are used herein in the masculine gender, they are to be construed as though they were also used in the feminine gender in all cases where they would so apply, and vice versa. Whenever any words are used herein in the singular form, they are to be construed as though they were also used in the plural form in all cases where they would so apply, and vice versa.

Section 11.Inalienability of Benefits.

Except for disclaimers under Section 3(f)(v), no Participant or Beneficiary has the right to assign, alienate, pledge, transfer, hypothecate, encumber, or anticipate his or her interest in any benefits under the Plan, nor are the benefits subject to garnishment by any creditor, nor may the benefits under the Plan be levied upon or attached. The preceding sentence does not apply to the enforcement of a federal tax levy made pursuant to Code §6331, the collection by the United States on a judgment resulting from an unpaid tax assessment, or any debt or obligation that is permitted to be collected from the Plan under federal law (such as the Federal Debt Collection Procedures Act of 1977).

Section 12.Applicable Law.

This Plan shall be interpreted to have been made in the State of Texas and the laws of the State of Texas shall control.

Dated July 29, 2019, effective as of the 2019 Restatement Date.

APACHE CORPORATION

ATTEST:

/s/Rajesh Sharma            By:    /s/ Dominic J. Ricotta        

Rajesh Sharma                Dominic J. Ricotta

Corporate Secretary                Vice President

- 16 -

EX-10.2

Exhibit 10.2

Apache Corporation
Executive Termination Policy

This Policy, which provides for the payment of certain benefits upon termination of employment, applies to:

All executive officers in the event of a termination of employment without cause.

Pursuant to the Policy, in the event of a termination of employment without cause, executive officers are eligible to receive the following benefits;

• base salary benefit:

• two times base salary for the chief executive officer;

• 1.75 times base salary for executive vice presidents;

• 1.5 times base salary for senior vice presidents and regional vice presidents;

• one times base salary for vice presidents;

• prorated target bonus;

• twelve months COBRA subsidy at active rates;

• three years’ service credit toward retiree medical;

• prorated vesting for restricted stock units and stock options and extension of exercise period to full life of original stock option award; and

• prorated vesting based on time in performance period for performance shares provided the executive has participated in the performance program for at least one year of the performance period (calculated at the end of the performance period and, if a payout is warranted, paid in cash according to the performance program’s vesting schedule).

A condition precedent to an executive officer receiving the benefits under this Executive Termination Policy will be for such executive to provide a full and final release to the Company of all claims in a form of release approved by the Company’s general counsel or chief executive officer.

Upon termination of employment after a Change of Control, all executive officers will receive no additional benefits pursuant to this Policy during the 24 months following a Change of Control when they are entitled to termination benefits under the Income Continuance Plan. Benefits for such officers after termination of employment upon a Change of Control will continue to be administered under the Company’s Income Continuance Plan and existing equity grant agreements with the Company. After expiration of the period that termination benefits are provided by the Income Continuance Plan, this Policy shall again be operative.

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: August 1, 2019

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: August 1, 2019

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 June 30, 2019, 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: August 1, 2019

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 June 30, 2019, 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: August 1, 2019

XML

Cover - shares	6 Months Ended
	Jun. 30, 2019	Jul. 31, 2019
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2019
Document Transition Report	false
Entity File Number	1-4300
Entity Registrant Name	APACHE CORPORATION
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	41-0747868
Entity Address, Address Line One	One Post Oak Central, 2000 Post Oak Boulevard, Suite 100
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77056-4400
City Area Code	713
Local Phone Number	296-6000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		375,958,977
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Entity Central Index Key	0000006769
Current Fiscal Year End Date	--12-31
Common Stock | New York Stock Exchange
Entity Information [Line Items]
Title of 12(b) Security	Common Stock, $0.625 par value
Trading Symbol	APA
Security Exchange Name	NYSE
Common Stock | Chicago Stock Exchange
Entity Information [Line Items]
Title of 12(b) Security	Common Stock, $0.625 par value
Trading Symbol	APA
Security Exchange Name	CHX
Common Stock | NASDAQ Global Select Market
Entity Information [Line Items]
Title of 12(b) Security	Common Stock, $0.625 par value
Trading Symbol	APA
Security Exchange Name	NASDAQ
7.75% Notes Due 2029 | New York Stock Exchange
Entity Information [Line Items]
Title of 12(b) Security	7.75% Notes Due 2029
Trading Symbol	APA/29
Security Exchange Name	NYSE

XML

STATEMENT OF CONSOLIDATED OPERATIONS (Unaudited) - USD ($) shares in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
REVENUES AND OTHER:
Oil and gas production revenues	$ 1,598,000,000	$ 1,936,000,000	$ 3,252,000,000	$ 3,669,000,000
Derivative instrument losses, net	(8,000,000)	(25,000,000)	(38,000,000)	(23,000,000)
Gain on divestitures	17,000,000	2,000,000	20,000,000	9,000,000
Other	(4,000,000)	16,000,000	4,000,000	21,000,000
Total revenues and other	1,603,000,000	1,929,000,000	3,238,000,000	3,676,000,000
OPERATING EXPENSES:
Lease operating expenses	389,000,000	356,000,000	754,000,000	705,000,000
Gathering, processing, and transmission	76,000,000	82,000,000	164,000,000	168,000,000
Taxes other than income	46,000,000	49,000,000	97,000,000	104,000,000
Exploration	95,000,000	76,000,000	164,000,000	152,000,000
General and administrative	102,000,000	117,000,000	225,000,000	231,000,000
Transaction, reorganization, and separation	6,000,000	12,000,000	10,000,000	12,000,000
Depreciation, depletion, and amortization	602,000,000	608,000,000	1,248,000,000	1,161,000,000
Asset retirement obligation accretion	26,000,000	27,000,000	53,000,000	54,000,000
Impairments	240,000,000	0	240,000,000	0
Financing costs, net	173,000,000	94,000,000	270,000,000	193,000,000
Total operating expenses	1,755,000,000	1,421,000,000	3,225,000,000	2,780,000,000
NET INCOME (LOSS) BEFORE INCOME TAXES	(152,000,000)	508,000,000	13,000,000	896,000,000
Current income tax provision	187,000,000	249,000,000	373,000,000	447,000,000
Deferred income tax benefit	(23,000,000)	(10,000,000)	(42,000,000)	(26,000,000)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	(316,000,000)	269,000,000	(318,000,000)	475,000,000
Net income attributable to noncontrolling interest				135,000,000
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$ (360,000,000)	$ 195,000,000	$ (407,000,000)	$ 340,000,000
NET INCOME (LOSS) PER COMMON SHARE:
Basic (in USD per share)	$ (0.96)	$ 0.51	$ (1.08)	$ 0.89
Diluted (in USD per share)	$ (0.96)	$ 0.51	$ (1.08)	$ 0.88
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic (in shares)	377	382	376	382
Diluted (in shares)	377	385	376	384
Oil
REVENUES AND OTHER:
Oil and gas production revenues	$ 1,397,000,000	$ 1,576,000,000	$ 2,707,000,000	$ 2,969,000,000
Natural Gas
REVENUES AND OTHER:
Oil and gas production revenues	118,000,000	212,000,000	354,000,000	434,000,000
Natural Gas liquids
REVENUES AND OTHER:
Oil and gas production revenues	83,000,000	148,000,000	191,000,000	266,000,000
Noncontrolling interest, Egypt
OPERATING EXPENSES:
Net income attributable to noncontrolling interest	43,000,000	74,000,000	87,000,000	135,000,000
Noncontrolling interest, Altus
OPERATING EXPENSES:
Net income attributable to noncontrolling interest	(3,000,000)	0	(2,000,000)	0
Altus Preferred Unit limited partners
OPERATING EXPENSES:
Net income attributable to noncontrolling interest	$ 4,000,000	$ 0	$ 4,000,000	$ 0

XML

STATEMENT OF CONSOLIDATED CASH FLOWS (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) including noncontrolling interest	$ (318)	$ 475
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized derivative instrument losses (gains), net	66	(104)
Gain on divestitures	(20)	(9)
Exploratory dry hole expense and unproved leasehold impairments	90	73
Depreciation, depletion, and amortization	1,248	1,161
Asset retirement obligation accretion	53	54
Impairments	240	0
Deferred income tax benefit	(42)	(26)
Loss on extinguishment of debt	75	0
Other	22	82
Changes in operating assets and liabilities:
Receivables	96	(101)
Inventories	(16)	(9)
Drilling advances	(8)	30
Deferred charges and other	(3)	69
Accounts payable	(66)	46
Accrued expenses	21	(20)
Deferred credits and noncurrent liabilities	16	7
NET CASH PROVIDED BY OPERATING ACTIVITIES	1,454	1,728
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(1,386)	(1,572)
Leasehold and property acquisitions	(34)	(38)
Additions to Altus gathering, processing, and transmission facilities	(246)	(284)
Altus equity method interests	(438)	0
Proceeds from sale of oil and gas properties	247	13
Other, net	25	(33)
NET CASH USED IN INVESTING ACTIVITIES	(1,832)	(1,914)
CASH FLOWS FROM FINANCING ACTIVITIES:
Fixed-rate debt borrowings	989	0
Payments on fixed-rate debt	(1,000)	(150)
Distributions to noncontrolling interest - Egypt	(164)	(155)
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	611	0
Dividends paid	(188)	(191)
Other	(35)	(14)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	213	(510)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(165)	(696)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	714	1,668
CASH AND CASH EQUIVALENTS AT END OF PERIOD	549	972
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	219	200
Income taxes paid, net of refunds	$ 285	$ 374

XML

CONSOLIDATED BALANCE SHEET (Unaudited) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
CURRENT ASSETS:
Cash and cash equivalents ($377 and $450 related to Altus VIE)	$ 549	$ 714
Receivables (net of allowance of $102 and $92)	1,098	1,194
Other current assets (Note 5) ($8 and $7 related to Altus VIE)	1,144	779
Total current assets	2,791	2,687
Oil and gas, on the basis of successful efforts accounting:
Proved properties	39,573	42,345
Unproved properties and properties under development	1,206	1,435
Gathering, processing, and transmission facilities ($1,452 and $1,251 related to Altus VIE)	2,057	1,856
Other ($38 and nil related to Altus VIE)	1,156	1,120
Property and equipment, gross	43,992	46,756
Less: Accumulated depreciation, depletion, and amortization ($40 and $24 related to Altus VIE)	(26,236)	(28,335)
Property and equipment, net	17,756	18,421
OTHER ASSETS:
Equity method interests ($527 and $91 related to Altus VIE)	527	121
Deferred charges and other ($72 and $71 related to Altus VIE)	732	353
Total assets	21,806	21,582
CURRENT LIABILITIES:
Accounts payable	644	709
Current debt ($23 and nil related to Altus VIE)	175	151
Other current liabilities (Note 7) ($44 and $85 related to Altus VIE)	1,443	1,341
Total current liabilities	2,262	2,201
LONG-TERM DEBT	8,157	8,093
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	348	391
Asset retirement obligation ($33 and $29 related to Altus VIE)	1,850	1,866
Other ($94 and nil related to Altus VIE)	514	219
Total deferred credits and other noncurrent liabilities	2,712	2,476
COMMITMENTS AND CONTINGENCIES (Note 11)
REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 12)	521	0
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 416,920,316 and 415,692,116 shares issued, respectively	261	260
Paid-in capital	11,931	12,106
Accumulated deficit	(2,455)	(2,048)
Treasury stock, at cost, 40,964,193 and 40,995,894 shares, respectively	(3,190)	(3,192)
Accumulated other comprehensive income	4	4
APACHE SHAREHOLDERS’ EQUITY	6,551	7,130
TOTAL EQUITY	8,154	8,812
TOTAL LIABILITIES AND EQUITY	21,806	21,582
Noncontrolling interest, Egypt
EQUITY:
Noncontrolling interest	1,198	1,275
Noncontrolling interest, Altus
EQUITY:
Noncontrolling interest	$ 405	$ 407

XML

CONSOLIDATED BALANCE SHEET (Unaudited) (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Cash and cash equivalents	$ 549	$ 714
Receivables	1,098	1,194
Other current assets (Note 5) ($8 and $7 related to Altus VIE)	1,144	779
Gathering, transmission and processing facilities	2,057	1,856
Other	1,156	1,120
Less: Accumulated depreciation, depletion, and amortization	(26,236)	(28,335)
Equity method interests	527	121
Deferred charges and other	732	353
Current debt	175	151
Other current liabilities	1,443	1,341
Asset retirement obligation	1,850	1,866
Other	$ 514	$ 219
Common stock, par value (in USD per share)	$ 0.625	$ 0.625
Common stock, shares authorized (in shares)	860,000,000	860,000,000
Common stock, shares issued (in shares)	416,920,316	415,692,116
Treasury stock, shares (in shares)	40,964,193	40,995,894
Altus VIE
Cash and cash equivalents	$ 377	$ 450
Receivables	102	92
Other current assets (Note 5) ($8 and $7 related to Altus VIE)	8	7
Gathering, transmission and processing facilities	1,452	1,251
Other	38	0
Less: Accumulated depreciation, depletion, and amortization	(40)	(24)
Equity method interests	527	91
Deferred charges and other	72	71
Current debt	23	0
Other current liabilities	44	85
Asset retirement obligation	33	29
Other	$ 94	$ 0

XML

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTEREST(Unaudited) - USD ($) $ in Millions	Total	Common Stock	Paid-In Capital	Accumulated Deficit	Treasury Stock	Accumulated Other Comprehensive Income	APACHE SHAREHOLDERS’ EQUITY	Noncontrolling Interest	Noncontrolling interest, Egypt	Noncontrolling interest, Altus	Altus Preferred Unit limited partners
Beginning balance at Dec. 31, 2017	$ 8,791	$ 259	$ 12,128	$ (2,088)	$ (2,887)	$ 4	$ 7,416	$ 1,375
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) attributable to common stock	340			340			340
Net income attributable to noncontrolling interest	135								$ 135	$ 0	$ 0
Distributions to noncontrolling interest - Egypt	(155)							(155)
Common dividends ($0.50 per share)	(191)		(191)				(191)
Other	75	1	74				75
Ending balance at Jun. 30, 2018	8,995	260	12,011	(1,748)	(2,887)	4	7,640	1,355
Beginning balance at Mar. 31, 2018	8,869	259	12,069	(1,943)	(2,887)	4	7,502	1,367
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) attributable to common stock	195			195			195
Net income attributable to noncontrolling interest									74	0	0
Distributions to noncontrolling interest - Egypt	(86)							(86)
Common dividends ($0.50 per share)	(95)		(95)				(95)
Other	38	1	37				38
Ending balance at Jun. 30, 2018	8,995	260	12,011	(1,748)	(2,887)	4	7,640	1,355
Beginning balance at Dec. 31, 2018	8,812	260	12,106	(2,048)	(3,192)	4	7,130	1,682
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) attributable to common stock	(407)			(407)			(407)
Net income attributable to noncontrolling interest									87	(2)	4
Distributions to noncontrolling interest - Egypt	(164)							(164)
Common dividends ($0.50 per share)	(188)		(188)				(188)
Other	16	1	13		2	0	16
Ending balance at Jun. 30, 2019	8,154	261	11,931	(2,455)	(3,190)	4	6,551	1,603
Beginning balance at Dec. 31, 2018	0										0
Increase (Decrease) in Temporary Equity [Roll Forward]
Issuance of Altus Preferred Units											517
Net income attributable to Altus Preferred Unit holders											4
Ending balance at Jun. 30, 2019	521										521
Beginning balance at Mar. 31, 2019	8,609	261	12,009	(2,095)	(3,190)	4	6,989	1,620
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) attributable to common stock	(360)			(360)			(360)
Net income attributable to noncontrolling interest									$ 43	$ (3)	4
Distributions to noncontrolling interest - Egypt	(57)							(57)
Common dividends ($0.50 per share)	(94)		(94)				(94)
Other	16		16			0	16
Ending balance at Jun. 30, 2019	8,154	$ 261	$ 11,931	$ (2,455)	$ (3,190)	$ 4	$ 6,551	$ 1,603
Beginning balance at Mar. 31, 2019											0
Increase (Decrease) in Temporary Equity [Roll Forward]
Issuance of Altus Preferred Units											517
Net income attributable to Altus Preferred Unit holders											4
Ending balance at Jun. 30, 2019	$ 521										$ 521

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STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTEREST(Unaudited) (Parenthetical) - $ / shares	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Statement of Stockholders' Equity [Abstract]
Common stock, dividends, per share (in USD per share)	$ 0.25	$ 0.25	$ 0.50	$ 0.50

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

6 Months Ended

Jun. 30, 2019

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of June 30, 2019, 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, 2018, with the exception of Accounting Standards Update (ASU) 2016-02, “Leases (Topic 842)” (see “Leases” section in this Note 1 below).

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated.

The Company consolidates all other investments in which, either through direct or indirect ownership, Apache has more than a 50 percent voting interest or controls the financial and operating decisions. Noncontrolling interests represent third-party ownership in the net assets of a consolidated Apache subsidiary and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in Apache’s Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate component of equity in Apache’s consolidated balance sheet.

Additionally, third-party investors own a minority interest of approximately 21 percent of Altus Midstream Company (ALTM), which is reflected as a separate noncontrolling interest component of equity in Apache’s consolidated balance sheet. Apache consolidates the activities of ALTM, which qualifies as a variable interest entity (VIE) under GAAP. Apache has concluded that it is the primary beneficiary of the VIE, as defined in the accounting standards, since Apache has the power, through its ownership, to direct those activities that most significantly impact the economic performance of ALTM and the obligation to absorb losses or the right to receive benefits that could be potentially significant to ALTM. This conclusion was based on a qualitative analysis that considered ALTM’s governance structure, the commercial agreements between ALTM, Altus Midstream LP (collectively with ALTM, Altus), and Apache, and the voting rights established between the members, which provide Apache with the ability to control the operations of Altus. On June 12, 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units (the Preferred Units) through a private offering that admitted additional limited partners with separate rights for the Preferred Unit holders. For further details on the terms of the Preferred Units and rights of the holders, refer to Note 12—Redeemable Noncontrolling Interest - Altus.

Investments in which Apache holds less than 50 percent of the voting interest are typically accounted for under the equity method of accounting, with the balance recorded separately as “Equity method interests” in Apache’s consolidated balance sheet and results of operations recorded as a component of “Other” under “Revenues and Other” in the Company’s statement of consolidated operations. Refer to Note 6—Equity Method Interests for more detail.

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, Note 10—Debt and Financing Costs, and Note 12—Redeemable Noncontrolling Interest - Altus.

Apache also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. In the second quarter of 2019, the Company entered into an agreement to sell certain of its assets in the Western Anadarko Basin in Oklahoma and Texas. As a result of this agreement, a separate impairment analysis was performed for each of the assets within the disposal group. The analyses were based on the agreed-upon proceeds less costs to sell for the transaction, a Level 1 fair value measurement. The carrying value of the net assets to be divested exceeded the fair value implied by the expected net proceeds, resulting in impairments totaling $240 million, including $86 million on the Company’s proved properties, $149 million on its unproved properties, and $5 million on other working capital. See Note 2—Acquisitions and Divestitures for more detail. The Company recorded no asset impairments in connection with fair value assessments in the second quarter and first six months of 2018.

Oil and Gas Property

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

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

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

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

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

The following table represents non-cash impairments of the carrying value of the Company’s proved and unproved property and equipment for the second quarters and first six months of 2019 and 2018:

	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(In millions)
Oil and Gas Property:
Proved	$	86	$	—	$	86	$	—
Unproved	188		21		211		37

Proved properties impaired during the second quarter of 2019 related to assets held for sale with an aggregate fair value of $379 million.

On the statement of consolidated operations, unproved leasehold impairments are typically recorded as a component of “Exploration” expense; however, in the second quarter of 2019, unproved impairments of $149 million were recorded in “Impairments” in connection with an agreement to sell certain non-core leasehold properties in Oklahoma and Texas.

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

Revenue Recognition

There have been no significant changes to the Company’s contracts with customers during the six months ended June 30, 2019. Apache recognizes revenue from its contracts with customers from the sale of its crude oil, natural gas, and natural gas liquids (NGLs) production as well as volumes purchased from third-parties. Each unit of quantity represents a single performance obligation that is satisfied at a point in time as control of the product has been transferred to the customer.

The contracted price is variable and is determined based on market-indexed prices adjusted for quality, transportation, and other market-reflective differentials. Sales proceeds related to third-party purchases volumes are considered revenue from a contract with a customer. Proceeds for these volumes totaled $18 million and $98 million for the second quarters of 2019 and 2018, respectively, and $42 million and $202 million for the first six months of 2019 and 2018, respectively. Associated purchase costs for these volumes totaled $15 million and $95 million for the second quarters of 2019 and 2018, respectively, and $37 million and $199 million for the first six months of 2019 and 2018, respectively. Proceeds and costs are both recorded as “Other” under “Revenues and Other” in the statement of consolidated operations.

The following table represents revenues from customers and non-customers for the second quarters and first six months of 2019 and 2018:

	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(In millions)
Revenues from customers	$	1,496	$	1,853	$	3,054	$	3,535
Revenues from non-customers	120		181		240		336

Payment from contracts with customers is typically received on a short-term basis after physical delivery of the product. Receivables from contracts with customers, net of allowance for doubtful accounts, totaled $936 million and $1.0 billion as of June 30, 2019 and December 31, 2018, 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 14—Business Segment Information for a disaggregation of revenue by each product sold.

Leases

On January 1, 2019, Apache adopted ASU 2016-02, “Leases (Topic 842),” which requires lessees to recognize separate right-of-use (ROU) assets and lease liabilities for most leases classified as operating leases under previous GAAP. Prior to adoption, the Financial Accounting Standards Board (FASB) issued transition guidance permitting an entity the option to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases, as well as an option to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the financial statements. Apache elected both transitional practical expedients. Under these transition options, comparative reporting was not required, and the provisions of the standard were applied prospectively to leases in effect at the date of adoption.

As allowed under the standard, the Company also applied practical expedients to carry forward its historical assessments of whether existing agreements contain a lease, classification of existing lease agreements, and treatment of initial direct lease costs. Apache also elected to exclude short-term leases (those with terms of 12 months or less) from the balance sheet presentation and accounts for non-lease and lease components as a single lease component for all asset classes. Short-term lease expense was not material for the second quarter and first six months of 2019.

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

Operating lease expense associated with ROU assets is recognized on a straight-line basis over the lease term. Lease expense is reflected on the statement of consolidated operations commensurate with the leased activities and nature of the services performed. Gross fixed operating lease expense, inclusive of amounts billable to partners and other working interest owners, was $59 million and $114 million for the second quarter and first six months of 2019, respectively.

In addition, the Company periodically enters into finance leases that are similar to those leases classified as capital leases under previous GAAP. Finance lease assets are included in “Property and Equipment” on the consolidated balance sheet, and the associated finance lease liabilities are reflected within “Current debt” and “Long-term debt,” as applicable. Prior periods include the reclassification of $39 million finance lease obligations from “Other” within “Deferred Credits and Other Noncurrent Liabilities” to “Long-term debt” on the Company’s consolidated balance sheet to conform with this presentation. There was no material impact to the Company’s statement of consolidated operations and statement of consolidated cash flows for its treatment of finance leases. Depreciation on the Company’s finance lease assets was $2 million and $4 million for the second quarter and first six months of 2019, respectively. Interest on the Company’s finance lease assets was $1 million for both the second quarter and first six months of 2019.

The following table represents the Company’s weighted average lease term and discount rate as of June 30, 2019:

	Operating Leases		Finance Leases
Weighted average remaining lease term	3.4 years		9.1 years
Weighted average discount rate	4.3	%	4.2	%

The undiscounted future minimum lease payments reconciled to the carrying value of the lease liabilities as of June 30, 2019 were as follows:

Net Minimum Commitments	Operating Leases(1)			Finance Leases(2)
	(In millions)
2019	$	101		$	16
2020	121			13
2021	47			3
2022	41			3
2023	24			3
Thereafter	41			40
Total future minimum lease payments	375			78
Less: imputed interest	(29		)	(15		)
Total lease liabilities	346			63
Current portion	(172		)	(25		)
Non-current portion	$	174		$	38

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

(2) Amounts represent the Company’s finance lease obligation related to physical power generators being leased on a one-year term with the right to purchase and a separate lease for the Company’s Midland, Texas regional office building.

The lease liability reflected in the table above represents the Company’s fixed minimum payments that are settled in accordance with the lease terms. Actual lease payments during the period may also include variable lease components such as common area maintenance, usage-based sales taxes and rate differentials, or other similar costs that are not determinable at the inception of the lease. Gross variable lease payments, inclusive of amounts billable to partners and other working interest owners, for the second quarter and first six months of 2019 were $24 million and $41 million, respectively.

New Pronouncements Issued But Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13, “Financial Instruments—Credit Losses.” The standard changes the impairment model for trade receivables, held-to-maturity debt securities, net investments in leases, loans, and other financial assets measured at amortized cost. The ASU requires the use of a new forward-looking “expected loss” model compared to the current “incurred loss” model, resulting in accelerated recognition of credit losses. This update is effective for the Company beginning in the first quarter of 2020, with early adoption permitted. The Company has developed and is in the process of executing a project plan for the implementation of the ASU and continues to evaluate and monitor standard setting activity. The Company does not believe the adoption and implementation of this ASU will have a material impact on its 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

6 Months Ended

Jun. 30, 2019

Business Combinations [Abstract]

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES

2019 Activity

During the second quarter and first six months of 2019, Apache completed leasehold and property acquisitions for total cash consideration of $19 million and $34 million, respectively, primarily in its U.S. onshore regions.

In the second quarter of 2019, Apache completed the sale of certain non-core assets in Oklahoma that had a carrying value of $218 million for aggregate expected cash proceeds of approximately $231 million. The Company recognized a $13 million gain during the second quarter of 2019 in association with this sale. During the first six months of 2019, the Company also completed the sale of certain other non-core assets, primarily in the Permian region, in multiple transactions for total cash proceeds of $11 million. The Company recognized a total net gain of approximately $7 million upon closing of these transactions.

In May 2019, Apache separately entered into an agreement to sell non-core assets in Oklahoma and Texas for $367 million, subject to normal and customary closing adjustments, plus the assumption of asset retirement obligations of $49 million. As a result of the agreement, the Company performed a fair value assessment of the assets and recorded impairments of $240 million to the carrying value of proved and unproved oil and gas properties, other fixed assets, and working capital. The remaining balance of proved oil and gas properties totaling $379 million were classified as current assets held for sale, and the asset retirement obligations were classified as a current liability held for sale as of June 30, 2019. The transaction closed in the third quarter of 2019, and no material gain or loss is expected to be recognized.

2018 Activity

During the second quarter and first six months of 2018, Apache completed $26 million and $38 million, respectively, of leasehold and property acquisitions primarily in its U.S. onshore and Egypt regions. During the first six months of 2018, the Company also completed the sale of certain non-core assets, primarily in the Permian region, in multiple transactions for total cash proceeds of $13 million. The Company recognized a total net gain of approximately $9 million during the first six months upon closing of these transactions.

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CAPITALIZED EXPLORATORY WELL COSTS

6 Months Ended

Jun. 30, 2019

Extractive Industries [Abstract]

CAPITALIZED EXPLORATORY WELL COSTS

CAPITALIZED EXPLORATORY WELL COSTS

The Company’s capitalized exploratory well costs were $124 million and $159 million at June 30, 2019 and December 31, 2018, 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, 2018 were charged to dry hole expense during the six months ended June 30, 2019. 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 proved reserves can be attributed to these projects.

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

6 Months Ended

Jun. 30, 2019

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, foreign currency exchange rates, and interest rates. The Company utilizes various types of derivative financial instruments to manage fluctuations in cash flows resulting from these fluctuations. 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 June 30, 2019, Apache had derivative positions with 7 counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, Apache may not realize the benefit of some of its derivative instruments resulting from changes in commodity prices, currency exchange rates, or interest rates.

Derivative Instruments

Commodity Derivative Instruments

As of June 30, 2019, Apache had the following open crude oil financial basis swap contracts:

Production Period	Settlement Index	Mbbls	Weighted Average Price Differential
July—September 2019	Midland-WTI/Cushing-WTI	2,484	$(8.60)
October—December 2019	Midland-WTI/Cushing-WTI	1,380	$(3.72)

As of June 30, 2019, Apache had the following open natural gas financial basis swap contracts:

Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential
July—December 2019	NYMEX Henry Hub/Waha	7,360	$(0.45)

Foreign Currency Derivative Instruments

Apache has open foreign currency costless collar contracts in GBP/USD for £12.5 million per each calendar month for 2019 with a weighted average floor and ceiling price of $1.20 and $1.35, respectively.

Altus Preferred Units Embedded Derivative

During the second quarter of 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units. Certain redemption features (the Redemption Option) embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. For further discussion of this derivative, see “Fair Value Measurements” below and Note 12—Redeemable Noncontrolling Interest - Altus.

Fair Value Measurements

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

The fair value of the Redemption Option, a Level 3 fair value measurement, was based on numerous factors including expected future interest rates using the Black-Karasinski model, imputed interest rate of Altus, the timing of periodic cash distributions, and dividend yields of the Preferred Units.

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)
June 30, 2019
Assets:
Commodity Derivative Instruments	$	—	$	5	$	—	$	5	$	(4	)	$	1
Foreign Currency Derivative Instruments	—		—		—		—		—			—
Liabilities:
Commodity Derivative Instruments	—		27		—		27		(4		)	23
Preferred Units Embedded Derivative	—		—		94		94		—			94
December 31, 2018
Assets:
Commodity Derivative Instruments	$	—	$	69	$	—	$	69	$	(14	)	$	55
Liabilities:
Commodity Derivative Instruments	—		25		—		25		(14		)	11

(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:

	June 30, 2019		December 31, 2018
	(In millions)
Current Assets: Other current assets	$	1	$	55
Total Assets	$	1	$	55
Current Liabilities: Other current liabilities	$	23	$	11
Deferred Credits and Other Noncurrent Liabilities: Other	94		—
Total Liabilities	$	117	$	11

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 June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions)
Realized gain (loss):
Derivative settlements, realized gain (loss)	$	13		$	(75	)	$	28		$	(117	)
Amortization of put premium, realized loss	—			(5		)	—			(10		)
Unrealized gain (loss)	(21		)	55			(66		)	104
Derivative instrument losses, net	$	(8	)	$	(25	)	$	(38	)	$	(23	)

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 losses (gains), net” in “Adjustments to reconcile net income (loss) to net cash provided by operating activities.”

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OTHER CURRENT ASSETS (Notes)

6 Months Ended

Jun. 30, 2019

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

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS

The following table provides detail of the Company’s other current assets as of June 30, 2019 and December 31, 2018:

	June 30, 2019		December 31, 2018
	(In millions)
Inventories	$	453	$	401
Drilling advances	226		218
Assets held for sale	379		—
Prepaid assets and other	86		160
Total other current assets	$	1,144	$	779

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EQUITY METHOD INTERESTS

6 Months Ended

Jun. 30, 2019

Equity Method Investments and Joint Ventures [Abstract]

EQUITY METHOD INTERESTS

EQUITY METHOD INTERESTS

Apache, through its ownership of Altus, has the following equity method interests in Permian Basin long-haul pipeline entities. For each of the equity method interests, Altus has the ability to exercise significant influence based on certain governance provisions and its participation in activities and decisions that impact the management and economic performance of the equity method interests.

	June 30, 2019				December 31, 2018
	Interest		Amount		Interest		Amount
	($ in millions)
Gulf Coast Express Pipeline LLC	16.0	%	$	251	15.0	%	$	91
EPIC Crude Holdings, LP	15.0	%	105		—		—
Permian Highway Pipeline LLC	26.7	%	171		—		—
			$	527			$	91

Altus’ underlying equity in the separate net assets within the financial statements of the respective entities as of June 30, 2019 and December 31, 2018 were $14 million less and $6 million more, respectively, than its equity method interest balances. Unamortized differences in the basis of the initial investments and Apache’s interest in the separate net assets within the financial statements of the investee will be amortized into net income over the useful lives of the underlying pipeline assets when they are placed into service.

The following table presents the activity in Apache’s equity method interests for the six months ended June 30, 2019:

	Gulf Coast Express Pipeline LLC(1)		EPIC Crude Holdings, LP			Permian Highway Pipeline LLC		Total
	(In millions)
Balance at December 31, 2018	$	91	$	—		$	—	$	91
Acquisitions	15		52			161		228
Capital contributions	144		56			10		210
Income (loss) from equity method interests	1		(3		)	—		(2		)
Balance at June 30, 2019	$	251	$	105		$	171	$	527

(1) In the second quarter of 2019, Altus Midstream LP exercised its option to acquire an additional 1 percent interest in the Gulf Coast Express Pipeline project, resulting in a total ownership of 16 percent at June 30, 2019.

As of December 31, 2018, Apache also held an investment in Marine Well Containment Company. This investment was sold in the first quarter of 2019 for $30 million, with no gain or loss recorded on the sale.

Exercise of Option in the Shin Oak Pipeline

Effective July 31, 2019, Altus Midstream Processing LP, a subsidiary of Altus Midstream, closed its option to acquire a 33.0 percent equity interest in the Shin Oak NGL pipeline project (Shin Oak) for approximately $441 million. Shin Oak comprises a 24-inch diameter mainline and related 20-inch lateral pipeline. The project, which is already in service, is expected to have ultimate capacity of approximately 550 MBbl/d and transports NGLs primarily from the Permian Basin to Mont Belvieu, Texas.

Shin Oak is owned and operated by Breviloba LLC (Breviloba), a subsidiary of Enterprise Products Partners, LP (Enterprise). Following closing of the option, Breviloba is 33.0 percent owned by Altus Midstream Processing LP and 67.0 percent owned by Enterprise.

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OTHER CURRENT LIABILITIES

6 Months Ended

Jun. 30, 2019

Payables and Accruals [Abstract]

OTHER CURRENT LIABILITIES

OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities as of June 30, 2019 and December 31, 2018:

	June 30, 2019		December 31, 2018
	(In millions)
Accrued operating expenses	$	78	$	65
Accrued exploration and development	535		667
Accrued gathering, processing, and transmission - Altus	34		81
Accrued compensation and benefits	135		177
Accrued interest	117		137
Accrued income taxes	126		58
Current asset retirement obligation	66		66
Current operating lease liability	172		—
Liabilities held for sale	49		—
Other	131		90
Total other current liabilities	$	1,443	$	1,341

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ASSET RETIREMENT OBLIGATION

6 Months Ended

Jun. 30, 2019

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 six-month period ended June 30, 2019:

	(In millions)
Asset retirement obligation at December 31, 2018	$	1,932
Liabilities incurred	7
Liabilities settled	(21		)
Liabilities divested	(6		)
Liabilities held for sale	(49		)
Accretion expense	53
Asset retirement obligation at June 30, 2019	1,916
Less current portion	(66		)
Asset retirement obligation, long-term	$	1,850

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INCOME TAXES

6 Months Ended

Jun. 30, 2019

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 second quarters of 2019 and 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.

Apache’s 2019 and 2018 year-to-date effective income tax rates were primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets.

Apache and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. The Company is currently under IRS audit for the 2014-2017 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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DEBT AND FINANCING COSTS

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

DEBT AND FINANCING COSTS

DEBT AND FINANCING COSTS

The following table presents the carrying value of the Company’s debt as of June 30, 2019 and December 31, 2018:

	June 30, 2019			December 31, 2018
	(In millions)
Notes and debentures before unamortized discount and debt issuance costs(1)	$	8,367		$	8,299
Finance lease obligations	63			40
Unamortized discount	(43		)	(44		)
Debt issuance costs	(55		)	(51		)
Total debt	8,332			8,244
Current maturities	(175		)	(151		)
Long-term debt	$	8,157		$	8,093

(1) The fair value of the Company’s notes and debentures was $8.6 billion and $7.8 billion as of June 30, 2019 and December 31, 2018, respectively. Apache uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

As of June 30, 2019, current debt included $150 million of 7.625% senior notes due July 1, 2019 and $25 million of finance lease obligations. On July 1, 2019, Apache’s 7.625% senior notes in original principal amount of $150 million matured and were repaid. As of December 31, 2018, current debt included $150 million of 7.625% senior notes due July 1, 2019 and $1 million of finance lease obligations.

On June 19, 2019, Apache closed offerings of $1.0 billion in aggregate principal amount of senior unsecured notes, comprised of $600 million in aggregate principal amount of 4.250% notes due January 15, 2030 and $400 million in aggregate principal amount of 5.350% notes due July 1, 2049. The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers and for general corporate purposes.

On June 21, 2019, the Company closed cash tender offers for certain outstanding notes. Apache accepted for purchase $932 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate of approximately $1.0 billion reflecting principal, the net premium to par, early tender premium, and accrued and unpaid interest. The Company recorded a net loss of $75 million on extinguishment of debt, including $7 million of unamortized debt issuance costs and discount, in connection with the note purchases.

In March 2018, the Company entered into a revolving credit facility with commitments totaling $4.0 billion. In March 2019, the term of this facility was extended by one year to March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exercise of an extension option. The Company can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of June 30, 2019. The facility is for general corporate purposes, and committed

borrowing capacity fully supports Apache’s commercial paper program. As of June 30, 2019, letters of credit aggregating approximately £3.1 million and no borrowings were outstanding under this facility.

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 June 30, 2019, the Company had no commercial paper outstanding.

In November 2018, Altus Midstream LP entered into a revolving credit facility for general corporate purposes that matures in November 2023 (subject to Altus Midstream LP’s two, one-year extension options). The agreement for this facility, as amended, provides aggregate commitments from a syndicate of banks of $650 million until the consolidated net income of Altus Midstream LP and its restricted subsidiaries, as adjusted pursuant to the agreement, for the immediately preceding fiscal quarter equals or exceeds $175 million on an annualized basis (such period, the Initial Period). Following the Initial Period, the aggregate commitments equal $800 million. All aggregate commitments include a letter of credit subfacility of up to $100 million and a swingline loan subfacility of up to $100 million. After the Initial Period, Altus Midstream LP may increase commitments up to an aggregate $1.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. As of June 30, 2019 and December 31, 2018, no borrowings or letters of credit were outstanding under this facility. The Altus Midstream LP credit facility is unsecured and is not guaranteed by Apache or any of Apache’s other subsidiaries.

Financing Costs, Net

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

	For the Quarter Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions)
Interest expense	$	109		$	110		$	216		$	222
Amortization of deferred loan costs	1			1			3			6
Capitalized interest	(9		)	(13		)	(17		)	(25		)
Loss on extinguishment of debt	75			—			75			—
Interest income	(3		)	(4		)	(7		)	(10		)
Financing costs, net	$	173		$	94		$	270		$	193

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COMMITMENTS AND CONTINGENCIES

6 Months Ended

Jun. 30, 2019

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 June 30, 2019, 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 9—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, 2018.

Argentine Environmental Claims and Argentina Tariff

No material change in the status of the YPF Sociedad Anónima indemnities matter has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018. Regarding the Pioneer Natural Resources Company indemnities matter, Company subsidiaries, on one hand, and Pioneer Natural Resources Company and TDF Holdings Company LDC, on the other, have settled and voluntarily dismissed certain indemnity-related claims against each other in a case captioned Apache Corporation, et al. v. Pioneer Natural Resources Co., et al., Cause No. 2014-64407, pending in the 189^th Judicial District of Harris County, Texas. Company subsidiaries retain certain rights to enforce certain Argentina-related indemnification obligations

against Pioneer pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer.

Louisiana Restoration 

As more fully described in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018, 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 2019, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including Apache. These cases have all been removed to federal courts in Louisiana. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable 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, 2018.

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 recently entered its order granting summary judgment in favor of Apache and finding that the plaintiffs had presented no evidence of damages. The plaintiffs have appealed. 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, 2018.

Australian Operations Divestiture Dispute

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

California Litigation

On July 17, 2017, in three separate actions, San Mateo County, California, Marin County, California, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil, gas, and coal companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County and in a separate action on January 22, 2018, the City of Richmond, filed similar lawsuits against many of the same defendants. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants. Apache believes that the claims made against it are baseless and intends to vigorously defend these lawsuits.

Castex Lawsuit

In a case styled Apache Corporation v. Castex Offshore, Inc, et. al., Cause No. 2015-48580, in the 113rd Judicial District Court of Harris County, Texas, Castex filed claims for alleged damages which they recently disclosed to be approximately $200 million, relating to overspend on the Belle Isle Gas Facility upgrade, and the drilling of five sidetracks on the Potomac #3 Well. After a jury trial, a verdict of approximately $60 million was entered against Apache. Apache intends to appeal.

Environmental Matters

As of June 30, 2019, the Company had an undiscounted reserve for environmental remediation of approximately $3 million. The Company is not aware of any environmental claims existing as of June 30, 2019 that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

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REEDEMABLE NONCONTROLLING INTEREST - ALTUS

6 Months Ended

Jun. 30, 2019

Equity [Abstract]

REEDEMABLE NONCONTROLLING INTEREST - ALTUS

Preferred Units Issuance

On June 12, 2019, Altus Midstream LP, an indirectly controlled subsidiary of Apache, issued and sold Series A Cumulative Redeemable Preferred Units (the Preferred Units) for an aggregate issue price of $625 million in a private offering exempt from the registration requirements of the Securities Act of 1933 (the Closing). Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. Pursuant to the partnership agreement of Altus Midstream LP:

• The Preferred Units bear quarterly distributions at a rate of 7 percent per annum, increasing after the fifth anniversary of Closing and upon the occurrence of specified events. Altus Midstream LP may pay distributions in-kind for the first six quarters after the Preferred Units are issued.

• The Preferred Units are redeemable at Altus Midstream LP’s option at any time in cash at a redemption price (the Redemption Price) equal to the greater of an 11.5 percent internal rate of return (increasing after the fifth anniversary of Closing to 13.75 percent) and a 1.3x multiple of invested capital. The Preferred Units will be redeemable at the holder’s option upon a change of control or liquidation of Altus Midstream LP and certain other events, including certain asset dispositions.

• The Preferred Units will be exchangeable for shares of ALTM’s Class A common stock at the holder’s election after the seventh anniversary of Closing or upon the occurrence of specified events. Each Preferred Unit will be exchangeable for a number of shares of ALTM’s Class A common stock equal to the Redemption Price divided by the volume-weighted average trading price of ALTM’s Class A common stock on the NASDAQ Capital Market for the 20 trading days immediately preceding the second trading day prior to the applicable exchange date, less a 6 percent discount.

• Each outstanding Preferred Unit has a liquidation preference equal to the Redemption Price payable before any amounts are paid in respect of Altus Midstream LP’s common units and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation.

• Preferred Units holders have rights to approve certain partnership business, financial, and governance-related matters.

• Altus Midstream LP is restricted from declaring or making cash distributions on its common units until all required distributions on the Preferred Units have been paid. In addition, before the fifth anniversary of Closing, aggregate cash distributions on, and redemptions of, Altus Midstream LP’s common units are limited to $650 million of cash from ordinary course operations if permitted under its credit facility. Cash distributions on, and redemptions of, Altus Midstream LP’s common units also are subject to satisfaction of leverage ratio requirements specified in its partnership agreement.

Classification

The Preferred Units are accounted for on the Company’s consolidated balance sheets as a redeemable noncontrolling interest classified as temporary equity based on the terms of the Preferred Units, including the redemption rights with respect thereto.

Initial Measurement

Altus recorded the net transaction price of $611 million, calculated as the negotiated transaction price of $625 million, less issue discounts of $4 million and transaction costs totaling $10 million.

Certain redemption features embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. Altus bifurcated and recognized at fair value an embedded derivative related to the Preferred Units of $94 million for a redemption option of the Preferred Unit holders. The derivative is reflected in “Other” within “Deferred Credits and Other Noncurrent Liabilities” on the Company’s consolidated balance sheet. The fair value of the embedded derivative, a Level 3 fair value measurement, was based on numerous factors including expected future interest rates using the Black-Karasinski model, imputed interest rate of Altus, the timing of periodic cash distributions, and dividend yields of the Preferred Units. See Note 4—Derivative Instruments and Hedging Activities for more detail.

The net transaction price was allocated to the preferred redeemable noncontrolling interest and the embedded features according to the associated initial fair value measurements as follows:

	June 12, 2019
	(In millions)
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners	$	517
Preferred Units embedded derivative	94
	$	611

Subsequent Measurement

Altus applies a two-step approach to subsequent measurement of the redeemable noncontrolling interest related to the Preferred Units by first allocating a portion of the net income of Altus Midstream LP in accordance with the terms of the partnership agreement. An additional adjustment to the carrying value of the Preferred Unit redeemable noncontrolling interest at each period end may be recorded, if applicable. The amount of such adjustment is determined based upon the accreted value method to reflect the passage of time until the Preferred Units are exchangeable at the option of the holder. Pursuant to this method, the net transaction price is accreted using the effective interest method to the Redemption Price calculated at the seventh anniversary of Closing. The total adjustment is limited to an amount such that the carrying amount of the Preferred Unit redeemable noncontrolling interest at each period end is equal to the greater of (a)(i) the carrying amount of the Preferred Units, plus (ii) the fair value of the embedded derivative liability or (b) the accreted value of the net transaction price.

Activity related to the Preferred Units during the six months ended June 30, 2019 is as follows:

	Units Outstanding	Financial Position(2)
	(In millions, except unit data)
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners: beginning of period	—	$	—
Issuance of Preferred Units, net	625,000	517
Allocation of Altus Midstream LP net income(1)	N/A	3
Accreted value adjustment	N/A	1
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners: end of period	625,000	521
Preferred Units embedded derivative		94
		$	615

(1) Subsequent to the balance sheet date, Altus Midstream LP provided notice to the Preferred Unit holders of record at June 30, 2019 of the amount of the initial distribution on the Preferred Units for the period from Closing to June 30, 2019. The holders also were notified that Altus Midstream LP elected to pay the entire amount of the approximate $2 million distribution in-kind in additional Preferred Units (PIK Units) on August 14, 2019. In total, 2,187.5 PIK Units will be issued in satisfaction of the initial required distribution.

(2) As at June 30, 2019, the aggregate Redemption Price was $628 million, based on an internal rate of return of 11.5 percent.

N/A - not applicable.

CAPITAL STOCK

Net Income (Loss) per Common Share

A reconciliation of the components of basic and diluted net income (loss) per common share for the quarters and six months ended June 30, 2019 and 2018, is presented in the table below.

 

	For the Quarter Ended June 30,
	2019							2018
	Loss			Shares	Per Share			Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock	$	(360	)	377	$	(0.96	)	$	195	382	$	0.51
Effect of Dilutive Securities:
Stock options and other	—			—	—			—		3	—
Diluted:
Income (loss) attributable to common stock	$	(360	)	377	$	(0.96	)	$	195	385	$	0.51

	For the Six Months Ended June 30,
	2019							2018
	Loss			Shares	Per Share			Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock	$	(407	)	376	$	(1.08	)	$	340	382	$	0.89
Effect of Dilutive Securities:
Stock options and other	—			—	—			—		2	(0.01		)
Diluted:
Income (loss) attributable to common stock	$	(407	)	376	$	(1.08	)	$	340	384	$	0.88

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 5.0 million and 5.9 million for the quarters ended June 30, 2019 and 2018, respectively, and 5.3 million and 6.4 million for the six months ended June 30, 2019 and 2018, respectively. The impact to net income (loss) attributable to common stock of an assumed conversion of the redeemable noncontrolling Preferred Units interests in Altus Midstream LP were anti-dilutive for the three- and six-month periods ended June 30, 2019.

Common Stock Dividends

For the quarters ended June 30, 2019 and 2018, Apache paid $94 million and $96 million, respectively, in dividends on its common stock. For the six months ended June 30, 2019 and 2018, the Company paid $188 million and $191 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 from time to time either in the open market or through privately negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through June 30, 2019, had repurchased a total of 40 million shares at an average price of $79.18 per share. During the fourth quarter of 2018, the Company’s Board of Directors authorized the purchase of up to 40 million additional shares of the Company’s common stock. The Company is not obligated to acquire any specific number of shares and has not purchased any shares during 2019.

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CAPITAL STOCK

6 Months Ended

Jun. 30, 2019

Equity [Abstract]

CAPITAL STOCK

Preferred Units Issuance

On June 12, 2019, Altus Midstream LP, an indirectly controlled subsidiary of Apache, issued and sold Series A Cumulative Redeemable Preferred Units (the Preferred Units) for an aggregate issue price of $625 million in a private offering exempt from the registration requirements of the Securities Act of 1933 (the Closing). Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. Pursuant to the partnership agreement of Altus Midstream LP:

• The Preferred Units bear quarterly distributions at a rate of 7 percent per annum, increasing after the fifth anniversary of Closing and upon the occurrence of specified events. Altus Midstream LP may pay distributions in-kind for the first six quarters after the Preferred Units are issued.

• The Preferred Units are redeemable at Altus Midstream LP’s option at any time in cash at a redemption price (the Redemption Price) equal to the greater of an 11.5 percent internal rate of return (increasing after the fifth anniversary of Closing to 13.75 percent) and a 1.3x multiple of invested capital. The Preferred Units will be redeemable at the holder’s option upon a change of control or liquidation of Altus Midstream LP and certain other events, including certain asset dispositions.

• The Preferred Units will be exchangeable for shares of ALTM’s Class A common stock at the holder’s election after the seventh anniversary of Closing or upon the occurrence of specified events. Each Preferred Unit will be exchangeable for a number of shares of ALTM’s Class A common stock equal to the Redemption Price divided by the volume-weighted average trading price of ALTM’s Class A common stock on the NASDAQ Capital Market for the 20 trading days immediately preceding the second trading day prior to the applicable exchange date, less a 6 percent discount.

• Each outstanding Preferred Unit has a liquidation preference equal to the Redemption Price payable before any amounts are paid in respect of Altus Midstream LP’s common units and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation.

• Preferred Units holders have rights to approve certain partnership business, financial, and governance-related matters.

• Altus Midstream LP is restricted from declaring or making cash distributions on its common units until all required distributions on the Preferred Units have been paid. In addition, before the fifth anniversary of Closing, aggregate cash distributions on, and redemptions of, Altus Midstream LP’s common units are limited to $650 million of cash from ordinary course operations if permitted under its credit facility. Cash distributions on, and redemptions of, Altus Midstream LP’s common units also are subject to satisfaction of leverage ratio requirements specified in its partnership agreement.

Classification

The Preferred Units are accounted for on the Company’s consolidated balance sheets as a redeemable noncontrolling interest classified as temporary equity based on the terms of the Preferred Units, including the redemption rights with respect thereto.

Initial Measurement

Altus recorded the net transaction price of $611 million, calculated as the negotiated transaction price of $625 million, less issue discounts of $4 million and transaction costs totaling $10 million.

Certain redemption features embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. Altus bifurcated and recognized at fair value an embedded derivative related to the Preferred Units of $94 million for a redemption option of the Preferred Unit holders. The derivative is reflected in “Other” within “Deferred Credits and Other Noncurrent Liabilities” on the Company’s consolidated balance sheet. The fair value of the embedded derivative, a Level 3 fair value measurement, was based on numerous factors including expected future interest rates using the Black-Karasinski model, imputed interest rate of Altus, the timing of periodic cash distributions, and dividend yields of the Preferred Units. See Note 4—Derivative Instruments and Hedging Activities for more detail.

The net transaction price was allocated to the preferred redeemable noncontrolling interest and the embedded features according to the associated initial fair value measurements as follows:

	June 12, 2019
	(In millions)
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners	$	517
Preferred Units embedded derivative	94
	$	611

Subsequent Measurement

Altus applies a two-step approach to subsequent measurement of the redeemable noncontrolling interest related to the Preferred Units by first allocating a portion of the net income of Altus Midstream LP in accordance with the terms of the partnership agreement. An additional adjustment to the carrying value of the Preferred Unit redeemable noncontrolling interest at each period end may be recorded, if applicable. The amount of such adjustment is determined based upon the accreted value method to reflect the passage of time until the Preferred Units are exchangeable at the option of the holder. Pursuant to this method, the net transaction price is accreted using the effective interest method to the Redemption Price calculated at the seventh anniversary of Closing. The total adjustment is limited to an amount such that the carrying amount of the Preferred Unit redeemable noncontrolling interest at each period end is equal to the greater of (a)(i) the carrying amount of the Preferred Units, plus (ii) the fair value of the embedded derivative liability or (b) the accreted value of the net transaction price.

Activity related to the Preferred Units during the six months ended June 30, 2019 is as follows:

	Units Outstanding	Financial Position(2)
	(In millions, except unit data)
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners: beginning of period	—	$	—
Issuance of Preferred Units, net	625,000	517
Allocation of Altus Midstream LP net income(1)	N/A	3
Accreted value adjustment	N/A	1
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners: end of period	625,000	521
Preferred Units embedded derivative		94
		$	615

(1) Subsequent to the balance sheet date, Altus Midstream LP provided notice to the Preferred Unit holders of record at June 30, 2019 of the amount of the initial distribution on the Preferred Units for the period from Closing to June 30, 2019. The holders also were notified that Altus Midstream LP elected to pay the entire amount of the approximate $2 million distribution in-kind in additional Preferred Units (PIK Units) on August 14, 2019. In total, 2,187.5 PIK Units will be issued in satisfaction of the initial required distribution.

(2) As at June 30, 2019, the aggregate Redemption Price was $628 million, based on an internal rate of return of 11.5 percent.

N/A - not applicable.

CAPITAL STOCK

Net Income (Loss) per Common Share

A reconciliation of the components of basic and diluted net income (loss) per common share for the quarters and six months ended June 30, 2019 and 2018, is presented in the table below.

 

	For the Quarter Ended June 30,
	2019							2018
	Loss			Shares	Per Share			Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock	$	(360	)	377	$	(0.96	)	$	195	382	$	0.51
Effect of Dilutive Securities:
Stock options and other	—			—	—			—		3	—
Diluted:
Income (loss) attributable to common stock	$	(360	)	377	$	(0.96	)	$	195	385	$	0.51

	For the Six Months Ended June 30,
	2019							2018
	Loss			Shares	Per Share			Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock	$	(407	)	376	$	(1.08	)	$	340	382	$	0.89
Effect of Dilutive Securities:
Stock options and other	—			—	—			—		2	(0.01		)
Diluted:
Income (loss) attributable to common stock	$	(407	)	376	$	(1.08	)	$	340	384	$	0.88

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 5.0 million and 5.9 million for the quarters ended June 30, 2019 and 2018, respectively, and 5.3 million and 6.4 million for the six months ended June 30, 2019 and 2018, respectively. The impact to net income (loss) attributable to common stock of an assumed conversion of the redeemable noncontrolling Preferred Units interests in Altus Midstream LP were anti-dilutive for the three- and six-month periods ended June 30, 2019.

Common Stock Dividends

For the quarters ended June 30, 2019 and 2018, Apache paid $94 million and $96 million, respectively, in dividends on its common stock. For the six months ended June 30, 2019 and 2018, the Company paid $188 million and $191 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 from time to time either in the open market or through privately negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through June 30, 2019, had repurchased a total of 40 million shares at an average price of $79.18 per share. During the fourth quarter of 2018, the Company’s Board of Directors authorized the purchase of up to 40 million additional shares of the Company’s common stock. The Company is not obligated to acquire any specific number of shares and has not purchased any shares during 2019.

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BUSINESS SEGMENT INFORMATION

6 Months Ended

Jun. 30, 2019

Segment Reporting [Abstract]

BUSINESS SEGMENT INFORMATION

BUSINESS SEGMENT INFORMATION

As of June 30, 2019, Apache is engaged in exploration and production (Upstream) activities across three operating segments: Egypt, the North Sea, and the U.S. Apache also has exploration interests in Suriname that may, over time, result in a reportable discovery and development opportunity. Apache’s Upstream business explores for, develops, and produces natural gas, crude oil and natural gas liquids. During the fourth quarter of 2018, Apache established a new reporting segment for its U.S. midstream business separate from its upstream oil and gas development activities. The midstream business is operated by Altus, which owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas, anchored by midstream service contracts to Apache’s production from its Alpine High resource play. Altus primarily generates revenue by providing fee-based natural gas gathering, compression, processing, and transportation services. Financial information for each segment is presented below:

	Egypt(1)		North Sea		U.S.			Altus			Intersegment Eliminations & Other			Total(2)
	Upstream							Midstream
	(In millions)
For the Quarter Ended June 30, 2019
Oil revenues	$	523	$	337	$	537		$	—		$	—		$	1,397
Natural gas revenues	70		18		30			—			—			118
Natural gas liquids revenues	3		5		75			—			—			83
Oil and gas production revenues	596		360		642			—			—			1,598
Midstream service affiliate revenues	—		—		—			24			(24		)	—
Operating Expenses:
Lease operating expenses	132		92		166			—			(1		)	389
Gathering, processing, and transmission	10		11		64			14			(23		)	76
Taxes other than income	—		—		42			4			—			46
Exploration	30		1		59			—			5			95
Depreciation, depletion, and amortization	174		99		320			9			—			602
Asset retirement obligation accretion	—		18		8			—			—			26
Impairments	—		—		240			—			—			240
	346		221		899			27			(19		)	1,474
Operating Income (Loss)(3)	$	250	$	139	$	(257	)	$	(3	)	$	(5	)	124
Other Income (Expense):
Gain on divestitures														17
Derivative instrument losses, net														(8		)
Other(4)														(4		)
General and administrative														(102		)
Transaction, reorganization, and separation														(6		)
Financing costs, net														(173		)
Loss Before Income Taxes														$	(152	)

	Egypt(1)		North Sea		U.S.			Altus			Intersegment Eliminations & Other			Total(2)
	Upstream							Midstream
	(In millions)
For the Six Months Ended June 30, 2019
Oil revenues	$	1,037	$	637	$	1,033		$	—		$	—		$	2,707
Natural gas revenues	151		50		153			—			—			354
Natural gas liquids revenues	7		11		173			—			—			191
Oil and gas production revenues	1,195		698		1,359			—			—			3,252
Midstream service affiliate revenues	—		—		—			58			(58		)	—
Operating Expenses:
Lease operating expenses	250		164		342			—			(2		)	754
Gathering, processing, and transmission	22		23		145			30			(56		)	164
Taxes other than income	—		—		91			6			—			97
Exploration	62		2		92			—			8			164
Depreciation, depletion, and amortization	361		198		673			16			—			1,248
Asset retirement obligation accretion	—		37		15			1			—			53
Impairments	—		—		240			—			—			240
	695		424		1,598			53			(50		)	2,720
Operating Income (Loss)(3)	$	500	$	274	$	(239	)	$	5		$	(8	)	532
Other Income (Expense):
Gain on divestitures														20
Derivative instrument losses, net														(38		)
Other(4)														4
General and administrative														(225		)
Transaction, reorganization, and separation														(10		)
Financing costs, net														(270		)
Income Before Income Taxes														$	13
Total Assets(5)	$	4,035	$	2,568	$	12,710		$	2,434		$	59		$	21,806
For the Quarter Ended June 30, 2018
Oil revenues	$	649	$	320	$	607		$	—		$	—		$	1,576
Natural gas revenues	89		27		96			—			—			212
Natural gas liquids revenues	4		5		139			—			—			148
Oil and gas production revenues	742		352		842			—			—			1,936
Midstream service affiliate revenues	—		—		—			12			(12		)	—
Operating Expenses:
Lease operating expenses	106		78		172			—			—			356
Gathering, processing, and transmission	11		10		62			11			(12		)	82
Taxes other than income	—		—		47			2			—			49
Exploration	32		3		40			—			1			76
Depreciation, depletion, and amortization	192		96		315			5			—			608
Asset retirement obligation accretion	—		19		8			—			—			27
Impairments	—		—		—			—			—			—
	341		206		644			18			(11		)	1,198
Operating Income (Loss)(3)	$	401	$	146	$	198		$	(6	)	$	(1	)	738
Other Income (Expense):
Gain on divestitures														2
Derivative instrument losses, net														(25		)
Other(4)														16
General and administrative														(117		)
Transaction, reorganization, and separation														(12		)
Financing costs, net														(94		)
Income Before Income Taxes														$	508

	Egypt(1)		North Sea		U.S.		Altus			Intersegment Eliminations & Other			Total(2)
	Upstream						Midstream
	(In millions)
For the Six Months Ended June 30, 2018
Oil revenues	$	1,218	$	591	$	1,160	$	—		$	—		$	2,969
Natural gas revenues	177		51		206		—			—			434
Natural gas liquids revenues	7		9		250		—			—			266
Oil and gas production revenues	1,402		651		1,616		—			—			3,669
Midstream service affiliate revenues	—		—		—		24			(24		)	—
Operating Expenses:
Lease operating expenses	204		172		329		—			—			705
Gathering, processing, and transmission	23		20		127		22			(24		)	168
Taxes other than income	—		—		99		5			—			104
Exploration	60		17		73		—			2			152
Depreciation, depletion, and amortization	378		191		584		8			—			1,161
Asset retirement obligation accretion	—		37		16		1			—			54
Impairments	—		—		—		—			—			—
	665		437		1,228		36			(22		)	2,344
Operating Income (Loss)(3)	$	737	$	214	$	388	$	(12	)	$	(2	)	1,325
Other Income (Expense):
Gain on divestitures													9
Derivative instrument losses, net													(23		)
Other(4)													21
General and administrative													(231		)
Transaction, reorganization, and separation													(12		)
Financing costs, net													(193		)
Income Before Income Taxes													$	896
Total Assets(5)	$	4,471	$	3,148	$	13,311	$	939		$	41		$	21,910

(1) Includes revenue from non-customers for the second quarters and six-month periods of 2019 and 2018 of:

	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(In millions)
Oil	$	111	$	165	$	218	$	304
Natural gas	9		15		21		30
Natural gas liquids	—		1		1		2

(2) Includes a noncontrolling interest in Egypt for the 2019 and 2018 periods, and Altus for the 2019 period.

(3) The operating income of U.S. and Egypt includes leasehold and other asset impairments totaling $277 million and $2 million, respectively, for the second quarter of 2019. The operating income of U.S. and Egypt includes leasehold and other asset impairments totaling $298 million and $4 million, respectively, for the first six months of 2019. The operating income of U.S. includes leasehold impairments totaling $21 million and $37 million for the second quarter and first six months of 2018, respectively.

(4) Included in Other are sales proceeds related to U.S. third-party purchased oil and gas which are determined to be revenue from customers. Proceeds for these volumes totaled $18 million and $98 million for the second quarters of 2019 and 2018, respectively, and $42 million and $202 million for the first six months of 2019 and 2018, respectively.

(5)

Intercompany balances are excluded from total assets.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

6 Months Ended

Jun. 30, 2019

Accounting Policies [Abstract]

Principles of Consolidation

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated.

The Company consolidates all other investments in which, either through direct or indirect ownership, Apache has more than a 50 percent voting interest or controls the financial and operating decisions. Noncontrolling interests represent third-party ownership in the net assets of a consolidated Apache subsidiary and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in Apache’s Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate component of equity in Apache’s consolidated balance sheet.

Additionally, third-party investors own a minority interest of approximately 21 percent of Altus Midstream Company (ALTM), which is reflected as a separate noncontrolling interest component of equity in Apache’s consolidated balance sheet. Apache consolidates the activities of ALTM, which qualifies as a variable interest entity (VIE) under GAAP. Apache has concluded that it is the primary beneficiary of the VIE, as defined in the accounting standards, since Apache has the power, through its ownership, to direct those activities that most significantly impact the economic performance of ALTM and the obligation to absorb losses or the right to receive benefits that could be potentially significant to ALTM. This conclusion was based on a qualitative analysis that considered ALTM’s governance structure, the commercial agreements between ALTM, Altus Midstream LP (collectively with ALTM, Altus), and Apache, and the voting rights established between the members, which provide Apache with the ability to control the operations of Altus. On June 12, 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units (the Preferred Units) through a private offering that admitted additional limited partners with separate rights for the Preferred Unit holders. For further details on the terms of the Preferred Units and rights of the holders, refer to Note 12—Redeemable Noncontrolling Interest - Altus.

Investments in which Apache holds less than 50 percent of the voting interest are typically accounted for under the equity method of accounting, with the balance recorded separately as “Equity method interests” in Apache’s consolidated balance sheet and results of operations recorded as a component of “Other” under “Revenues and Other” in the Company’s statement of consolidated operations.

Use of Estimates

Use of Estimates

Preparation of financial statements in conformity with GAAP 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).

Oil and Gas Property

Oil and Gas Property

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

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

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

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

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

The following table represents non-cash impairments of the carrying value of the Company’s proved and unproved property and equipment for the second quarters and first six months of 2019 and 2018:

	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(In millions)
Oil and Gas Property:
Proved	$	86	$	—	$	86	$	—
Unproved	188		21		211		37

Proved properties impaired during the second quarter of 2019 related to assets held for sale with an aggregate fair value of $379 million.

On the statement of consolidated operations, unproved leasehold impairments are typically recorded as a component of “Exploration” expense; however, in the second quarter of 2019, unproved impairments of $149 million were recorded in “Impairments” in connection with an agreement to sell certain non-core leasehold properties in Oklahoma and Texas.

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

Revenue Recognition

Revenue Recognition

There have been no significant changes to the Company’s contracts with customers during the six months ended June 30, 2019. Apache recognizes revenue from its contracts with customers from the sale of its crude oil, natural gas, and natural gas liquids (NGLs) production as well as volumes purchased from third-parties. Each unit of quantity represents a single performance obligation that is satisfied at a point in time as control of the product has been transferred to the customer.

The contracted price is variable and is determined based on market-indexed prices adjusted for quality, transportation, and other market-reflective differentials. Sales proceeds related to third-party purchases volumes are considered revenue from a contract with a customer. Proceeds for these volumes totaled $18 million and $98 million for the second quarters of 2019 and 2018, respectively, and $42 million and $202 million for the first six months of 2019 and 2018, respectively. Associated purchase costs for these volumes totaled $15 million and $95 million for the second quarters of 2019 and 2018, respectively, and $37 million and $199 million for the first six months of 2019 and 2018, respectively. Proceeds and costs are both recorded as “Other” under “Revenues and Other” in the statement of consolidated operations.

The following table represents revenues from customers and non-customers for the second quarters and first six months of 2019 and 2018:

	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(In millions)
Revenues from customers	$	1,496	$	1,853	$	3,054	$	3,535
Revenues from non-customers	120		181		240		336

Payment from contracts with customers is typically received on a short-term basis after physical delivery of the product. Receivables from contracts with customers, net of allowance for doubtful accounts, totaled $936 million and $1.0 billion as of June 30, 2019 and December 31, 2018, 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

Leases

Leases

On January 1, 2019, Apache adopted ASU 2016-02, “Leases (Topic 842),” which requires lessees to recognize separate right-of-use (ROU) assets and lease liabilities for most leases classified as operating leases under previous GAAP. Prior to adoption, the Financial Accounting Standards Board (FASB) issued transition guidance permitting an entity the option to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases, as well as an option to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the financial statements. Apache elected both transitional practical expedients. Under these transition options, comparative reporting was not required, and the provisions of the standard were applied prospectively to leases in effect at the date of adoption.

As allowed under the standard, the Company also applied practical expedients to carry forward its historical assessments of whether existing agreements contain a lease, classification of existing lease agreements, and treatment of initial direct lease costs. Apache also elected to exclude short-term leases (those with terms of 12 months or less) from the balance sheet presentation and accounts for non-lease and lease components as a single lease component for all asset classes. Short-term lease expense was not material for the second quarter and first six months of 2019.

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

Operating lease expense associated with ROU assets is recognized on a straight-line basis over the lease term. Lease expense is reflected on the statement of consolidated operations commensurate with the leased activities and nature of the services performed. Gross fixed operating lease expense, inclusive of amounts billable to partners and other working interest owners, was $59 million and $114 million for the second quarter and first six months of 2019, respectively.

In addition, the Company periodically enters into finance leases that are similar to those leases classified as capital leases under previous GAAP. Finance lease assets are included in “Property and Equipment” on the consolidated balance sheet, and the associated finance lease liabilities are reflected within “Current debt” and “Long-term debt,” as applicable. Prior periods include the reclassification of $39 million finance lease obligations from “Other” within “Deferred Credits and Other Noncurrent Liabilities” to “Long-term debt” on the Company’s consolidated balance sheet to conform with this presentation. There was no material impact to the Company’s statement of consolidated operations and statement of consolidated cash flows for its treatment of finance leasesThe lease liability reflected in the table above represents the Company’s fixed minimum payments that are settled in accordance with the lease terms. Actual lease payments during the period may also include variable lease components such as common area maintenance, usage-based sales taxes and rate differentials, or other similar costs that are not determinable at the inception of the lease.

New Pronouncements Issued But Not Yet Adopted

New Pronouncements Issued But Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13, “Financial Instruments—Credit Losses.” The standard changes the impairment model for trade receivables, held-to-maturity debt securities, net investments in leases, loans, and other financial assets measured at amortized cost. The ASU requires the use of a new forward-looking “expected loss” model compared to the current “incurred loss” model, resulting in accelerated recognition of credit losses. This update is effective for the Company beginning in the first quarter of 2020, with early adoption permitted. The Company has developed and is in the process of executing a project plan for the implementation of the ASU and continues to evaluate and monitor standard setting activity. The Company does not believe the adoption and implementation of this ASU will have a material impact on its 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)

6 Months Ended

Jun. 30, 2019

Accounting Policies [Abstract]

Schedule of Non-cash Impairments of Proved and Unproved Property and Equipment

The following table represents non-cash impairments of the carrying value of the Company’s proved and unproved property and equipment for the second quarters and first six months of 2019 and 2018:

	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(In millions)
Oil and Gas Property:
Proved	$	86	$	—	$	86	$	—
Unproved	188		21		211		37

Schedule of Revenues Revenues from Customers and Non-Customers

The following table represents revenues from customers and non-customers for the second quarters and first six months of 2019 and 2018:

	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(In millions)
Revenues from customers	$	1,496	$	1,853	$	3,054	$	3,535
Revenues from non-customers	120		181		240		336

Schedule of Weighted Average Lease Term and Discount Rate Related to Leases

The following table represents the Company’s weighted average lease term and discount rate as of June 30, 2019:

	Operating Leases		Finance Leases
Weighted average remaining lease term	3.4 years		9.1 years
Weighted average discount rate	4.3	%	4.2	%

Operating Lease, Liability, Maturity

The undiscounted future minimum lease payments reconciled to the carrying value of the lease liabilities as of June 30, 2019 were as follows:

Net Minimum Commitments	Operating Leases(1)			Finance Leases(2)
	(In millions)
2019	$	101		$	16
2020	121			13
2021	47			3
2022	41			3
2023	24			3
Thereafter	41			40
Total future minimum lease payments	375			78
Less: imputed interest	(29		)	(15		)
Total lease liabilities	346			63
Current portion	(172		)	(25		)
Non-current portion	$	174		$	38

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

(2)

Amounts represent the Company’s finance lease obligation related to physical power generators being leased on a one-year term with the right to purchase and a separate lease for the Company’s Midland, Texas regional office building

Finance Lease, Liability, Maturity

The undiscounted future minimum lease payments reconciled to the carrying value of the lease liabilities as of June 30, 2019 were as follows:

Net Minimum Commitments	Operating Leases(1)			Finance Leases(2)
	(In millions)
2019	$	101		$	16
2020	121			13
2021	47			3
2022	41			3
2023	24			3
Thereafter	41			40
Total future minimum lease payments	375			78
Less: imputed interest	(29		)	(15		)
Total lease liabilities	346			63
Current portion	(172		)	(25		)
Non-current portion	$	174		$	38

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

(2)

Amounts represent the Company’s finance lease obligation related to physical power generators being leased on a one-year term with the right to purchase and a separate lease for the Company’s Midland, Texas regional office building

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)

6 Months Ended

Jun. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of commodity derivative positions

As of June 30, 2019, Apache had the following open crude oil financial basis swap contracts:

Production Period	Settlement Index	Mbbls	Weighted Average Price Differential
July—September 2019	Midland-WTI/Cushing-WTI	2,484	$(8.60)
October—December 2019	Midland-WTI/Cushing-WTI	1,380	$(3.72)

As of June 30, 2019, Apache had the following open natural gas financial basis swap contracts:

Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential
July—December 2019	NYMEX Henry Hub/Waha	7,360	$(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)
June 30, 2019
Assets:
Commodity Derivative Instruments	$	—	$	5	$	—	$	5	$	(4	)	$	1
Foreign Currency Derivative Instruments	—		—		—		—		—			—
Liabilities:
Commodity Derivative Instruments	—		27		—		27		(4		)	23
Preferred Units Embedded Derivative	—		—		94		94		—			94
December 31, 2018
Assets:
Commodity Derivative Instruments	$	—	$	69	$	—	$	69	$	(14	)	$	55
Liabilities:
Commodity Derivative Instruments	—		25		—		25		(14		)	11

(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)
June 30, 2019
Assets:
Commodity Derivative Instruments	$	—	$	5	$	—	$	5	$	(4	)	$	1
Foreign Currency Derivative Instruments	—		—		—		—		—			—
Liabilities:
Commodity Derivative Instruments	—		27		—		27		(4		)	23
Preferred Units Embedded Derivative	—		—		94		94		—			94
December 31, 2018
Assets:
Commodity Derivative Instruments	$	—	$	69	$	—	$	69	$	(14	)	$	55
Liabilities:
Commodity Derivative Instruments	—		25		—		25		(14		)	11

(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:

	June 30, 2019		December 31, 2018
	(In millions)
Current Assets: Other current assets	$	1	$	55
Total Assets	$	1	$	55
Current Liabilities: Other current liabilities	$	23	$	11
Deferred Credits and Other Noncurrent Liabilities: Other	94		—
Total Liabilities	$	117	$	11

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 June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions)
Realized gain (loss):
Derivative settlements, realized gain (loss)	$	13		$	(75	)	$	28		$	(117	)
Amortization of put premium, realized loss	—			(5		)	—			(10		)
Unrealized gain (loss)	(21		)	55			(66		)	104
Derivative instrument losses, net	$	(8	)	$	(25	)	$	(38	)	$	(23	)

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OTHER CURRENT ASSETS (Tables)

6 Months Ended

Jun. 30, 2019

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

Schedule of Other Current Assets

The following table provides detail of the Company’s other current assets as of June 30, 2019 and December 31, 2018:

	June 30, 2019		December 31, 2018
	(In millions)
Inventories	$	453	$	401
Drilling advances	226		218
Assets held for sale	379		—
Prepaid assets and other	86		160
Total other current assets	$	1,144	$	779

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EQUITY METHOD INTERESTS (Tables)

6 Months Ended

Jun. 30, 2019

Equity Method Investments and Joint Ventures [Abstract]

Summary of equity method investment information

The following table presents the activity in Apache’s equity method interests for the six months ended June 30, 2019:

	Gulf Coast Express Pipeline LLC(1)		EPIC Crude Holdings, LP			Permian Highway Pipeline LLC		Total
	(In millions)
Balance at December 31, 2018	$	91	$	—		$	—	$	91
Acquisitions	15		52			161		228
Capital contributions	144		56			10		210
Income (loss) from equity method interests	1		(3		)	—		(2		)
Balance at June 30, 2019	$	251	$	105		$	171	$	527

	June 30, 2019				December 31, 2018
	Interest		Amount		Interest		Amount
	($ in millions)
Gulf Coast Express Pipeline LLC	16.0	%	$	251	15.0	%	$	91
EPIC Crude Holdings, LP	15.0	%	105		—		—
Permian Highway Pipeline LLC	26.7	%	171		—		—
			$	527			$	91

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OTHER CURRENT LIABILITIES (Tables)

6 Months Ended

Jun. 30, 2019

Payables and Accruals [Abstract]

Detail of Other Current Liabilities

The following table provides detail of the Company’s other current liabilities as of June 30, 2019 and December 31, 2018:

	June 30, 2019		December 31, 2018
	(In millions)
Accrued operating expenses	$	78	$	65
Accrued exploration and development	535		667
Accrued gathering, processing, and transmission - Altus	34		81
Accrued compensation and benefits	135		177
Accrued interest	117		137
Accrued income taxes	126		58
Current asset retirement obligation	66		66
Current operating lease liability	172		—
Liabilities held for sale	49		—
Other	131		90
Total other current liabilities	$	1,443	$	1,341

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ASSET RETIREMENT OBLIGATION (Tables)

6 Months Ended

Jun. 30, 2019

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the six-month period ended June 30, 2019:

	(In millions)
Asset retirement obligation at December 31, 2018	$	1,932
Liabilities incurred	7
Liabilities settled	(21		)
Liabilities divested	(6		)
Liabilities held for sale	(49		)
Accretion expense	53
Asset retirement obligation at June 30, 2019	1,916
Less current portion	(66		)
Asset retirement obligation, long-term	$	1,850

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DEBT AND FINANCING COSTS (Tables)

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Schedule of Debt

The following table presents the carrying value of the Company’s debt as of June 30, 2019 and December 31, 2018:

	June 30, 2019			December 31, 2018
	(In millions)
Notes and debentures before unamortized discount and debt issuance costs(1)	$	8,367		$	8,299
Finance lease obligations	63			40
Unamortized discount	(43		)	(44		)
Debt issuance costs	(55		)	(51		)
Total debt	8,332			8,244
Current maturities	(175		)	(151		)
Long-term debt	$	8,157		$	8,093

(1)

The fair value of the Company’s notes and debentures was $8.6 billion and $7.8 billion as of June 30, 2019 and December 31, 2018, respectively. Apache uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

Components of Financing Costs, Net

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

	For the Quarter Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions)
Interest expense	$	109		$	110		$	216		$	222
Amortization of deferred loan costs	1			1			3			6
Capitalized interest	(9		)	(13		)	(17		)	(25		)
Loss on extinguishment of debt	75			—			75			—
Interest income	(3		)	(4		)	(7		)	(10		)
Financing costs, net	$	173		$	94		$	270		$	193

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REEDEMABLE NONCONTROLLING INTEREST - ALTUS (Tables)

6 Months Ended

Jun. 30, 2019

Equity [Abstract]

Schedule of Preferred Units

Activity related to the Preferred Units during the six months ended June 30, 2019 is as follows:

	Units Outstanding	Financial Position(2)
	(In millions, except unit data)
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners: beginning of period	—	$	—
Issuance of Preferred Units, net	625,000	517
Allocation of Altus Midstream LP net income(1)	N/A	3
Accreted value adjustment	N/A	1
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners: end of period	625,000	521
Preferred Units embedded derivative		94
		$	615

(1) Subsequent to the balance sheet date, Altus Midstream LP provided notice to the Preferred Unit holders of record at June 30, 2019 of the amount of the initial distribution on the Preferred Units for the period from Closing to June 30, 2019. The holders also were notified that Altus Midstream LP elected to pay the entire amount of the approximate $2 million distribution in-kind in additional Preferred Units (PIK Units) on August 14, 2019. In total, 2,187.5 PIK Units will be issued in satisfaction of the initial required distribution.

(2)

As at June 30, 2019, the aggregate Redemption Price was $628 million, based on an internal rate of return of 11.5 percent.

The net transaction price was allocated to the preferred redeemable noncontrolling interest and the embedded features according to the associated initial fair value measurements as follows:

	June 12, 2019
	(In millions)
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners	$	517
Preferred Units embedded derivative	94
	$	611

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CAPITAL STOCK (Tables)

6 Months Ended

Jun. 30, 2019

Equity [Abstract]

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

A reconciliation of the components of basic and diluted net income (loss) per common share for the quarters and six months ended June 30, 2019 and 2018, is presented in the table below.

 

	For the Quarter Ended June 30,
	2019							2018
	Loss			Shares	Per Share			Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock	$	(360	)	377	$	(0.96	)	$	195	382	$	0.51
Effect of Dilutive Securities:
Stock options and other	—			—	—			—		3	—
Diluted:
Income (loss) attributable to common stock	$	(360	)	377	$	(0.96	)	$	195	385	$	0.51

	For the Six Months Ended June 30,
	2019							2018
	Loss			Shares	Per Share			Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock	$	(407	)	376	$	(1.08	)	$	340	382	$	0.89
Effect of Dilutive Securities:
Stock options and other	—			—	—			—		2	(0.01		)
Diluted:
Income (loss) attributable to common stock	$	(407	)	376	$	(1.08	)	$	340	384	$	0.88

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BUSINESS SEGMENT INFORMATION (Tables)

6 Months Ended

Jun. 30, 2019

Segment Reporting [Abstract]

Financial Segment Information

Financial information for each segment is presented below:

	Egypt(1)		North Sea		U.S.			Altus			Intersegment Eliminations & Other			Total(2)
	Upstream							Midstream
	(In millions)
For the Quarter Ended June 30, 2019
Oil revenues	$	523	$	337	$	537		$	—		$	—		$	1,397
Natural gas revenues	70		18		30			—			—			118
Natural gas liquids revenues	3		5		75			—			—			83
Oil and gas production revenues	596		360		642			—			—			1,598
Midstream service affiliate revenues	—		—		—			24			(24		)	—
Operating Expenses:
Lease operating expenses	132		92		166			—			(1		)	389
Gathering, processing, and transmission	10		11		64			14			(23		)	76
Taxes other than income	—		—		42			4			—			46
Exploration	30		1		59			—			5			95
Depreciation, depletion, and amortization	174		99		320			9			—			602
Asset retirement obligation accretion	—		18		8			—			—			26
Impairments	—		—		240			—			—			240
	346		221		899			27			(19		)	1,474
Operating Income (Loss)(3)	$	250	$	139	$	(257	)	$	(3	)	$	(5	)	124
Other Income (Expense):
Gain on divestitures														17
Derivative instrument losses, net														(8		)
Other(4)														(4		)
General and administrative														(102		)
Transaction, reorganization, and separation														(6		)
Financing costs, net														(173		)
Loss Before Income Taxes														$	(152	)

	Egypt(1)		North Sea		U.S.			Altus			Intersegment Eliminations & Other			Total(2)
	Upstream							Midstream
	(In millions)
For the Six Months Ended June 30, 2019
Oil revenues	$	1,037	$	637	$	1,033		$	—		$	—		$	2,707
Natural gas revenues	151		50		153			—			—			354
Natural gas liquids revenues	7		11		173			—			—			191
Oil and gas production revenues	1,195		698		1,359			—			—			3,252
Midstream service affiliate revenues	—		—		—			58			(58		)	—
Operating Expenses:
Lease operating expenses	250		164		342			—			(2		)	754
Gathering, processing, and transmission	22		23		145			30			(56		)	164
Taxes other than income	—		—		91			6			—			97
Exploration	62		2		92			—			8			164
Depreciation, depletion, and amortization	361		198		673			16			—			1,248
Asset retirement obligation accretion	—		37		15			1			—			53
Impairments	—		—		240			—			—			240
	695		424		1,598			53			(50		)	2,720
Operating Income (Loss)(3)	$	500	$	274	$	(239	)	$	5		$	(8	)	532
Other Income (Expense):
Gain on divestitures														20
Derivative instrument losses, net														(38		)
Other(4)														4
General and administrative														(225		)
Transaction, reorganization, and separation														(10		)
Financing costs, net														(270		)
Income Before Income Taxes														$	13
Total Assets(5)	$	4,035	$	2,568	$	12,710		$	2,434		$	59		$	21,806
For the Quarter Ended June 30, 2018
Oil revenues	$	649	$	320	$	607		$	—		$	—		$	1,576
Natural gas revenues	89		27		96			—			—			212
Natural gas liquids revenues	4		5		139			—			—			148
Oil and gas production revenues	742		352		842			—			—			1,936
Midstream service affiliate revenues	—		—		—			12			(12		)	—
Operating Expenses:
Lease operating expenses	106		78		172			—			—			356
Gathering, processing, and transmission	11		10		62			11			(12		)	82
Taxes other than income	—		—		47			2			—			49
Exploration	32		3		40			—			1			76
Depreciation, depletion, and amortization	192		96		315			5			—			608
Asset retirement obligation accretion	—		19		8			—			—			27
Impairments	—		—		—			—			—			—
	341		206		644			18			(11		)	1,198
Operating Income (Loss)(3)	$	401	$	146	$	198		$	(6	)	$	(1	)	738
Other Income (Expense):
Gain on divestitures														2
Derivative instrument losses, net														(25		)
Other(4)														16
General and administrative														(117		)
Transaction, reorganization, and separation														(12		)
Financing costs, net														(94		)
Income Before Income Taxes														$	508

	Egypt(1)		North Sea		U.S.		Altus			Intersegment Eliminations & Other			Total(2)
	Upstream						Midstream
	(In millions)
For the Six Months Ended June 30, 2018
Oil revenues	$	1,218	$	591	$	1,160	$	—		$	—		$	2,969
Natural gas revenues	177		51		206		—			—			434
Natural gas liquids revenues	7		9		250		—			—			266
Oil and gas production revenues	1,402		651		1,616		—			—			3,669
Midstream service affiliate revenues	—		—		—		24			(24		)	—
Operating Expenses:
Lease operating expenses	204		172		329		—			—			705
Gathering, processing, and transmission	23		20		127		22			(24		)	168
Taxes other than income	—		—		99		5			—			104
Exploration	60		17		73		—			2			152
Depreciation, depletion, and amortization	378		191		584		8			—			1,161
Asset retirement obligation accretion	—		37		16		1			—			54
Impairments	—		—		—		—			—			—
	665		437		1,228		36			(22		)	2,344
Operating Income (Loss)(3)	$	737	$	214	$	388	$	(12	)	$	(2	)	1,325
Other Income (Expense):
Gain on divestitures													9
Derivative instrument losses, net													(23		)
Other(4)													21
General and administrative													(231		)
Transaction, reorganization, and separation													(12		)
Financing costs, net													(193		)
Income Before Income Taxes													$	896
Total Assets(5)	$	4,471	$	3,148	$	13,311	$	939		$	41		$	21,910

(1) Includes revenue from non-customers for the second quarters and six-month periods of 2019 and 2018 of:

	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(In millions)
Oil	$	111	$	165	$	218	$	304
Natural gas	9		15		21		30
Natural gas liquids	—		1		1		2

(2) Includes a noncontrolling interest in Egypt for the 2019 and 2018 periods, and Altus for the 2019 period.

(3) The operating income of U.S. and Egypt includes leasehold and other asset impairments totaling $277 million and $2 million, respectively, for the second quarter of 2019. The operating income of U.S. and Egypt includes leasehold and other asset impairments totaling $298 million and $4 million, respectively, for the first six months of 2019. The operating income of U.S. includes leasehold impairments totaling $21 million and $37 million for the second quarter and first six months of 2018, respectively.

(4) Included in Other are sales proceeds related to U.S. third-party purchased oil and gas which are determined to be revenue from customers. Proceeds for these volumes totaled $18 million and $98 million for the second quarters of 2019 and 2018, respectively, and $42 million and $202 million for the first six months of 2019 and 2018, respectively.

(5)

Intercompany balances are excluded from total assets.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Jan. 01, 2019	Dec. 31, 2018
Schedule Of Significant Accounting Policies [Line Items]
Impairments	$ 240,000,000	$ 0	$ 240,000,000	$ 0
Assets held-for-sale, fair value	379,000,000		379,000,000
Oil and gas production revenues	1,598,000,000	1,936,000,000	3,252,000,000	3,669,000,000
Cost of oil and gas purchased	76,000,000	82,000,000	164,000,000	168,000,000
Receivables from contracts with customer, net	936,000,000		936,000,000			$ 1,000,000,000.0
Fixed operating lease expenses	59,000,000		114,000,000
Other noncurrent liabilities	(514,000,000)		(514,000,000)			(219,000,000)
Long-term debt	8,157,000,000		8,157,000,000			$ 8,093,000,000
Variable lease payment	24,000,000		41,000,000
Accounting Standards Update 2016-02
Schedule Of Significant Accounting Policies [Line Items]
Other noncurrent liabilities					$ 39,000,000
Long-term debt					$ 39,000,000
Oil and Gas, Purchased
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas production revenues	18,000,000	98,000,000	42,000,000	202,000,000
Cost of oil and gas purchased	15,000,000	95,000,000	37,000,000	199,000,000
Oil and Gas Properties, Proved
Schedule Of Significant Accounting Policies [Line Items]
Impairments	86,000,000	0	86,000,000	0
Oil and Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Impairments	188,000,000	$ 21,000,000	211,000,000	$ 37,000,000
Other Working Capital
Schedule Of Significant Accounting Policies [Line Items]
Impairments	5,000,000
Assets held under Finance Leases
Schedule Of Significant Accounting Policies [Line Items]
Depreciation	2,000,000		4,000,000
Interest costs	$ 1,000,000		$ 1,000,000
Altus Midstream Company
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners	21.00%		21.00%
Minimum
Schedule Of Significant Accounting Policies [Line Items]
Percentage of voting interests acquired	50.00%		50.00%
Maximum
Schedule Of Significant Accounting Policies [Line Items]
Percentage of voting interests acquired	50.00%		50.00%
Oklahoma and Texas | Oil and Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Impairments	$ 149,000,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Schedule of Revenues from Customers and Non-Customers (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Accounting Policies [Abstract]
Revenues from customers	$ 1,496	$ 1,853	$ 3,054	$ 3,535
Revenues from non-customers	$ 120	$ 181	$ 240	$ 336

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Company's Weighted Average Lease Term and Discount Rate related to Leases (Details)	Jun. 30, 2019
Accounting Policies [Abstract]
Operating leases, weighted average remaining lease term	3 years 4 months 24 days
Finance leases, weighted average remaining lease term	9 years 1 month 6 days
Operating leases, weighted average discount rate	4.30%
Finance leases, weighted average discount rate	4.20%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Schedule of Future Minimum Lease Payments (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Operating Leases
2019	$ 101
2020	121
2021	47
2022	41
2023	24
Thereafter	41
Total future minimum lease payments	375
Less: imputed interest	(29)
Total lease liabilities	346
Current portion	(172)
Non-current portion	174
Finance Leases
2019	16
2020	13
2021	3
2022	3
2023	3
Thereafter	40
Total future minimum lease payments	78
Less: imputed interest	(15)
Total lease liabilities	63
Current portion	(25)	$ (1)
Non-current portion	$ 38

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ACQUISITIONS AND DIVESTITURES (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	May 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Leasehold and property acquisitions			$ 34,000,000	$ 38,000,000
Assets held for sale	$ 379,000,000		379,000,000			$ 0
Impairments	240,000,000	$ 0	240,000,000	0
Assets held-for-sale, fair value	379,000,000		379,000,000
U.S. onshore regions
Business Acquisition [Line Items]
Leasehold and property acquisitions	19,000,000	$ 26,000,000	34,000,000	38,000,000
Permian region | Disposed of by Sale
Business Acquisition [Line Items]
Proceeds from sale of non-core assets			11,000,000	13,000,000
Gains on sale of non-core assets			7,000,000	$ 9,000,000
Oklahoma | Disposed of by Sale
Business Acquisition [Line Items]
Proceeds from sale of non-core assets	231,000,000
Gains on sale of non-core assets	13,000,000
Assets held for sale	218,000,000		218,000,000
Oklahoma and Texas | Held-for-sale
Business Acquisition [Line Items]
Non-core assets, selling price					$ 367,000,000
Asset retirement obligation assumed					$ 49,000,000
Impairments	240,000,000
Assets held-for-sale, fair value	$ 379,000,000		$ 379,000,000

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CAPITALIZED EXPLORATORY WELL COSTS (Details) - USD ($)	Jun. 30, 2019	Dec. 31, 2018
Extractive Industries [Abstract]
Capitalized exploratory well costs	$ 124,000,000	$ 159,000,000
Capitalized exploratory well costs that have been capitalized for period greater than one year		$ 0

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Instruments (Detail) bbl in Thousands, £ in Millions	6 Months Ended
	Jun. 30, 2019 GBP (£) MMBTU $ / MMBTU Counterparty bbl
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of derivative counterparties | Counterparty	7
Put Options | July—September 2019 | Crude Oil | Midland-WTI/Cushing-WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume | bbl	2,484
Weighted Average Price Differential	(8.60)
Put Options | October—December 2019 | Crude Oil | Midland-WTI/Cushing-WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume | bbl	1,380
Weighted Average Price Differential	(3.72)
Collars | January—December 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, weighted average floor price (USD per bbl)	1.20
Derivative, weighted average ceiling price (USD per bbl)	1.35
Derivative, notional amount | £	£ 12.5
Basis Swap | July—December 2019 | Natural Gas | NYMEX Henry Hub/Waha
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price Differential | MMBTU	(0.45)
Derivative, nonmonetary notional amount, energy | MMBTU	7,360,000

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities Measured at Fair Value (Details) - Recurring - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Derivative [Line Items]
Derivative asset	$ 1	$ 55
Derivative liability	117	11
Commodity Derivative Instruments
Derivative [Line Items]
Derivative asset, fair value	5	69
Derivative asset, netting	(4)	(14)
Derivative asset	1	55
Derivative liability, fair value	27	25
Derivative liability, netting	(4)	(14)
Derivative liability	23	11
Commodity Derivative Instruments | Quoted Price in Active Markets (Level 1)
Derivative [Line Items]
Derivative asset, fair value	0	0
Derivative liability, fair value	0	0
Commodity Derivative Instruments | Significant Other Inputs (Level 2)
Derivative [Line Items]
Derivative asset, fair value	5	69
Derivative liability, fair value	27	25
Commodity Derivative Instruments | Significant Unobservable Inputs (Level 3)
Derivative [Line Items]
Derivative asset, fair value	0	0
Derivative liability, fair value	0	$ 0
Foreign Currency Derivative Instruments
Derivative [Line Items]
Derivative asset, fair value	0
Derivative asset, netting	0
Derivative asset	0
Foreign Currency Derivative Instruments | Quoted Price in Active Markets (Level 1)
Derivative [Line Items]
Derivative asset, fair value	0
Foreign Currency Derivative Instruments | Significant Other Inputs (Level 2)
Derivative [Line Items]
Derivative asset, fair value	0
Foreign Currency Derivative Instruments | Significant Unobservable Inputs (Level 3)
Derivative [Line Items]
Derivative asset, fair value	0
Preferred Units Embedded Derivative
Derivative [Line Items]
Derivative liability, fair value	94
Derivative liability, netting	0
Derivative liability	94
Preferred Units Embedded Derivative | Quoted Price in Active Markets (Level 1)
Derivative [Line Items]
Derivative liability, fair value	0
Preferred Units Embedded Derivative | Significant Other Inputs (Level 2)
Derivative [Line Items]
Derivative liability, fair value	0
Preferred Units Embedded Derivative | Significant Unobservable Inputs (Level 3)
Derivative [Line Items]
Derivative liability, fair value	$ 94

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities and Locations on Consolidated Balance Sheet (Details) - Recurring - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Derivative asset	$ 1	$ 55
Derivative liability	117	11
Current Assets: Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset	1	55
Current Liabilities: Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability	23	11
Deferred Credits and Other Noncurrent Liabilities: Other
Derivatives, Fair Value [Line Items]
Derivative liability	94	0
Commodity Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative asset	1	55
Derivative liability	$ 23	$ 11

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Activities Recorded in the Statement of Consolidated Operations (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Realized gain (loss):
Unrealized gain (loss)			$ (66)	$ 104
Not Designated as Hedging Instrument
Realized gain (loss):
Derivative settlements, realized gain (loss)	$ 13	$ (75)	28	(117)
Amortization of put premium, realized loss	0	(5)	0	(10)
Unrealized gain (loss)	(21)	55	(66)	104
Derivative instrument losses, net	$ (8)	$ (25)	$ (38)	$ (23)

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OTHER CURRENT ASSETS (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Inventories	$ 453	$ 401
Drilling advances	226	218
Assets held for sale	379	0
Prepaid assets and other	86	160
Total other current assets	$ 1,144	$ 779

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EQUITY METHOD INTERESTS - Summary of Investments (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Equity method interests	$ 527	$ 121
Altus Midstream Company
Schedule of Equity Method Investments [Line Items]
Equity method interests	$ 527	$ 91
Altus Midstream Company | Gulf Coast Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Interest	16.00%	15.00%
Equity method interests	$ 251	$ 91
Altus Midstream Company | EPIC Crude Holdings, LP
Schedule of Equity Method Investments [Line Items]
Interest	15.00%	0.00%
Equity method interests	$ 105	$ 0
Altus Midstream Company | Permian Highway Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Interest	26.70%	0.00%
Equity method interests	$ 171	$ 0

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EQUITY METHOD INTERESTS - Narrative (Details)		6 Months Ended
	Jul. 31, 2019 USD ($) MBbls / d	Jun. 30, 2019 USD ($)	Jun. 30, 2018 USD ($)	Mar. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Schedule of Equity Method Investments [Line Items]
Difference between carrying amount and underlying equity amount		$ 14,000,000			$ 6,000,000
Equity method interests		527,000,000			$ 121,000,000
Payments to acquire equity method investments		438,000,000	$ 0
Marine Well Containment Company
Schedule of Equity Method Investments [Line Items]
Equity method interests				$ 30,000,000
Gain (loss) on disposal of investment		$ 0
Subsequent Event | Shin Oak Pipeline Project
Schedule of Equity Method Investments [Line Items]
Ownership percentage	33.00%
Payments to acquire equity method investments	$ 441,000,000
Pipeline production capacity (in MBbl/d) | MBbls / d	550
Breviloba LLC | Altus Midstream Processing LP | Subsequent Event
Schedule of Equity Method Investments [Line Items]
Ownership percentage by noncontrolling owners	33.00%
Breviloba LLC | Enterprise | Subsequent Event
Schedule of Equity Method Investments [Line Items]
Ownership percentage by parent	67.00%

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EQUITY METHOD INTERESTS - Rollforward Activity (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance		$ 121
Acquisitions		438	$ 0
Equity method interest, ending balance	$ 527	527
Altus Midstream Company
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance		91
Acquisitions		228
Capital contributions		210
Income (loss) from equity method interests		(2)
Equity method interest, ending balance	527	527
Altus Midstream Company | Gulf Coast Express Pipeline LLC
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance		91
Acquisitions		15
Capital contributions		144
Income (loss) from equity method interests		1
Equity method interest, ending balance	$ 251	$ 251
Equity method investment, percentage acquired	1.00%
Ownership percentage	16.00%	16.00%		15.00%
Altus Midstream Company | EPIC Crude Holdings, LP
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance		$ 0
Acquisitions		52
Capital contributions		56
Income (loss) from equity method interests		(3)
Equity method interest, ending balance	$ 105	$ 105
Ownership percentage	15.00%	15.00%		0.00%
Altus Midstream Company | Permian Highway Pipeline LLC
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance		$ 0
Acquisitions		161
Capital contributions		10
Income (loss) from equity method interests		0
Equity method interest, ending balance	$ 171	$ 171
Ownership percentage	26.70%	26.70%		0.00%

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OTHER CURRENT LIABILITIES (Detail) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Payables and Accruals [Abstract]
Accrued operating expenses	$ 78	$ 65
Accrued exploration and development	535	667
Accrued gathering, processing, and transmission - Altus	34	81
Accrued compensation and benefits	135	177
Accrued interest	117	137
Accrued income taxes	126	58
Current asset retirement obligation	66	66
Current operating lease liability	172
Liabilities held for sale	49	0
Other	131	90
Total other current liabilities	$ 1,443	$ 1,341

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ASSET RETIREMENT OBLIGATION (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at the beginning of period	$ 1,932
Liabilities incurred	7
Liabilities settled	(21)
Liabilities divested	(6)
Liabilities held for sale	(49)
Accretion expense	53
Asset retirement obligation at the end of period	$ 1,932	$ 1,916	$ 1,932
Less current portion		(66)	(66)
Asset retirement obligation, long-term		$ 1,850	$ 1,866

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DEBT AND FINANCING COSTS - Schedule of Debt (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Finance lease obligations	$ 63
Capital lease obligations		$ 40
Unamortized discount	(43)	(44)
Debt issuance costs	(55)	(51)
Total debt	8,332	8,244
Current maturities	(175)	(151)
Long-term debt	8,157	8,093
Notes And Debentures | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross	$ 8,367	$ 8,299

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DEBT AND FINANCING COSTS - Additional Information (Detail) £ in Millions		1 Months Ended		3 Months Ended		6 Months Ended
	Jun. 21, 2019 USD ($)	Mar. 31, 2019 USD ($)	Nov. 30, 2018 USD ($) contract	Jun. 30, 2019 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2019 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2019 GBP (£)	Jun. 19, 2019 USD ($)	Mar. 01, 2019 USD ($)	Feb. 28, 2019 USD ($)	Dec. 31, 2018 USD ($)	Mar. 31, 2018 USD ($)
Debt Instrument [Line Items]
Finance lease obligations, current				$ 25,000,000		$ 25,000,000						$ 1,000,000
Loss on extinguishment of debt				75,000,000	$ 0	75,000,000	$ 0
Available commercial paper				3,500,000,000		3,500,000,000
Commercial paper outstanding				0		0
Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, committed amount													$ 4,000,000,000.0
Extended financing agreement term		1 year
Credit facility maximum borrowing capacity		$ 5,000,000,000.0
Letters of credit outstanding, amount				0		0
Letter of Credit
Debt Instrument [Line Items]
Line of credit facility, committed amount				2,080,000,000.00		2,080,000,000.00
Credit facility maximum borrowing capacity				3,000,000,000.0		3,000,000,000.0
Line of credit facility aggregate commitment amount | £								£ 3.1
Notes And Debentures
Debt Instrument [Line Items]
Debt instrument, fair value				8,600,000,000		8,600,000,000						7,800,000,000
Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, face amount									$ 1,000,000,000.0
Unsecured Debt | 6.9% senior notes due September 15, 2018
Debt Instrument [Line Items]
Debt instrument, face amount				$ 150,000,000		$ 150,000,000						$ 150,000,000
Debt instrument, stated interest rate				7.625%		7.625%		7.625%				7.625%
Unsecured Debt | 4.250% Notes Due January 15, 2030
Debt Instrument [Line Items]
Debt instrument, face amount									$ 600,000,000
Debt instrument, stated interest rate									4.25%
Unsecured Debt | 5.350% Notes Due July 1, 2049
Debt Instrument [Line Items]
Debt instrument, face amount									$ 400,000,000
Debt instrument, stated interest rate									5.35%
Altus Midstream LP | Line of Credit | Revolving Credit Facility
Debt Instrument [Line Items]
Extended financing agreement term			1 year
Credit facility maximum borrowing capacity			$ 650,000,000							$ 1,500,000,000	$ 800,000,000
Line of credit facility, number of extension options | contract			2
Debt covenant, minimum consolidated net income for three consecutive calendar months			$ 175,000,000
Borrowings on line of credit				$ 0		$ 0						$ 0
Altus Midstream LP | Line of Credit | Letter of Credit
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity											100,000,000
Altus Midstream LP | Line of Credit | Swingline Loan Subfacility
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity											$ 100,000,000
Commercial Paper
Debt Instrument [Line Items]
Period for borrowing funds						270 days
Senior Notes [Member]
Debt Instrument [Line Items]
Debt repurchased principal amount	$ 932,000,000
Extinguishment of debt amount	1,000,000,000.0
Loss on extinguishment of debt	75,000,000
Unamortized debt issuance costs and discount	$ 7,000,000

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DEBT AND FINANCING COSTS - Components of Financing Costs, Net (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Debt Disclosure [Abstract]
Interest expense	$ 109	$ 110	$ 216	$ 222
Amortization of deferred loan costs	1	1	3	6
Capitalized interest	(9)	(13)	(17)	(25)
Loss on extinguishment of debt	75	0	75	0
Interest income	(3)	(4)	(7)	(10)
Financing costs, net	$ 173	$ 94	$ 270	$ 193

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COMMITMENTS AND CONTINGENCIES (Detail) $ in Millions, $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Apr. 30, 2017 AUD ($)
Commitment And Contingencies [Line Items]
Accrued liability for legal contingencies	$ 39
Undiscounted reserve for environmental remediation	3
Apollo Exploration Lawsuit
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages	200
Apollo Exploration Lawsuit | Minimum
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages		$ 1,100
Australian Operations Divestiture Dispute | Apache Australia Operation
Commitment And Contingencies [Line Items]
Gain contingency, unrecorded amount				$ 80
Loss contingency, estimated of possible loss amount			$ 200
Castex Lawsuit
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages	60
Loss contingency, estimated of possible loss amount	$ 200

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REEDEMABLE NONCONTROLLING INTEREST - ALTUS - Additional Information (Details) - USD ($) $ in Millions		3 Months Ended	6 Months Ended
	Jun. 12, 2019	Jun. 30, 2019	Jun. 30, 2019	Jun. 30, 2018
Class of Stock [Line Items]
Redeemable noncontrolling interest - Altus Preferred Unit limited partners			$ 611	$ 0
Altus Midstream LP
Class of Stock [Line Items]
Preferred Units, redemption terms, internal rate of return		11.50%	11.50%
Embedded derivative	$ 94	$ 94	$ 94
Altus Midstream LP | Altus Preferred Unit limited partners
Class of Stock [Line Items]
Aggregate issue price of Preferred Units	625
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	611
Preferred Units, quarterly distribution rate per annum		7.00%
Preferred Units, redemption terms, internal rate of return		11.50%	11.50%
Preferred Units, redemption terms, internal rate of return after fifth anniversary of closing		13.75%	13.75%
Preferred Units, redemption terms, multiple of invested capital		1.3	1.3
Preferred Units, exchangeable, number of preceding trading days		20 days
Preferred Units, exchangeable, discount percentage		6.00%	6.00%
Maximum amount of distributions to common unit holders	650
Issue discount	4
Transaction costs	10
Embedded derivative	$ 94

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REEDEMABLE NONCONTROLLING INTEREST - ALTUS - Schedule of Preferred Units (Details) - Altus Midstream LP - USD ($) $ in Millions	Jun. 30, 2019	Jun. 12, 2019
Class of Stock [Line Items]
Embedded derivative	$ 94	$ 94
Altus Preferred Unit limited partners
Class of Stock [Line Items]
Redeemable noncontrolling interest — Preferred Unit limited partners		517
Embedded derivative		94
Transaction price, net		$ 611

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REEDEMABLE NONCONTROLLING INTEREST - ALTUS - Activity Related to Preferred Units (Details) - USD ($) $ in Millions		3 Months Ended	6 Months Ended
	Aug. 14, 2019	Jun. 30, 2019	Jun. 30, 2019	Jun. 12, 2019
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance			$ 0
Ending balance		$ 521	521
Altus Preferred Unit limited partners
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance		0	0
Issuance of Preferred Units, net		517	517
Allocation of Altus Midstream net income		4	4
Ending balance		521	521
Altus Midstream LP
Increase (Decrease) in Temporary Equity [Roll Forward]
Embedded derivative liability		94	94	$ 94
Redeemable Noncontrolling Interest, Net Of Embedded Derivative Liability		615	615
Preferred Units, Redemption Price		$ 628	$ 628
Preferred Units, redemption terms, internal rate of return		11.50%	11.50%
Altus Midstream LP | Altus Preferred Unit limited partners
Movement In Preferred Units [Roll Forward]
Preferred Units: beginning of period (in shares)			0
Issuance of Preferred Units, net (in shares)			625,000
Preferred Units: end of period (in shares)		625,000	625,000
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance			$ 0
Issuance of Preferred Units, net		$ 517
Allocation of Altus Midstream net income		3
Accreted value adjustment		1
Ending balance		$ 521	$ 521
Embedded derivative liability				$ 94
Preferred Units, redemption terms, internal rate of return		11.50%	11.50%
Altus Midstream LP | Scenario, Forecast | Subsequent Event
Increase (Decrease) in Temporary Equity [Roll Forward]
Preferred Units, distribution in-kind	$ 2
Preferred Units, distribution, PIK units	2,187.5

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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		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Basic:
Income (loss) attributable to common stock	$ (360)	$ 195	$ (407)	$ 340
Income (loss) attributable to common stock, shares	377	382	376	382
Basic net income (loss) per share (in USD per share)	$ (0.96)	$ 0.51	$ (1.08)	$ 0.89
Effect of Dilutive Securities:
Stock options and other (in shares)		3		2
Stock options and other (in USD per share)				$ (0.01)
Diluted:
Income (loss) attributable to common stock	$ (360)	$ 195	$ (407)	$ 340
Income (loss) attributable to common stock, shares	377	385	376	384
Diluted net income (loss) per share (in USD per share)	$ (0.96)	$ 0.51	$ (1.08)	$ 0.88

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CAPITAL STOCK - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		6 Months Ended		70 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Mar. 31, 2019	Dec. 31, 2018	Dec. 31, 2014
Equity [Abstract]
Options and restricted stock, anti-dilutive (in shares)	5,000,000.0	5,900,000	5,300,000	6,400,000
Payments of dividend on common stock	$ 94	$ 96	$ 188	$ 191
Number of shares authorized to be repurchased (in shares)						40,000,000	40,000,000
Number of shares repurchased during period (in shares)			0		40,000,000
Average price of shares repurchased during period (in USD per share)					$ 79.18

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BUSINESS SEGMENT INFORMATION (Detail)	3 Months Ended		6 Months Ended
	Jun. 30, 2019 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2019 USD ($) Segment	Jun. 30, 2018 USD ($)	Dec. 31, 2018 USD ($)
Segment Reporting [Abstract]
Number of reporting segments | Segment			3
Segment Reporting Information [Line Items]
Oil and gas production revenues	$ 1,598,000,000	$ 1,936,000,000	$ 3,252,000,000	$ 3,669,000,000
Lease operating expenses	389,000,000	356,000,000	754,000,000	705,000,000
Gathering, processing, and transmission	76,000,000	82,000,000	164,000,000	168,000,000
Taxes other than income	46,000,000	49,000,000	97,000,000	104,000,000
Exploration	95,000,000	76,000,000	164,000,000	152,000,000
Depreciation, depletion, and amortization	602,000,000	608,000,000	1,248,000,000	1,161,000,000
Asset retirement obligation accretion	26,000,000	27,000,000	53,000,000	54,000,000
Impairments	240,000,000	0	240,000,000	0
Operating expenses	1,474,000,000	1,198,000,000	2,720,000,000	2,344,000,000
Operating Income (Loss)	124,000,000	738,000,000	532,000,000	1,325,000,000
Other Income (Expense):
Gain on divestitures	17,000,000	2,000,000	20,000,000	9,000,000
Derivative instrument losses, net	(8,000,000)	(25,000,000)	(38,000,000)	(23,000,000)
Other	(4,000,000)	16,000,000	4,000,000	21,000,000
General and administrative	(102,000,000)	(117,000,000)	(225,000,000)	(231,000,000)
Transaction, reorganization, and separation	(6,000,000)	(12,000,000)	(10,000,000)	(12,000,000)
Financing costs, net	(173,000,000)	(94,000,000)	(270,000,000)	(193,000,000)
NET INCOME (LOSS) BEFORE INCOME TAXES	(152,000,000)	508,000,000	13,000,000	896,000,000
Revenues from non-customers	120,000,000	181,000,000	240,000,000	336,000,000
Total Assets	21,806,000,000	21,910,000,000	21,806,000,000	21,910,000,000	$ 21,582,000,000
Impairments	240,000,000	0	240,000,000	0
Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil and gas production revenues	596,000,000	742,000,000	1,195,000,000	1,402,000,000
Lease operating expenses	132,000,000	106,000,000	250,000,000	204,000,000
Gathering, processing, and transmission	10,000,000	11,000,000	22,000,000	23,000,000
Taxes other than income	0	0	0	0
Exploration	30,000,000	32,000,000	62,000,000	60,000,000
Depreciation, depletion, and amortization	174,000,000	192,000,000	361,000,000	378,000,000
Asset retirement obligation accretion	0	0	0	0
Impairments	0	0	0	0
Operating expenses	346,000,000	341,000,000	695,000,000	665,000,000
Operating Income (Loss)	250,000,000	401,000,000	500,000,000	737,000,000
Other Income (Expense):
Total Assets	4,035,000,000	4,471,000,000	4,035,000,000	4,471,000,000
Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil and gas production revenues	360,000,000	352,000,000	698,000,000	651,000,000
Lease operating expenses	92,000,000	78,000,000	164,000,000	172,000,000
Gathering, processing, and transmission	11,000,000	10,000,000	23,000,000	20,000,000
Taxes other than income	0	0	0	0
Exploration	1,000,000	3,000,000	2,000,000	17,000,000
Depreciation, depletion, and amortization	99,000,000	96,000,000	198,000,000	191,000,000
Asset retirement obligation accretion	18,000,000	19,000,000	37,000,000	37,000,000
Impairments	0	0	0	0
Operating expenses	221,000,000	206,000,000	424,000,000	437,000,000
Operating Income (Loss)	139,000,000	146,000,000	274,000,000	214,000,000
Other Income (Expense):
Total Assets	2,568,000,000	3,148,000,000	2,568,000,000	3,148,000,000
Impairments	2,000,000		4,000,000	37,000,000
Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil and gas production revenues	642,000,000	842,000,000	1,359,000,000	1,616,000,000
Lease operating expenses	166,000,000	172,000,000	342,000,000	329,000,000
Gathering, processing, and transmission	64,000,000	62,000,000	145,000,000	127,000,000
Taxes other than income	42,000,000	47,000,000	91,000,000	99,000,000
Exploration	59,000,000	40,000,000	92,000,000	73,000,000
Depreciation, depletion, and amortization	320,000,000	315,000,000	673,000,000	584,000,000
Asset retirement obligation accretion	8,000,000	8,000,000	15,000,000	16,000,000
Impairments	240,000,000	0	240,000,000	0
Operating expenses	899,000,000	644,000,000	1,598,000,000	1,228,000,000
Operating Income (Loss)	(257,000,000)	198,000,000	(239,000,000)	388,000,000
Other Income (Expense):
Total Assets	12,710,000,000	13,311,000,000	12,710,000,000	13,311,000,000
Impairments	277,000,000	21,000,000	298,000,000
Operating Segments | Altus Midstream
Segment Reporting Information [Line Items]
Oil and gas production revenues	0	0	0	0
Lease operating expenses	0	0	0	0
Gathering, processing, and transmission	14,000,000	11,000,000	30,000,000	22,000,000
Taxes other than income	4,000,000	2,000,000	6,000,000	5,000,000
Exploration	0	0	0	0
Depreciation, depletion, and amortization	9,000,000	5,000,000	16,000,000	8,000,000
Asset retirement obligation accretion	0	0	1,000,000	1,000,000
Impairments	0	0	0	0
Operating expenses	27,000,000	18,000,000	53,000,000	36,000,000
Operating Income (Loss)	(3,000,000)	(6,000,000)	5,000,000	(12,000,000)
Other Income (Expense):
Total Assets	2,434,000,000	939,000,000	2,434,000,000	939,000,000
Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil and gas production revenues	(24,000,000)	(12,000,000)	(58,000,000)	(24,000,000)
Lease operating expenses	(1,000,000)	0	(2,000,000)	0
Gathering, processing, and transmission	(23,000,000)	(12,000,000)	(56,000,000)	(24,000,000)
Taxes other than income	0	0	0	0
Exploration	5,000,000	1,000,000	8,000,000	2,000,000
Depreciation, depletion, and amortization	0	0	0	0
Asset retirement obligation accretion	0	0	0	0
Impairments	0	0	0	0
Operating expenses	(19,000,000)	(11,000,000)	(50,000,000)	(22,000,000)
Operating Income (Loss)	(5,000,000)	(1,000,000)	(8,000,000)	(2,000,000)
Other Income (Expense):
Total Assets	59,000,000	41,000,000	59,000,000	41,000,000
Intersegment Eliminations & Other | Egypt
Segment Reporting Information [Line Items]
Oil and gas production revenues	0	0	0	0
Intersegment Eliminations & Other | North Sea
Segment Reporting Information [Line Items]
Oil and gas production revenues	0	0	0	0
Intersegment Eliminations & Other | U.S.
Segment Reporting Information [Line Items]
Oil and gas production revenues	0	0	0	0
Intersegment Eliminations & Other | Altus Midstream
Segment Reporting Information [Line Items]
Oil and gas production revenues	24,000,000	12,000,000	58,000,000	24,000,000
Oil and Gas, Purchased
Segment Reporting Information [Line Items]
Oil and gas production revenues	18,000,000	98,000,000	42,000,000	202,000,000
Gathering, processing, and transmission	15,000,000	95,000,000	37,000,000	199,000,000
Oil
Segment Reporting Information [Line Items]
Oil and gas production revenues	1,397,000,000	1,576,000,000	2,707,000,000	2,969,000,000
Other Income (Expense):
Revenues from non-customers	111,000,000	165,000,000	218,000,000	304,000,000
Oil | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil and gas production revenues	523,000,000	649,000,000	1,037,000,000	1,218,000,000
Oil | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil and gas production revenues	337,000,000	320,000,000	637,000,000	591,000,000
Oil | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil and gas production revenues	537,000,000	607,000,000	1,033,000,000	1,160,000,000
Oil | Operating Segments | Altus Midstream
Segment Reporting Information [Line Items]
Oil and gas production revenues	0	0	0	0
Oil | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil and gas production revenues	0	0	0	0
Natural Gas
Segment Reporting Information [Line Items]
Oil and gas production revenues	118,000,000	212,000,000	354,000,000	434,000,000
Other Income (Expense):
Revenues from non-customers	9,000,000	15,000,000	21,000,000	30,000,000
Natural Gas | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil and gas production revenues	70,000,000	89,000,000	151,000,000	177,000,000
Natural Gas | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil and gas production revenues	18,000,000	27,000,000	50,000,000	51,000,000
Natural Gas | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil and gas production revenues	30,000,000	96,000,000	153,000,000	206,000,000
Natural Gas | Operating Segments | Altus Midstream
Segment Reporting Information [Line Items]
Oil and gas production revenues	0	0	0	0
Natural Gas | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil and gas production revenues	0	0	0	0
Natural Gas liquids
Segment Reporting Information [Line Items]
Oil and gas production revenues	83,000,000	148,000,000	191,000,000	266,000,000
Other Income (Expense):
Revenues from non-customers	0	1,000,000	1,000,000	2,000,000
Natural Gas liquids | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil and gas production revenues	3,000,000	4,000,000	7,000,000	7,000,000
Natural Gas liquids | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil and gas production revenues	5,000,000	5,000,000	11,000,000	9,000,000
Natural Gas liquids | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil and gas production revenues	75,000,000	139,000,000	173,000,000	250,000,000
Natural Gas liquids | Operating Segments | Altus Midstream
Segment Reporting Information [Line Items]
Oil and gas production revenues	0	0	0	0
Natural Gas liquids | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil and gas production revenues	$ 0	$ 0	$ 0	$ 0