Edgar Filing: APACHE CORP

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________________________________

FORM 10-Q

________________________________________________________________

(Mark One)



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

For the quarterly period ended June 30, 2018



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

For the transition period from to

Commission File Number 1-4300

APACHE CORPORATION

(exact name of registrant as specified in its charter)

_______________________________________________________________________



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

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

(Address of principal executive offices)

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

__________________________________________________________________________________

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

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

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



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

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

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



Number of shares of registrant’s common stock outstanding as of July 31, 2018	382,485,953



	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	4
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	5
2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	19
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	30
4.	CONTROLS AND PROCEDURES	31
	PART II - OTHER INFORMATION
1.	LEGAL PROCEEDINGS	32
1A.	RISK FACTORS	32
2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	32
3.	DEFAULTS UPON SENIOR SECURITIES	32
4.	MINE SAFETY DISCLOSURES	32
5.	OTHER INFORMATION	32
6.	EXHIBITS	33

Forward-Looking Statements and Risk

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs, and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information that was used to prepare our estimate of proved reserves as of December 31, 2017, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:


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


•	our commodity hedging arrangements;


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


•	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 2018 earnings release, other factors disclosed under Part II, Item 1A—Risk Factors of this Quarterly Report on Form 10-Q, and other filings that we make with the Securities and Exchange Commission.

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

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

(Unaudited)



	For the Quarter Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(In millions, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues
Oil revenues	$	1,576		$	1,050		$	2,969		$	2,222
Natural gas revenues	212			233			434			488
Natural gas liquids revenues	148			63			266			148
	1,936			1,346			3,669			2,858
Gain (loss) on divestitures	2			(21		)	9			320
Other	(9		)	59			(2		)	84
	1,929			1,384			3,676			3,262
OPERATING EXPENSES:
Lease operating expenses	356			372			705			708
Gathering, transmission, and processing	82			48			168			105
Taxes other than income	49			29			104			71
Exploration	76			108			152			200
General and administrative	117			106			231			209
Transaction, reorganization, and separation	12			4			12			(6		)
Depreciation, depletion, and amortization:
Oil and gas property and equipment	573			536			1,091			1,074
Other assets	35			36			70			74
Asset retirement obligation accretion	27			37			54			73
Impairments	—			—			—			8
Financing costs, net	94			99			193			199
	1,421			1,375			2,780			2,715
NET INCOME BEFORE INCOME TAXES	508			9			896			547
Current income tax provision	249			126			447			314
Deferred income tax benefit	(10		)	(730		)	(26		)	(647		)
NET INCOME INCLUDING NONCONTROLLING INTEREST	269			613			475			880
Net income attributable to noncontrolling interest	74			41			135			95
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	195		$	572		$	340		$	785

NET INCOME PER COMMON SHARE:
Basic	$	0.51		$	1.50		$	0.89		$	2.06
Diluted	$	0.51		$	1.50		$	0.88		$	2.05
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	382			381			382			380
Diluted	385			383			384			383
DIVIDENDS DECLARED PER COMMON SHARE	$	0.25		$	0.25		$	0.50		$	0.50

The accompanying notes to consolidated financial statements

are an integral part of this statement.

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

(Unaudited)



	For the Six Months Ended June 30,
	2018			2017
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interest	$	475		$	880
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized derivative instrument gain, net	(104		)	(41		)
Gain on divestitures	(9		)	(320		)
Exploratory dry hole expense and unproved leasehold impairments	73			152
Depreciation, depletion, and amortization	1,161			1,148
Asset retirement obligation accretion	54			73
Impairments	—			8
Deferred income tax benefit	(26		)	(647		)
Other	107			80
Changes in operating assets and liabilities:
Receivables	(101		)	62
Inventories	(9		)	20
Drilling advances	30			(20		)
Deferred charges and other	69			(90		)
Accounts payable	46			(37		)
Accrued expenses	(45		)	(86		)
Deferred credits and noncurrent liabilities	7			24
NET CASH PROVIDED BY OPERATING ACTIVITIES	1,728			1,206

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(1,572		)	(883		)
Leasehold and property acquisitions	(38		)	(67		)
Additions to gas gathering, transmission, and processing facilities	(284		)	(274		)
Proceeds from sale of Midale and House Mountain	—			228
Proceeds from sale of oil and gas properties	13			483
Other, net	(33		)	(16		)
NET CASH USED IN INVESTING ACTIVITIES	(1,914		)	(529		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on fixed-rate debt	(150		)	(70		)
Distributions to noncontrolling interest	(155		)	(170		)
Dividends paid	(191		)	(190		)
Other	(14		)	43
NET CASH USED IN FINANCING ACTIVITIES	(510		)	(387		)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(696		)	290
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	1,668			1,377
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	972		$	1,667

SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	200		$	202
Income taxes paid, net of refunds	374			163

The accompanying notes to consolidated financial statements

are an integral part of this statement.

APACHE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)



	June 30, 2018			December 31, 2017
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	972		$	1,668
Receivables, net of allowance	1,446			1,345
Inventories	361			368
Drilling advances	177			207
Prepaid assets and other	183			137
	3,139			3,725
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of successful efforts accounting:
Proved properties	40,644			39,197
Unproved properties and properties under development	1,807			1,783
Gathering, transmission and processing facilities	1,619			1,376
Other	1,062			1,046
	45,132			43,402
Less: Accumulated depreciation, depletion, and amortization	(26,796		)	(25,643		)
	18,336			17,759
OTHER ASSETS:
Deferred charges and other	435			438
	$	21,910		$	21,922
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	682		$	641
Current debt	400			550
Other current liabilities (Note 5)	1,230			1,373
	2,312			2,564
LONG-TERM DEBT	7,937			7,934
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	518			545
Asset retirement obligation	1,845			1,792
Other	303			296
	2,666			2,633
COMMITMENTS AND CONTINGENCIES (Note 9)
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 415,627,712 and 414,125,879 shares issued, respectively	260			259
Paid-in capital	12,011			12,128
Accumulated deficit	(1,748		)	(2,088		)
Treasury stock, at cost, 33,168,561 and 33,171,015 shares, respectively	(2,887		)	(2,887		)
Accumulated other comprehensive income	4			4
APACHE SHAREHOLDERS’ EQUITY	7,640			7,416
Noncontrolling interest	1,355			1,375
TOTAL EQUITY	8,995			8,791
	$	21,910		$	21,922

The accompanying notes to consolidated financial statements

are an integral part of this statement.

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY

(Unaudited)



	Common Stock		Paid-In Capital			Accumulated Deficit			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			APACHE SHAREHOLDERS’ EQUITY			Noncontrolling Interest			TOTAL EQUITY
	(In millions)
BALANCE AT DECEMBER 31, 2016	$	258	$	12,364		$	(3,385	)	$	(2,887	)	$	(112	)	$	6,238		$	1,441		$	7,679
Net income	—		—			785			—			—			785			95			880
Distributions to noncontrolling interest	—		—			—			—			—			—			(170		)	(170		)
Common dividends ($0.50 per share)	—		(190		)	—			—			—			(190		)	—			(190		)
Other	1		72			(7		)	—			—			66			—			66
BALANCE AT JUNE 30, 2017	$	259	$	12,246		$	(2,607	)	$	(2,887	)	$	(112	)	$	6,899		$	1,366		$	8,265

BALANCE AT DECEMBER 31, 2017	$	259	$	12,128		$	(2,088	)	$	(2,887	)	$	4		$	7,416		$	1,375		$	8,791
Net income	—		—			340			—			—			340			135			475
Distributions to noncontrolling interest	—		—			—			—			—			—			(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

The accompanying notes to consolidated financial statements

are an integral part of this statement.

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

These consolidated financial statements have been prepared by Apache Corporation (Apache or the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited financial statements, with the exception of recently adopted accounting pronouncements discussed below. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, which contains a summary of the Company’s significant accounting policies and other disclosures.


1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of June 30, 2018, Apache’s significant accounting policies are consistent with those discussed in Note 1—Summary of Significant Accounting Policies of its consolidated financial statements contained in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, with the exception of Accounting Standards Update (ASU) 2014-09, “Revenue from Contracts with Customers (Topic 606)” (see “Revenue Recognition” section in this Note 1 below).

Use of Estimates

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

Fair Value Measurements

Certain assets and liabilities are reported at fair value on a recurring basis in Apache’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

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

Apache also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. For the second quarter and six-month periods ended June 30, 2018, the Company recorded no asset impairments in connection with fair value assessments.

The Company recorded no asset impairments in connection with fair value assessments in the second quarter of 2017. For the six-month period ended June 30, 2017, the Company recorded asset impairments in connection with fair value assessments totaling $8 million for a United Kingdom (U.K.) Petroleum Revenue Tax (PRT) decommissioning asset that is no longer expected to be realizable from future abandonment activities in the North Sea.

In 2016, the U.K. government enacted Finance Bill 2016, providing tax relief to exploration and production (E&P) companies operating in the U.K. North Sea. Under the enacted legislation, the U.K. PRT rate was reduced to zero from the previously enacted 35 percent rate in effect from January 1, 2016. PRT expense ceased prospectively from that date. During the first quarter of 2017, the Company fully impaired the aggregate remaining value of the recoverable PRT decommissioning asset of $8 million that would have been realized from future abandonment activities. The recoverable value of the PRT decommissioning asset was estimated using the income approach. The expected future cash flows used in the determination were based on anticipated spending and timing of planned future abandonment activities for applicable fields, considering all available information at the date of review. Apache has classified this fair value measurement as Level 3 in the fair value hierarchy.

Oil and Gas Property

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

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

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

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

When circumstances indicate that proved oil and gas properties may be impaired, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on Apache’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. If applicable, the Company utilizes prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a discount rate believed to be consistent with those applied by market participants. Apache has classified these fair value measurements as Level 3 in the fair value hierarchy.

The following table represents non-cash impairments of the carrying value of the Company’s proved and unproved property and equipment for the second quarters and first six months of 2018 and 2017:



	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2018		2017		2018		2017
	(In millions)
Oil and Gas Property:
Proved	$	—	$	—	$	—	$	—
Unproved	21		39		37		54

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

Revenue Recognition

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

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

Apache markets its own United States (U.S.) natural gas and crude oil production based on market-priced contracts. Typically, these contracts are adjusted for quality, transportation, and other market-reflective differentials. Since the Company’s production may fluctuate as a result of operational issues, it is occasionally necessary to purchase third-party oil and gas to fulfill sales obligations and commitments. Sales proceeds related to third-party purchased oil and gas are determined to be revenue from a customer. Proceeds for these volumes, which offset the associated purchase costs, totaled $98 million and $202 million for the second quarter and first six months of 2018, respectively. Proceeds and costs are both recorded as “Other” under “Revenues and Other” in the statement of consolidated operations.

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

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

For the second quarter of 2018, revenues from customers and revenues from non-customers were $1.9 billion and $181 million, respectively. For the first six months of 2018, revenues from customers and revenues from non-customers were $3.5 billion and $336 million, respectively.

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

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

Practical Expedients and Exemptions

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

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

New Pronouncements Issued But Not Yet Adopted

In February 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-02, “Leases (Topic 842),” requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous GAAP. The guidance is effective for fiscal years beginning after December 15, 2018. Early adoption is permitted; however, the Company does not intend to early adopt. In July 2018, the FASB issued ASU 2018-11, which adds a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the consolidated financial statements. Under this transition option, comparative reporting would not be required and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. In the normal course of business, the Company enters into various lease agreements for real estate, aircraft, and equipment related to its exploration and development activities that are currently accounted for as operating leases. To track these lease arrangements and facilitate compliance with this ASU, the Company is in the process of implementing a third-party lease accounting software solution and designing processes and internal controls. The Company continues to evaluate contracts, train departments affected by the standard, and monitor updates to the standard to determine the impact this ASU will have on its consolidated financial statements. At this time, the Company cannot reasonably estimate the financial impact this will have on its consolidated financial statements; however, the Company believes adoption and implementation of this ASU will significantly impact its balance sheet, resulting in an increase in both assets and liabilities relating to its leasing activities.


2.	ACQUISITIONS AND DIVESTITURES

2018 Activity

Divestitures

During the first six months of 2018, Apache completed the sale of certain non-core assets, primarily in the Permian region, in multiple transactions for cash proceeds of $13 million. The Company recognized gains of approximately $9 million during the first six months of 2018 upon the closing of these transactions.

Leasehold and Property Acquisitions

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.

2017 Activity

Canada Divestitures

On June 30, 2017, Apache completed the sale of its Canadian assets at Midale and House Mountain, located in Saskatchewan and Alberta, for aggregate cash proceeds of approximately $228 million. The Company recognized a $52 million loss during the second quarter of 2017 in association with this sale. The Company completed the sale and complete exit of its remaining Canadian operations in the third quarter of 2017.

U.S. Divestitures

During the first six months of 2017, Apache completed the sale of certain non-core assets, primarily in the Permian and Midcontinent/Gulf Coast regions, in multiple transactions for cash proceeds of $522 million, subject to customary closing adjustments. A refundable deposit of $40 million was received in the fourth quarter of 2016 in connection with certain of these transactions. The Company recognized gains of approximately $372 million during the first six months of 2017 in connection with these transactions.

Leasehold and Property Acquisitions

During the second quarter and first six months of 2017, Apache completed $18 million and $67 million, respectively, of leasehold and property acquisitions primarily in its U.S. onshore regions.

3. CAPITALIZED EXPLORATORY WELL COSTS

The Company’s capitalized exploratory well costs were $389 million and $350 million at June 30, 2018 and December 31, 2017, respectively. The increase is primarily attributable to additional drilling activities during the period, partially offset by successful transfers and dry hole write-offs. No suspended exploratory well costs previously capitalized for greater than one year at December 31, 2017 were charged to dry hole expense during the six months ended June 30, 2018. Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether reserves can be attributed to these projects.

4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production. Apache manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production. The Company utilizes various types of derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. Apache has elected not to designate any of its derivative contracts as cash flow hedges.

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, 2018, Apache had derivative positions with 15 counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, Apache may not realize the benefit of some of its derivative instruments resulting from lower commodity prices.

Derivative Instruments

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



		Put Options⁽¹⁾
Production Period	Settlement Index	Mbbls	Weighted Average Strike Price
July—December 2018	Dated Brent	7,360	$56.00
July—December 2018	NYMEX WTI	5,520	$53.00


(1)	The remaining unamortized premium paid as of June 30, 2018, was $25 million.

Collars

Call Options⁽²⁾

Production Period

Settlement Index

Mbbls

Weighted Average Floor Price

Weighted Average Ceiling Price

Mbbls

Strike Price

July—December 2018

NYMEX WTI

3,404

$45.00

$57.00

3,404

$60.03


(2)	The remaining unamortized premium paid as of June 30, 2018, was $5 million.

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



Production Period	Settlement Index	Mbbls	Weighted Average Price Differential
October—December 2018	Midland-WTI/Cushing-WTI	1,380	$(9.23)
January—September 2019	Midland-WTI/Cushing-WTI	4,095	$(9.23)
October—December 2019	Midland-WTI/Cushing-WTI	1,380	$(3.72)

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



		Fixed-Price Swaps
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Fixed Price
July—December 2018	NYMEX Henry Hub	33,580	$2.96

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



Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential
July—December 2018	NYMEX Henry Hub/Waha	33,120	$(0.53)
October—December 2018	NYMEX Henry Hub/Waha	1,380	$(0.51)
January—March 2019	NYMEX Henry Hub/Waha	1,350	$(0.54)
January—June 2019	NYMEX Henry Hub/Waha	32,580	$(0.53)
January—December 2019	NYMEX Henry Hub/Waha	14,600	$(0.45)

Fair Value Measurements

Apache’s commodity derivative instruments consist of variable-to-fixed price commodity swaps, options, and collars. The fair values of the Company’s derivatives are not actively quoted in the open market. The Company uses a market approach to estimate the fair values of its derivative instruments on a recurring basis, utilizing commodity futures pricing for the underlying commodities provided by a reputable third party, a Level 2 fair value measurement.

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:



	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting⁽¹⁾			Carrying Amount
	(In millions)
June 30, 2018
Assets:
Commodity Derivative Instruments	$	—	$	124	$	—	$	124	$	(46	)	$	78
Liabilities:
Commodity Derivative Instruments	—		50		—		50		(46		)	4
December 31, 2017
Assets:
Commodity Derivative Instruments	$	—	$	67	$	—	$	67	$	(43	)	$	24
Liabilities:
Commodity Derivative Instruments	—		107		—		107		(43		)	64


(1)	The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.

All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:



	June 30, 2018		December 31, 2017
	(In millions)
Current Assets: Prepaid assets and other	$	74	$	8
Other Assets: Deferred charges and other	4		16
Total Assets	$	78	$	24

Current Liabilities: Other current liabilities	$	2	$	64
Noncurrent Liabilities: Other	2		—
Total Liabilities	$	4	$	64

Derivative Activity Recorded in the Statement of Consolidated Operations

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



	For the Quarter Ended June 30,					For the Six Months Ended June 30,
	2018			2017		2018			2017
	(In millions)
Realized loss:
Derivative settlements	$	(75	)	$	—	$	(117	)	$	—
Amortization of call and put premium	(5		)	—		(10		)	—
Unrealized gain	55			41		104			41
Derivative instrument gain (losses), net	$	(25	)	$	41	$	(23	)	$	41

Derivative instrument gains and losses are recorded in “Other” 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 is reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument gain, net” in “Adjustments to reconcile net income to net cash provided by operating activities.”


5.	OTHER CURRENT LIABILITIES

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



	June 30, 2018		December 31, 2017
	(In millions)
Accrued operating expenses	$	76	$	72
Accrued exploration and development	603		680
Accrued gathering, transmission, and processing	70		122
Accrued compensation and benefits	90		115
Accrued interest	141		145
Accrued income taxes	110		55
Current asset retirement obligation	38		43
Other	102		141
Total other current liabilities	$	1,230	$	1,373


6.	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, 2018:



	(In millions)
Asset retirement obligation at December 31, 2017	$	1,835
Liabilities incurred	18
Liabilities settled	(24		)
Accretion expense	54
Asset retirement obligation at June 30, 2018	1,883
Less current portion	(38		)
Asset retirement obligation, long-term	$	1,845


7.	INCOME TAXES

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

During the second quarter of 2018, Apache’s effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets. During the second quarter of 2017, Apache’s effective income tax rate was primarily impacted by the decrease in deferred taxes associated with its investments in foreign subsidiaries, gains on the sale of oil and gas properties and an increase in the amount of valuation allowance on Canadian deferred tax assets.

Apache’s 2018 year-to-date effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets. Apache’s 2017 year-to-date effective income tax rate was primarily impacted by the decrease in deferred taxes associated with its investments in foreign subsidiaries, gains on the sale of oil and gas properties, non-cash impairments of the Company’s PRT decommissioning asset, and an increase in the amount of valuation allowance on Canadian deferred tax assets.

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

Apache and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. The Company is currently under IRS audit for the 2014-2016 tax years and is also under audit in various states and foreign jurisdictions as part of its normal course of business.


8.	DEBT AND FINANCING COSTS

The following table presents the carrying amounts and estimated fair values of the Company’s outstanding debt as of June 30, 2018 and December 31, 2017:



	June 30, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Commercial paper and committed bank facilities	$	—	$	—	$	—	$	—
Notes and debentures	8,337		8,507		8,484		9,244
Total Debt	$	8,337	$	8,507	$	8,484	$	9,244

The Company’s debt is recorded at the carrying amount, net of related unamortized discount and deferred loan costs, on its consolidated balance sheet. When recorded, the carrying amount of the Company’s commercial paper, committed bank facilities, and uncommitted bank lines approximates fair value because the interest rates are variable and reflective of market rates. Apache uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

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



	June 30, 2018			December 31, 2017
	(In millions)
Debt before unamortized discount and deferred loan costs	$	8,430		$	8,580
Unamortized discount	(46		)	(47		)
Deferred loan costs	(47		)	(49		)
Total debt	8,337			8,484
Current maturities	(400		)	(550		)
Long-term debt	$	7,937		$	7,934

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

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

The Company’s $3.5 billion commercial paper program, which is subject to market availability, facilitates Apache borrowing funds for up to 270 days at competitive interest rates. As of June 30, 2018, the Company had no commercial paper outstanding.

Financing Costs, Net

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



	For the Quarter Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(In millions)
Interest expense	$	110		$	115		$	222		$	231
Amortization of deferred loan costs	1			2			6			4
Capitalized interest	(13		)	(13		)	(25		)	(27		)
Loss on extinguishment of debt	—			—			—			1
Interest income	(4		)	(5		)	(10		)	(10		)
Financing costs, net	$	94		$	99		$	193		$	199


9.	COMMITMENTS AND CONTINGENCIES

Legal Matters

Apache is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls. As of June 30, 2018, the Company has an accrued liability of approximately $35 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. Apache’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to Apache’s financial position, results of operations, or liquidity after consideration of recorded accruals. For material matters that Apache believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.

For additional information on each of the Legal Matters described below, please see Note 10—Commitments and Contingencies to the consolidated financial statements contained in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017.

Argentine Environmental Claims and Argentina Tariff

No material change in the status of the YPF Sociedad Anónima and Pioneer Natural Resources Company indemnities matters has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017.

Louisiana Restoration

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

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

No other material change in the status of these matters has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017.

Apollo Exploration Lawsuit

In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and areas of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The Court granted motions filed by Apache reducing the plaintiffs’ alleged damages to an amount that is not material to the Company. Apache believes that plaintiffs’ claims lack merit and will vigorously oppose the claims. No other material change in the status of these matters has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017.

Australian Operations Divestiture Dispute

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

California Litigation

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

Environmental Matters

As of June 30, 2018, the Company had an undiscounted reserve for environmental remediation of approximately $4 million. The Company is not aware of any environmental claims existing as of June 30, 2018, that have not been provided for or that would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.


10.	CAPITAL STOCK

Net Income per Common Share

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



	For the Quarter Ended June 30,
	2018					2017
	Income		Shares	Per Share		Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	195	382	$	0.51	$	572	381	$	1.50
Effect of Dilutive Securities:
Stock options and other	$	—	3	$	—	$	—	2	$	—
Diluted:
Income attributable to common stock	$	195	385	$	0.51	$	572	383	$	1.50



	For the Six Months Ended June 30,
	2018						2017
	Income		Shares	Per Share			Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	340	382	$	0.89		$	785	380	$	2.06
Effect of Dilutive Securities:
Stock options and other	$	—	2	$	(0.01	)	$	—	3	$	(0.01	)
Diluted:
Income attributable to common stock	$	340	384	$	0.88		$	785	383	$	2.05

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 5.9 million and 8.5 million for the quarters ended June 30, 2018 and 2017, respectively, and 6.4 million and 8.6 million for the six months ended June 30, 2018 and 2017, respectively.

Common Stock Dividends

For the quarters ended June 30, 2018 and 2017, Apache paid $96 million and $95 million, respectively, in dividends on its common stock. For the six months ended June 30, 2018 and 2017, the Company paid $191 million and $190 million, respectively.

Stock Repurchase Program

Apache’s Board of Directors has authorized the purchase of up to 40 million shares of the Company’s common stock. Shares may be purchased either in the open market or through privately negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through June 30, 2018, had repurchased a total of 32.2 million shares at an average price of $88.96 per share. The Company is not obligated to acquire any specific number of shares and has not purchased any shares during 2018.


11.	BUSINESS SEGMENT INFORMATION

Apache is engaged in a single line of business. Both domestically and internationally, the Company explores for, develops, and produces natural gas, crude oil, and natural gas liquids. At June 30, 2018, the Company had production in three reporting segments: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). Apache also has exploration interests in Suriname that may, over time, result in a reportable discovery and development opportunity. Financial information for each area is presented below:



	United States		Canada⁽¹⁾		Egypt^(2,3)		North Sea		Other International			Total
	(In millions)
For the Quarter Ended June 30, 2018
Oil revenues	$	607	$	—	$	649	$	320	$	—		$	1,576
Natural gas revenues	96		—		89		27		—			212
Natural gas liquids revenues	139		—		4		5		—			148
Total Oil and Gas Production Revenues	$	842	$	—	$	742	$	352	$	—		$	1,936
Operating Income (Loss)⁽⁴⁾	$	192	$	—	$	401	$	146	$	(1	)	$	738
Other Income (Expense):
Gain on divestitures, net												2
Other⁽⁵⁾												(9		)
General and administrative												(117		)
Transaction, reorganization, and separation												(12		)
Financing costs, net												(94		)
Income Before Income Taxes												$	508

For the Six Months Ended June 30, 2018
Oil revenues	$	1,160	$	—	$	1,218	$	591	$	—		$	2,969
Natural gas revenues	206		—		177		51		—			434
Natural gas liquids revenues	250		—		7		9		—			266
Total Oil and Gas Production Revenues	$	1,616	$	—	$	1,402	$	651	$	—		$	3,669
Operating Income (Loss)⁽⁴⁾	$	376	$	—	$	737	$	214	$	(2	)	$	1,325
Other Income (Expense):
Gain on divestitures, net												9
Other⁽⁵⁾												(2		)
General and administrative												(231		)
Transaction, reorganization, and separation												(12		)
Financing costs, net												(193		)
Income Before Income Taxes												$	896
Total Assets	$	14,250	$	—	$	4,471	$	3,148	$	41		$	21,910



	United States			Canada⁽¹⁾			Egypt^(2,3)		North Sea		Other International			Total
	(In millions)
For the Quarter Ended June 30, 2017
Oil revenues	$	355		$	47		$	423	$	225	$	—		$	1,050
Natural gas revenues	84			40			95		14		—			233
Natural gas liquids revenues	52			6			3		2		—			63
Total Oil and Gas Production Revenues	$	491		$	93		$	521	$	241	$	—		$	1,346
Operating Income (Loss)⁽⁶⁾	$	(17	)	$	(18	)	$	213	$	4	$	(2	)	$	180
Other Income (Expense):
Loss on divestitures, net														(21		)
Other														59
General and administrative														(106		)
Transaction, reorganization, and separation														(4		)
Financing costs, net														(99		)
Income Before Income Taxes														$	9

For the Six Months Ended June 30, 2017
Oil revenues	$	752		$	96		$	909	$	465	$	—		$	2,222
Natural gas revenues	169			85			197		37		—			488
Natural gas liquids revenues	122			14			6		6		—			148
Total Oil and Gas Production Revenues	$	1,043		$	195		$	1,112	$	508	$	—		$	2,858
Operating Income (Loss)⁽⁶⁾	$	43		$	(31	)	$	514	$	42	$	(23	)	$	545
Other Income (Expense):
Gain on divestitures, net														320
Other														84
General and administrative														(209		)
Transaction, reorganization, and separation														6
Financing costs, net														(199		)
Income Before Income Taxes														$	547
Total Assets	$	12,530		$	1,476		$	4,778	$	3,772	$	46		$	22,602


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


(2)	Includes a noncontrolling interest in Egypt.


(3)	Includes revenue from non-customer of $165 million, $15 million, and $1 million for oil, natural gas, and natural gas liquids, respectively, for the second quarter of 2018, and $304 million, $30 million, and $2 million, for oil, natural gas, and natural gas liquids, respectively, for the first six months of 2018.

(4)

Operating income (loss) consists of oil and gas production revenues less lease operating expenses, gathering, transmission, and processing costs, taxes other than income, exploration costs, depreciation, depletion, and amortization, asset retirement obligation accretion, and impairments. The operating income of U.S. includes leasehold impairments totaling $21 million for the second quarter of 2018. The operating income of U.S. includes leasehold impairments totaling $37 million for the first six months of 2018.


(5)	Included in Other are sales proceeds related to U.S. third-party purchased oil and gas totaling $98 million and $202 million for the second quarter and first six months of 2018, respectively, which are determined to be revenue from customers.


(6)	The operating income (loss) of U.S. and Canada includes leasehold impairments totaling $38 million and $1 million, respectively, for the second quarter of 2017. The operating income (loss) of U.S., Canada and North Sea includes leasehold and other asset impairments totaling $52 million, $2 million, and $8 million, respectively, for the first six months of 2017.

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

The following discussion relates to Apache Corporation and its consolidated subsidiaries and should be read in conjunction with the Company’s consolidated financial statements and accompanying notes included under Part I, Item 1, “Financial Statements” of this Quarterly Report on Form 10-Q, as well as the Company’s consolidated financial statements, accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017.

Overview

Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. Apache currently has exploration and production operations in three geographic areas: the United States (U.S.), Egypt, and offshore the United Kingdom (U.K.) in the North Sea (North Sea). Apache also has exploration interests in Suriname that may, over time, result in a reportable discovery and development opportunity. In the third quarter of 2017, Apache completed the sale of its Canadian operations.

Apache reported second quarter net income of $195 million, or $0.51 per common share, compared to net income of $572 million, or $1.50 per common share, in the second quarter of 2017. The decrease in net income compared to the prior-year quarter is primarily the result of a $674 million deferred income tax benefit recorded in the second quarter of 2017 associated with the sale of Apache’s Canadian operations. Income before taxes increased $499 million between the periods. Daily production in the second quarter of 2018 averaged 464 Mboe/d, an increase of 1 percent from the comparative prior-year quarter. Excluding Canada, Apache’s daily production increased 13 percent driven by the continued development of the Company’s Alpine High field and infrastructure.

The Company generated $1.7 billion in cash from operating activities during the first six months of 2018, a 43 percent increase from the comparable prior-year period driven by higher revenues from increased Permian production and stronger realized commodity prices. Apache ended the quarter with $1.0 billion of cash, while continuing its midstream infrastructure build-out and paying down $150 million of debt.

During the first half of 2018, Apache invested approximately $1.5 billion in its upstream operations, excluding noncontrolling interest, and $243 million in Alpine High midstream. The Company anticipates maintaining this investment pace in the second half of the year, bringing full-year 2018 capital investment outlook to approximately $3.4 billion, an increase of $400 million from prior guidance. The majority of this incremental capital is being directed to the Permian, where Apache is increasing investment to align and optimize its drilling and completion program.

Realized oil prices have been considerably higher than budgeted this year, particularly Dated Brent, which has provided the cash flow to reinvest in the Company’s core assets and generate high rates of return without a material impact on its balance sheet.

Operating Highlights

Key operational highlights for the quarter include:

United States


•	U.S. onshore equivalent production increased 33 percent from the second quarter of 2017, a reflection of the success of the Midland Basin drilling program and the commencement and continued production ramp-up of the Company’s Alpine High development.


•	Second-quarter equivalent production from the Permian region, which accounts for 79 percent of Apache’s total U.S. production, increased 39 percent from the second quarter of 2017, driven by the Alpine High discovery and strong performance in the Midland Basin. Crude oil production in the region increased 25 percent between the comparative quarters.


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


◦	First production from the Alpine High play was achieved in early May 2017. Net production for the second quarter of 2018 averaged approximately 32.1 Mboe/d.


◦	Development continues to ramp-up steadily as the Company drills more development wells in the overall mix of its drilling program at Alpine High. Apache is now conducting key spacing and pattern tests in addition to its ongoing retention drilling program.


◦	During the second quarter of 2018, Apache invested $123 million in Alpine High infrastructure, with development ongoing. Inception-to-date investment in Alpine High infrastructure as of quarter-end was $949 million.


◦	The Company is in the process of evaluating opportunities for monetizing its Alpine High midstream assets, including options for minority interests in transportation projects from the Permian Basin to the Gulf Coast.

International


•	The Egypt region averaged 13 rigs and drilled 35 gross wells during the second quarter of 2018. Net equivalent production decreased 5 percent from the second quarter 2017 despite an increase of 2 percent in gross production, a result of the impact of higher Brent oil prices on cost recovery volumes as a function of the Company’s production sharing contracts.


•	In Egypt, Apache completed the acquisition of 650,000 additional gross acres in the East Bahariya area. The contract provides a 6-year term for exploration on the concession, which is located close to existing production. Apache plans to commence exploration drilling in the third quarter of 2018.


•	The North Sea region average daily production remained relatively flat compared with the second quarter of 2017 primarily as a result of production from new wells offsetting natural decline.

Results of Operations

Oil and Gas Revenues

The table below presents the second-quarter and year-to-date 2018 and 2017 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,
	2018				2017				2018				2017
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution
	($ in millions)
Total Oil Revenues:
United States	$	607	39	%	$	355	34	%	$	1,160	39	%	$	752	34	%
Canada	—		—		47		4	%	—		—		96		4	%
North America	607		39	%	402		38	%	1,160		39	%	848		38	%
Egypt⁽¹⁾	649		41	%	423		40	%	1,218		41	%	909		41	%
North Sea	320		20	%	225		22	%	591		20	%	465		21	%
International ⁽¹⁾	969		61	%	648		62	%	1,809		61	%	1,374		62	%
Total ⁽¹⁾	$	1,576	100	%	$	1,050	100	%	$	2,969	100	%	$	2,222	100	%
Total Natural Gas Revenues:
United States	$	96	45	%	$	84	36	%	$	206	47	%	$	169	35	%
Canada	—		—		40		17	%	—		—		85		17	%
North America	96		45	%	124		53	%	206		47	%	254		52	%
Egypt ⁽¹⁾	89		42	%	95		41	%	177		41	%	197		40	%
North Sea	27		13	%	14		6	%	51		12	%	37		8	%
International ⁽¹⁾	116		55	%	109		47	%	228		53	%	234		48	%
Total ⁽¹⁾	$	212	100	%	$	233	100	%	$	434	100	%	$	488	100	%
Total Natural Gas Liquids (NGL) Revenues:
United States	$	139	94	%	$	52	83	%	$	250	94	%	$	122	82	%
Canada	—		—		6		9	%	—		—		14		10	%
North America	139		94	%	58		92	%	250		94	%	136		92	%
Egypt ⁽¹⁾	4		3	%	3		5	%	7		3	%	6		4	%
North Sea	5		3	%	2		3	%	9		3	%	6		4	%
International ⁽¹⁾	9		6	%	5		8	%	16		6	%	12		8	%
Total ⁽¹⁾	$	148	100	%	$	63	100	%	$	266	100	%	$	148	100	%
Total Oil and Gas Revenues:
United States	$	842	43	%	$	491	36	%	$	1,616	44	%	$	1,043	36	%
Canada	—		—		93		7	%	—		—		195		7	%
North America	842		43	%	584		43	%	1,616		44	%	1,238		43	%
Egypt ⁽¹⁾	742		39	%	521		39	%	1,402		38	%	1,112		39	%
North Sea	352		18	%	241		18	%	651		18	%	508		18	%
International ⁽¹⁾	1,094		57	%	762		57	%	2,053		56	%	1,620		57	%
Total ⁽¹⁾	$	1,936	100	%	$	1,346	100	%	$	3,669	100	%	$	2,858	100	%


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

Production

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



	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2018	Increase (Decrease)		2017	2018	Increase (Decrease)		2017
Oil Volume – b/d
United States	105,163	22	%	86,071	102,470	16	%	88,386
Canada	—	NM		11,638	—	NM		11,647
North America	105,163	8	%	97,709	102,470	2	%	100,033
Egypt⁽¹⁾⁽²⁾	96,185	(1	)%	96,961	95,730	(4	)%	99,327
North Sea	46,150	(4	)%	48,091	46,249	(5	)%	48,933
International	142,335	(2	)%	145,052	141,979	(4	)%	148,260
Total	247,498	2	%	242,761	244,449	(2	)%	248,293
Natural Gas Volume – Mcf/d
United States	547,777	50	%	364,052	518,324	42	%	365,481
Canada	—	NM		205,408	—	NM		210,484
North America	547,777	(4	)%	569,460	518,324	(10	)%	575,965
Egypt⁽¹⁾⁽²⁾	340,991	(11	)%	383,296	342,438	(13	)%	395,179
North Sea	43,297	26	%	34,348	42,174	8	%	39,111
International	384,288	(8	)%	417,644	384,612	(11	)%	434,290
Total	932,065	(6	)%	987,104	902,936	(11	)%	1,010,255
NGL Volume – b/d
United States	59,036	26	%	47,029	55,182	16	%	47,511
Canada	—	NM		4,365	—	NM		4,592
North America	59,036	15	%	51,394	55,182	6	%	52,103
Egypt⁽¹⁾⁽²⁾	1,127	28	%	880	1,033	13	%	917
North Sea	1,104	49	%	741	1,135	19	%	955
International	2,231	38	%	1,621	2,168	16	%	1,872
Total	61,267	16	%	53,015	57,350	6	%	53,975
BOE per day⁽³⁾
United States	255,495	32	%	193,775	244,039	24	%	196,811
Canada	—	NM		50,238	—	NM		51,319
North America	255,495	5	%	244,013	244,039	(2	)%	248,130
Egypt⁽²⁾	154,144	(5	)%	161,724	153,836	(7	)%	166,107
North Sea⁽⁴⁾	54,470	—		54,556	54,413	(4	)%	56,407
International	208,614	(4	)%	216,280	208,249	(6	)%	222,514
Total	464,109	1	%	460,293	452,288	(4	)%	470,644


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



	For the Quarter Ended June 30,		For the Six Months Ended June 30,
	2018	2017	2018	2017
Oil (b/d)	206,296	195,293	204,264	194,559
Natural Gas (Mcf/d)	801,727	825,947	780,121	811,608
NGL (b/d)	1,719	1,545	1,598	1,509


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



	For the Quarter Ended June 30,		For the Six Months Ended June 30,
	2018	2017	2018	2017
Oil (b/d)	32,066	32,562	31,921	33,232
Natural Gas (Mcf/d)	113,846	128,696	114,377	132,197
NGL (b/d)	376	293	344	306


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


(4)	Average sales volumes from the North Sea for the second quarter of 2018 and 2017 were 56,516 boe/d and 57,905 boe/d, respectively, and 55,113 boe/d and 58,347 boe/d for the first six months of 2018 and 2017, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

NM — Not meaningful

Pricing

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



	For the Quarter Ended June 30,						For the Six Months Ended June 30,
	2018		Increase (Decrease)		2017		2018		Increase (Decrease)		2017
Average Oil Price - Per barrel
United States	$	63.27	40	%	$	45.18	$	62.54	33	%	$	46.99
Canada	—		NM		44.52		—		NM		45.70
North America	63.27		40	%	45.10		62.54		34	%	46.84
Egypt	74.14		55	%	47.98		70.26		39	%	50.57
North Sea	73.05		52	%	48.21		69.58		38	%	50.51
International	73.78		54	%	48.06		70.04		39	%	50.55
Total	69.35		48	%	46.89		66.90		36	%	49.06
Average Natural Gas Price - Per Mcf
United States	$	1.94	(23	)%	$	2.53	$	2.20	(14	)%	$	2.55
Canada	—		NM		2.14		—		NM		2.24
North America	1.94		(19	)%	2.39		2.20		(10	)%	2.44
Egypt	2.85		4	%	2.73		2.85		4	%	2.75
North Sea	6.82		50	%	4.54		6.71		27	%	5.27
International	3.29		14	%	2.88		3.27		10	%	2.98
Total	2.50		(4	)%	2.60		2.65		(1	)%	2.67
Average NGL Price - Per barrel
United States	$	26.03	112	%	$	12.26	$	25.10	77	%	$	14.21
Canada	—		NM		15.99		—		NM		16.53
North America	26.03		107	%	12.58		25.10		74	%	14.42
Egypt	40.80		31	%	31.11		38.72		8	%	35.74
North Sea	44.71		95	%	22.92		43.75		33	%	32.85
International	42.73		56	%	27.37		41.35		21	%	34.26
Total	26.64		104	%	13.03		25.72		70	%	15.10

NM — Not meaningful

Crude Oil Revenues Crude oil revenues for the second quarter of 2018 totaled $1.6 billion, a $526 million increase from the comparative 2017 quarter. A 48 percent increase in average realized prices increased second-quarter 2018 revenues by $504 million compared to the prior-year quarter, while 2 percent higher average daily production increased revenues by $22 million. Crude oil accounted for 81 percent of oil and gas production revenues and 53 percent of worldwide production in the second quarter of 2018. Crude oil prices realized in the second quarter of 2018 averaged $69.35 per barrel, compared with $46.89 per barrel in the comparative prior-year quarter.

Worldwide oil production increased 4.7 Mb/d to 247.5 Mb/d in the second quarter of 2018 from the comparative prior-year period, primarily a result of an increase in Apache’s Permian region on the success of the Midland and Delaware basin drilling programs.

Natural Gas Revenues Gas revenues for the second quarter of 2018 totaled $212 million, a $21 million decrease from the comparative 2017 quarter. A 4 percent decrease in average realized prices decreased second-quarter revenues by $9 million compared to the prior-year quarter, while 6 percent lower average daily production decreased revenues by $12 million. Natural gas accounted for 11 percent of Apache’s oil and gas production revenues and 33 percent of its equivalent production during the second quarter of 2018.

Worldwide natural gas production decreased 55 MMcf/d to 932 MMcf/d in the second quarter of 2018 from the comparative prior-year period, primarily a result of Apache’s exit from Canada and natural decline in Egypt due to lower drilling activity, partially offset by an increase from Alpine High production.

NGL Revenues NGL revenues for the second quarter of 2018 totaled $148 million, an $85 million increase from the comparative 2017 quarter. A 104 percent increase in average realized prices increased second-quarter 2018 revenues by approximately $66 million compared to the prior-year quarter, while 16 percent higher average daily production increased revenues by approximately $19 million. The increase in realized prices is primarily the result of the reclassification of certain transportation charges from revenues to Gathering, Transmission, and Processing (GTP) expense as a result of the adoption of new revenue recognition rules effective January 1, 2018. NGLs accounted for 8 percent of Apache’s oil and gas production revenues and 14 percent of its equivalent production during the second quarter of 2018.

Worldwide production of NGLs increased 8.3 Mb/d to 61.3 Mb/d in the second quarter of 2018 from the comparative prior-year period, primarily a result of the commencement of Alpine High production, partially offset by a decrease from Apache’s exit from Canada.

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

Crude Oil Revenues Crude oil revenues for the first six months of 2018 totaled $3.0 billion, a $747 million increase from the comparative 2017 period. A 36 percent increase in average realized prices increased 2018 oil revenues by $808 million compared to the prior-year period, while 2 percent lower average daily production decreased revenues by $61 million. Crude oil accounted for 81 percent of oil and gas production revenues and 54 percent of worldwide production for the first six months of 2018, compared to 78 percent and 53 percent, respectively, for the 2017 period. Crude oil prices realized in the first six months of 2018 averaged $66.90 per barrel, compared with $49.06 per barrel in the comparative prior-year period.

Worldwide production decreased 3.8 Mb/d to 244.4 Mb/d in the first six months of 2018 from the comparative prior-year period, primarily a result of a decrease from Apache’s exit from Canada, partially offset by an increase in its Permian region on the success of the Midland and Delaware basin drilling programs.

Natural Gas Revenues Gas revenues for the first six months of 2018 totaled $434 million, a $54 million decrease from the comparative 2017 period. A 1 percent decrease in average realized prices decreased 2018 natural gas revenues by $3 million compared to the prior-year period, while 11 percent lower average daily production decreased revenues by $51 million. Natural gas accounted for 12 percent of the Company’s oil and gas production revenues and 33 percent of Apache’s equivalent production for the first six months of 2018, compared to 17 percent and 36 percent, respectively, for the 2017 period.

Worldwide natural gas production decreased 107.3 MMcf/d to 903 MMcf/d in the first six months of 2018 from the comparative prior-year period, primarily a result of Apache’s exit from Canada and natural decline in Egypt due to lower drilling activity, partially offset by an increase from Alpine High production.

NGL Revenues NGL revenues for the first six months of 2018 totaled $266 million, a $118 million increase from the comparative 2017 period. A 70 percent increase in average realized prices increased 2018 NGL revenues by $103 million compared to the prior-year period, while 6 percent higher average daily production increased revenues by $15 million. The increase in realized prices is primarily the result of the reclassification of certain transportation charges from revenues to GTP expense as a result of the adoption of new revenue recognition rules effective January 1, 2018. NGLs accounted for nearly 7 percent of the Company’s oil and gas production revenues and 13 percent of Apache’s equivalent production for the first six months of 2018, compared to 5 percent and 11 percent, respectively, for the 2017 period.

Worldwide production of NGLs increased 3.4 Mb/d to 57.4 Mb/d in the first six months of 2018 from the comparative prior-year period, primarily as a result of the commencement of Alpine High production, partially offset by a decrease from Apache’s exit from Canada.

Operating Expenses

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



	For the Quarter Ended June 30,								For the Six Months Ended June 30,
	2018		2017		2018		2017		2018		2017			2018		2017
	(In millions)				(Per boe)				(In millions)					(Per boe)
Lease operating expenses⁽¹⁾	$	356	$	372	$	8.39	$	8.81	$	705	$	708		$	8.60	$	8.27
Gathering, transmission, and processing⁽¹⁾	82		48		1.95		1.19		168		105			2.04		1.24
Taxes other than income	49		29		1.16		0.68		104		71			1.27		0.83
Exploration	76		108		1.81		2.58		152		200			1.86		2.35
General and administrative	117		106		2.76		2.53		231		209			2.82		2.45
Transaction, reorganization, and separation	12		4		0.27		0.08		12		(6		)	0.14		(0.07		)
Depreciation, depletion, and amortization:
Oil and gas property and equipment⁽¹⁾	573		536		13.50		12.72		1,091		1,074			13.31		12.56
Other assets	35		36		0.82		0.86		70		74			0.85		0.87
Asset retirement obligation accretion	27		37		0.64		0.87		54		73			0.66		0.85
Impairments	—		—		—		—		—		8			—		0.09
Financing costs, net	94		99		2.24		2.37		193		199			2.36		2.34


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

Lease Operating Expenses (LOE) LOE decreased $16 million and $3 million for the second quarter and first six months of 2018, respectively, on an absolute dollar basis relative to the comparable periods of 2017. On a per-unit basis, LOE decreased 5 percent to $8.39 per boe for the second quarter of 2018, and increased 4 percent to $8.60 per boe for the first six months of 2018 as compared to the prior-year periods. The decrease on an absolute dollar basis for both comparative periods is primarily the result of the sale of Apache’s Canadian operations in the third quarter of 2017, partially offset by general cost increases in a higher commodity price environment.

Gathering, Transmission, and Processing GTP costs totaled $82 million and $168 million in the second quarter and first six months of 2018, respectively, an increase of $34 million from the second quarter of 2017 and $63 million from the first six months of 2017. The increase is primarily the result of the reclassification of certain transportation charges from revenues to GTP expense as a result of the adoption of new revenue recognition rules effective January 1, 2018, as well as the ramp-up of operations at Alpine High, partially offset by Apache’s exit from Canada.

Taxes other than Income Taxes other than income totaled $49 million and $104 million for the second quarter and first six months of 2018, an increase of $20 million and $33 million from the second quarter and first six months of 2017, respectively. Second-quarter and year-to-date 2018 expense consists primarily of severance and ad valorem taxes, which combined increased $8 million and $18 million, respectively. The increase for both comparative periods is primarily the result of an increase in severance taxes on higher commodity prices and increased U.S. production driven by the ramp-up of operations at Alpine High. In addition, in the second quarter and first six months of 2017, Apache recognized a $12 million and $14 million benefit, respectively, related to the U.K. Petroleum Revenue Tax (PRT). The U.K. PRT rate, historically assessed on qualifying fields in the U.K. North Sea, was reduced to zero during 2016.

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 2018 decreased $32 million and $48 million, respectively, compared to the prior-year period.

The following table presents a summary of exploration expense:



	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2018		2017		2018		2017
	(In millions)
Unproved leasehold impairments	$	21	$	39	$	37	$	54
Dry hole expense	16		46		36		98
Geological and geophysical expense	17		6		35		12
Exploration overhead and other	22		17		44		36
	$	76	$	108	$	152	$	200

Unproved leasehold impairments in the second quarter and first six months of 2018 decreased $18 million and $17 million, respectively, from the comparative prior-year periods, primarily a result of stabilizing commodity and leasehold prices. Dry hole expense decreased $30 million and $62 million in the second quarter and first six months of 2018, respectively, from the comparative prior-year periods on activity primarily in the U.S. and North Sea. Geological and geophysical expense increased $11 million and $23 million in the second quarter and first six months of 2018, respectively, from the comparative prior-year periods driven by 3-D seismic acquisition in Egypt for the Khalda Extension 3 and various other concessions.

General and Administrative (G&A) Expenses G&A expense for the second quarter and first six months of 2018 were $11 million and $22 million higher than the comparative 2017 period. The increase in G&A expense was primarily related to non-cash stock-based compensation expense, which was impacted by a change in vesting terms for certain retirement eligible employees.

Transaction, Reorganization, and Separation (TRS) Costs The Company recorded TRS costs of $12 million for each of the second quarter and first six months of 2018 compared to $4 million of expense and a benefit of $6 million for the second quarter and first six months of 2017, respectively, primarily a result of an increase in the market value of stock awards outstanding for former employees.

Depreciation, Depletion, and Amortization (DD&A) Oil and gas property DD&A expense of $573 million in the second quarter of 2018 increased $37 million compared to the second quarter of 2017. For the first six months of 2018, oil and gas property DD&A expense increased $17 million compared to the prior-year period. The Company’s oil and gas property DD&A rate increased $0.78 per boe and $0.75 per boe in the second quarter and first six months of 2018 compared to the comparable prior-year periods. The primary factor driving higher absolute dollar expense was an increase in capital spending primarily in the Permian and Alpine High regions as a result of drilling and development activity. The increase on an absolute dollar basis was partially offset by the sale of Apache’s Canadian operations in the third quarter of 2017.

Impairments The Company did not record any asset impairments in connection with fair value assessments in the second quarter or first six months of 2018, or in the second quarter of 2017. For the six-month period ended June 30, 2017, the Company recorded asset impairments totaling $8 million for a U.K. PRT decommissioning asset that is no longer expected to be realizable from future abandonment activities in the North Sea. For more information regarding asset impairments, please refer to “Fair Value Measurements” within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q.

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



	For the Quarter Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(In millions)
Interest expense	$	110		$	115		$	222		$	231
Amortization of deferred loan costs	1			2			6			4
Capitalized interest	(13		)	(13		)	(25		)	(27		)
Loss on extinguishment of debt	—			—			—			1
Interest income	(4		)	(5		)	(10		)	(10		)
Financing costs, net	$	94		$	99		$	193		$	199

Net financing costs decreased $5 million and $6 million in the second quarter and first six months of 2018, respectively, compared to the same prior-year periods on lower interest expense from the repayment of $150 million of 7.0% senior notes due February 1, 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.

Capital Resources and Liquidity

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

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

Apache’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of Apache’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves.

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

For additional information, please see Part I, Items 1 and 2, “Business and Properties,” and Item 1A, “Risk Factors,” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

Sources and Uses of Cash

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



	For the Six Months Ended June 30,
	2018			2017
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	1,728		$	1,206
Proceeds from sale of oil and gas properties	13			711
Other	—			27
	1,741			1,944
Uses of Cash and Cash Equivalents:
Capital expenditures⁽¹⁾	$	1,856		$	1,157
Leasehold and property acquisitions	38			67
Payments on fixed-rate debt	150			70
Dividends paid	191			190
Distributions to noncontrolling interest	155			170
Other	47			—
	2,437			1,654
Increase (decrease) in cash and cash equivalents	$	(696	)	$	290


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

Net Cash Provided by Operating Activities Operating cash flows are Apache’s primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile oil and natural gas prices. The factors that determine operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation (ARO) accretion, and deferred income tax expense.

Net cash provided by operating activities for the first six months of 2018 totaled $1.7 billion, an increase of $522 million from the first six months of 2017. The increase primarily reflects higher commodity prices compared to the prior-year period.

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

Asset Divestitures The Company recorded proceeds from asset divestitures totaling $13 million and $711 million in the first six months of 2018 and 2017, respectively. For more information regarding the Company’s acquisitions and divestitures, please see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q.

Capital Expenditures Worldwide exploration and development (E&D) cash expenditures for the first six months of 2018 totaled $1.6 billion, compared to $883 million for the first six months of 2017. 2018 expenditures were primarily in the Permian region as Apache continues development of its Alpine High play. Apache operated an average of 33 drilling rigs during the second quarter of 2018.

Apache’s cash expenditures in GTP facilities totaled $284 million and $274 million in the first six months of 2018 and 2017, respectively, and primarily comprise investments in infrastructure for the Alpine High play.

Leasehold and Property Acquisitions Apache completed leasehold and property acquisitions for cash consideration totaling $38 million and $67 million during the first six months of 2018 and 2017, respectively.

Dividends The Company paid $191 million and $190 million in dividends on its common stock for the six-month periods ended June 30, 2018 and 2017, respectively.

Liquidity

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



	June 30, 2018		December 31, 2017
	(In millions)
Cash and cash equivalents	$	972	$	1,668
Total debt	8,337		8,484
Equity	8,995		8,791
Available committed borrowing capacity	3,830		3,500

Cash and cash equivalents The Company had $1.0 billion in cash and cash equivalents as of June 30, 2018, compared to $1.7 billion at December 31, 2017. The majority of the cash is invested in highly liquid, investment grade securities with maturities of three months or less at the time of purchase.

Debt As of June 30, 2018, outstanding debt, which consisted of unsecured notes and debentures, totaled $8.3 billion. Current debt as of June 30, 2018, included $400 million of 6.9% senior notes due September 15, 2018.

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Risk

The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices the Company receives for its crude oil, natural gas, and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather, political climate, and global supply and demand. The Company’s average crude oil realizations have increased 48 percent to $69.35 per barrel in the second quarter of 2018 from $46.89 per barrel in the comparable period of 2017. The Company’s average natural gas price realizations have decreased 4 percent to $2.50 per Mcf in the second quarter of 2018 from $2.60 per Mcf in the comparable period of 2017. Based on average daily production for the second quarter of 2018, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the quarter by approximately $23 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, 2018, the Company had open natural gas derivatives not designated as cash flow hedges in an asset position with a fair value of $72 million. A 10 percent increase in gas prices would decrease the asset by approximately $1 million, while a 10 percent decrease in prices would increase the asset by approximately $1 million. As of June 30, 2018, the Company had open oil derivatives not designated as cash flow hedges in an asset position with a fair value of $2 million. A 10 percent increase in oil prices would move the derivatives to a liability position with a fair value of $42 million, while a 10 percent decrease in prices would increase the asset by approximately $47 million. These fair value changes assume volatility based on prevailing market parameters at June 30, 2018. See Note 4—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q for notional volumes and terms with the Company’s derivative contracts.

Foreign Currency Risk

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

Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Currency gains and losses are included as either a component of “Other” under “Revenues and Other” or, as is the case when the Company re-measures its foreign tax liabilities, as a component of the Company’s provision for income tax expense on the statement of consolidated operations. A foreign currency net gain or loss of $11 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of June 30, 2018.

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, 2018, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that information we are required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

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

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Please refer to Part I, Item 3 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017 (filed with the SEC on February 23, 2018) and Note 9—Commitments and Contingencies in the notes to the consolidated financial statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q, for a description of material legal proceedings.

ITEM 1A. RISK FACTORS

Please refer to Part I, Item 1A—Risk Factors of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, and Part I, Item 3—Quantitative and Qualitative Disclosures About Market Risk of this Quarterly Report on Form 10-Q. There have been no material changes to our risk factors since our annual report on Form 10-K for the fiscal year ended December 31, 2017.

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

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4. MINE SAFETY DISCLOSURES

None

ITEM 5. OTHER INFORMATION

None

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).
*†10.1	–	2018 Employee Release and Benefits Agreement between Registrant and W. Kregg Olson, effective August 1, 2018.
*31.1	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
*32.1	–	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
*101.INS	–	XBRL Instance Document.
*101.SCH	–	XBRL Taxonomy Schema Document.
*101.CAL	–	XBRL Calculation Linkbase Document.
*101.DEF	–	XBRL Definition Linkbase Document.
*101.LAB	–	XBRL Label Linkbase Document.
*101.PRE	–	XBRL Presentation Linkbase Document.

* Filed herewith.

† Management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 15 hereof.

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 2, 2018	/s/ STEPHEN J. RINEY
		Stephen J. Riney
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

Dated:	August 2, 2018	/s/ REBECCA A. HOYT
		Rebecca A. Hoyt
		Senior Vice President, Chief Accounting Officer, and Controller
		(Principal Accounting Officer)