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 September 30, 2018
OR
¨

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File Number 1-4300
APACHE CORPORATION
(exact name of registrant as specified in its charter)
    _______________________________________________________________________
Delaware
41-0747868
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification Number)
One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400
(Address of principal executive offices)
Registrant’s Telephone Number, Including Area Code: (713) 296-6000
__________________________________________________________________________________
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
ý
Accelerated filer
 
¨
Non-accelerated filer
 
¨ (Do not check if a smaller reporting company)
Smaller reporting company
 
¨
 
 
 
Emerging growth company
 
¨ 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  ¨    No  ý
Number of shares of registrant’s common stock outstanding as of October 31, 2018
379,543,642




 
TABLE OF CONTENTS
 
DESCRIPTION
Item
 
 
Page
 
PART I - FINANCIAL INFORMATION
 
 
1.
 
 
 
 
 
 
 
 
 
 
 
2.
 
3.
 
4.
 
 
PART II - OTHER INFORMATION
 
 
1.
 
1A.
 
2.
 
3.
 
4.
 
5.
 
6.
 



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

our commodity hedging arrangements;

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

pipeline and gathering system capacity;

production and reserve levels;

drilling risks;

economic and competitive conditions;

the availability of capital resources;

capital expenditure and other contractual obligations;

currency exchange rates;

weather conditions;

inflation rates;

the availability of goods and services;

legislative, regulatory, or policy changes;

terrorism or cyber attacks;

occurrence of property acquisitions or divestitures;

the integration of acquisitions;

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

other factors disclosed under Items 1 and 2—Business and Properties—Estimated Proved Reserves and Future Net Cash Flows, Item 1A—Risk Factors, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A—Quantitative and Qualitative Disclosures About Market Risk and elsewhere in our most recently filed Annual Report on Form 10-K, other risks and uncertainties in our third-quarter 2018 earnings release, other factors disclosed under Part II, Item 1A—Risk Factors of this Quarterly Report on Form 10-Q, and other filings that we make with the Securities and Exchange Commission.
All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.





PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Unaudited)
 
 
For the Quarter Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(In millions, except per common share data)
REVENUES AND OTHER:
 
 
 
 
 
 
 
 
Oil and gas production revenues
 
 
 
 
 
 
 
 
Oil revenues
 
$
1,555

 
$
1,070

 
$
4,524

 
$
3,292

Natural gas revenues
 
241

 
238

 
675

 
726

Natural gas liquids revenues
 
180

 
81

 
446

 
229

 
 
1,976

 
1,389

 
5,645

 
4,247

Derivative instrument losses, net
 
(23
)
 
(110
)
 
(46
)
 
(69
)
Gain on divestitures
 
1

 
296

 
10

 
616

Other
 
29

 

 
50

 
43

 
 
1,983

 
1,575

 
5,659

 
4,837

OPERATING EXPENSES:
 
 
 
 
 
 
 
 
Lease operating expenses
 
382

 
353

 
1,087

 
1,059

Gathering, transmission, and processing
 
92

 
44

 
260

 
151

Taxes other than income
 
58

 
46

 
162

 
117

Exploration
 
99

 
231

 
251

 
431

General and administrative
 
99

 
98

 
330

 
307

Transaction, reorganization, and separation
 
8

 
20

 
20

 
14

Depreciation, depletion, and amortization:
 
 
 
 
 
 
 
 
Oil and gas property and equipment
 
575

 
524

 
1,666

 
1,598

Other assets
 
35

 
35

 
105

 
109

Asset retirement obligation accretion
 
27

 
30

 
81

 
103

Impairments
 
10

 

 
10

 
8

Financing costs, net
 
192

 
101

 
385

 
300

 
 
1,577

 
1,482

 
4,357

 
4,197

NET INCOME BEFORE INCOME TAXES
 
406

 
93

 
1,302

 
640

Current income tax provision
 
262

 
99

 
709

 
413

Deferred income tax benefit
 
(17
)
 
(111
)
 
(43
)
 
(758
)
NET INCOME INCLUDING NONCONTROLLING INTEREST
 
161

 
105

 
636

 
985

Net income attributable to noncontrolling interest
 
80

 
42

 
215

 
137

NET INCOME ATTRIBUTABLE TO COMMON STOCK
 
$
81

 
$
63

 
$
421

 
$
848

 
 
 
 
 
 
 
 
 
NET INCOME PER COMMON SHARE:
 
 
 
 
 
 
 
 
Basic
 
$
0.21

 
$
0.16

 
$
1.10

 
$
2.23

Diluted
 
$
0.21

 
$
0.16

 
$
1.09

 
$
2.22

WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
 
 
 
 
 
 
 
 
Basic
 
383

 
381

 
383

 
381

Diluted
 
385

 
383

 
385

 
383

DIVIDENDS DECLARED PER COMMON SHARE
 
$
0.25

 
$
0.25

 
$
0.75

 
$
0.75

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

1



APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME
(Unaudited)
 
 
 
For the Quarter Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(In millions)
NET INCOME INCLUDING NONCONTROLLING INTEREST
 
$
161

 
$
105

 
$
636

 
$
985

OTHER COMPREHENSIVE INCOME:
 
 
 
 
 
 
 
 
Currency translation adjustment
 

 
109

 

 
109

COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTEREST
 
161

 
214

 
636

 
1,094

Comprehensive income attributable to noncontrolling interest
 
80

 
42

 
215

 
137

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK
 
$
81

 
$
172

 
$
421

 
$
957


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

2



APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Unaudited)
 
 
For the Nine Months Ended September 30,
 
 
2018
 
2017
 
 
(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
 
Net income including noncontrolling interest
 
$
636

 
$
985

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Unrealized derivative instrument (gain) loss, net
 
(88
)
 
42

Gain on divestitures
 
(10
)
 
(616
)
Exploratory dry hole expense and unproved leasehold impairments
 
133

 
350

Depreciation, depletion, and amortization
 
1,771

 
1,707

Asset retirement obligation accretion
 
81

 
103

Impairments
 
10

 
8

Deferred income tax benefit
 
(43
)
 
(758
)
Loss on extinguishment of debt
 
94

 
1

Other
 
147

 
166

Changes in operating assets and liabilities:
 
 
 
 
Receivables
 
(113
)
 
(70
)
Inventories
 
(7
)
 
17

Drilling advances
 
(22
)
 
(72
)
Deferred charges and other
 
91

 
(60
)
Accounts payable
 
110

 
2

Accrued expenses
 
(54
)
 
(65
)
Deferred credits and noncurrent liabilities
 
(2
)
 
20

NET CASH PROVIDED BY OPERATING ACTIVITIES
 
2,734

 
1,760

 
 
 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
Additions to oil and gas property
 
(2,338
)
 
(1,471
)
Leasehold and property acquisitions
 
(86
)
 
(142
)
Additions to gas gathering, transmission, and processing facilities
 
(412
)
 
(384
)
Proceeds from sale of Canadian assets, net of cash divested
 

 
661

Proceeds from sale of oil and gas properties
 
51

 
743

Other, net
 
(55
)
 
(30
)
NET CASH USED IN INVESTING ACTIVITIES
 
(2,840
)
 
(623
)
 
 
 
 
 
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
Fixed-rate debt borrowings
 
992

 

Payments on fixed-rate debt
 
(1,370
)
 
(70
)
Distributions to noncontrolling interest
 
(256
)
 
(212
)
Dividends paid
 
(287
)
 
(285
)
Other
 
(48
)
 
(5
)
NET CASH USED IN FINANCING ACTIVITIES
 
(969
)
 
(572
)
 
 
 
 
 
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS, AND RESTRICTED CASH
 
(1,075
)
 
565

CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF YEAR
 
1,668

 
1,377

CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD
 
$
593

 
$
1,942

 
 
 
 
 
SUPPLEMENTARY CASH FLOW DATA:
 
 
 
 
Interest paid, net of capitalized interest
 
$
344

 
$
341

Income taxes paid, net of refunds
 
649

 
315

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

3



APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)
 
 
September 30, 2018
 
December 31, 2017
 
 
(In millions)
ASSETS
 
 
 
 
CURRENT ASSETS:
 
 
 
 
Cash and cash equivalents
 
$
593

 
$
1,668

Receivables, net of allowance
 
1,457

 
1,345

Inventories
 
362

 
368

Drilling advances
 
229

 
207

Prepaid assets and other
 
144

 
137

 
 
2,785

 
3,725

PROPERTY AND EQUIPMENT:
 
 
 
 
Oil and gas, on the basis of successful efforts accounting:
 
 
 
 
Proved properties
 
41,518

 
39,197

Unproved properties and properties under development
 
1,704

 
1,783

Gathering, transmission and processing facilities
 
1,742

 
1,376

Other
 
1,081

 
1,046

 
 
46,045

 
43,402

Less: Accumulated depreciation, depletion, and amortization
 
(27,399
)
 
(25,643
)
 
 
18,646

 
17,759

OTHER ASSETS:
 
 
 
 
Deferred charges and other
 
439

 
438

 
 
$
21,870

 
$
21,922

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
CURRENT LIABILITIES:
 
 
 
 
Accounts payable
 
$
744

 
$
641

Current debt
 
150

 
550

Other current liabilities (Note 5)
 
1,313

 
1,373

 
 
2,207

 
2,564

LONG-TERM DEBT
 
8,053

 
7,934

DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
 
 
 
 
Income taxes
 
502

 
545

Asset retirement obligation
 
1,867

 
1,792

Other
 
295

 
296

 
 
2,664

 
2,633

COMMITMENTS AND CONTINGENCIES (Note 9)
 

 

EQUITY:
 
 
 
 
Common stock, $0.625 par, 860,000,000 shares authorized, 415,660,982 and 414,125,879 shares issued, respectively
 
260

 
259

Paid-in capital
 
11,945

 
12,128

Accumulated deficit
 
(1,667
)
 
(2,088
)
Treasury stock, at cost, 34,092,692 and 33,171,015 shares, respectively
 
(2,930
)
 
(2,887
)
Accumulated other comprehensive income
 
4

 
4

APACHE SHAREHOLDERS’ EQUITY
 
7,612

 
7,416

Noncontrolling interest
 
1,334

 
1,375

TOTAL EQUITY
 
8,946

 
8,791

 
 
$
21,870

 
$
21,922

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

4



APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY
(Unaudited)
 
 
 
Common
Stock
 
Paid-In
Capital
 
Accumulated Deficit
 
Treasury
Stock
 
Accumulated
Other
Comprehensive
Income (Loss)
 
APACHE
SHAREHOLDERS’
EQUITY
 
Noncontrolling
Interest
 
TOTAL
EQUITY
 
 
(In millions)
BALANCE AT DECEMBER 31, 2016
 
$
258

 
$
12,364

 
$
(3,385
)
 
$
(2,887
)
 
$
(112
)
 
$
6,238

 
$
1,441

 
$
7,679

Net income
 

 

 
848

 

 

 
848

 
137

 
985

Distributions to noncontrolling interest
 

 

 

 

 

 

 
(212
)
 
(212
)
Common dividends ($0.75 per share)
 

 
(286
)
 

 

 

 
(286
)
 

 
(286
)
Other
 
1

 
108

 
(7
)
 

 
109

 
211

 

 
211

BALANCE AT SEPTEMBER 30, 2017
 
$
259

 
$
12,186

 
$
(2,544
)
 
$
(2,887
)
 
$
(3
)
 
$
7,011

 
$
1,366

 
$
8,377

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
BALANCE AT DECEMBER 31, 2017
 
$
259

 
$
12,128

 
$
(2,088
)
 
$
(2,887
)
 
$
4

 
$
7,416

 
$
1,375

 
$
8,791

Net income
 

 

 
421

 

 

 
421

 
215

 
636

Distributions to noncontrolling interest
 

 

 

 

 

 

 
(256
)
 
(256
)
Common dividends ($0.75 per share)
 

 
(287
)
 

 

 

 
(287
)
 

 
(287
)
Other
 
1

 
104

 

 
(43
)
 

 
62

 

 
62

BALANCE AT SEPTEMBER 30, 2018
 
$
260

 
$
11,945

 
$
(1,667
)
 
$
(2,930
)
 
$
4

 
$
7,612

 
$
1,334

 
$
8,946

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


5



APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
These consolidated financial statements have been prepared by Apache Corporation (Apache or the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited financial statements, with the exception of recently adopted accounting pronouncements discussed below. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, which contains a summary of the Company’s significant accounting policies and other disclosures.
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
As of September 30, 2018, Apache’s significant accounting policies are consistent with those discussed in Note 1—Summary of Significant Accounting Policies of its consolidated financial statements contained in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, with the exception of Accounting Standards Update (ASU) 2014-09, “Revenue from Contracts with Customers (Topic 606)” (see “Revenue Recognition” section in this Note 1 below).
Use of Estimates
Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates with regard to these financial statements include the fair value determination of acquired assets and liabilities, the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, the assessment of asset retirement obligations, the estimates of fair value for long-lived assets, and the estimate of income taxes. Actual results could differ from those estimates.
Fair Value Measurements
Certain assets and liabilities are reported at fair value on a recurring basis in Apache’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.
The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
Recurring fair value measurements are presented in further detail in Note 4—Derivative Instruments and Hedging Activities and Note 8—Debt and Financing Costs.
Apache also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. For the third quarter and nine-month period ended September 30, 2018, the Company recorded asset impairments in connection with fair value assessments totaling $10 million. In the third quarter of 2018, Apache agreed to sell certain of its unproved properties offshore the U.K. in the North Sea (North Sea). As a result, the Company performed a fair value assessment of the properties and recorded a $10 million impairment on the carrying values of the associated capitalized exploratory well costs. The fair value of the impaired assets was determined using the negotiated sales price, a Level 1 fair value measurement.
The Company recorded no asset impairments in connection with fair value assessments in the third quarter of 2017. For the nine-month period ended September 30, 2017, the Company recorded asset impairments in connection with fair value assessments

6



totaling $8 million for a United Kingdom (U.K.) Petroleum Revenue Tax (PRT) decommissioning asset that is no longer expected to be realizable from future abandonment activities in the North Sea.
In 2016, the U.K. government enacted Finance Bill 2016, providing tax relief to exploration and production (E&P) companies operating in the U.K. North Sea. Under the enacted legislation, the U.K. PRT rate was reduced to zero from the previously enacted 35 percent rate in effect from January 1, 2016. PRT expense ceased prospectively from that date. During the first quarter of 2017, the Company fully impaired the aggregate remaining value of the recoverable PRT decommissioning asset of $8 million that would have been realized from future abandonment activities. The recoverable value of the PRT decommissioning asset was estimated using the income approach. The expected future cash flows used in the determination were based on anticipated spending and timing of planned future abandonment activities for applicable fields, considering all available information at the date of review. Apache has classified this fair value measurement as Level 3 in the fair value hierarchy.
Oil and Gas Property
The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs such as exploratory geological and geophysical costs, delay rentals, and exploration overhead are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.
Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations.
Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of those reserves. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized costs for exploratory and development wells is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.
Oil and gas properties are grouped for depreciation in accordance with ASC 932 “Extractive Activities—Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

7



When circumstances indicate that proved oil and gas properties may be impaired, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on Apache’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. If applicable, the Company utilizes prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a discount rate believed to be consistent with those applied by market participants. Apache has classified these fair value measurements as Level 3 in the fair value hierarchy.
The following table represents non-cash impairments of the carrying value of the Company’s proved and unproved property for the third quarters and first nine months of 2018 and 2017:
 
 
For the Quarter Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(In millions)
Oil and Gas Property:
 
 
 
 
 
 
 
 
Proved
 
$

 
$

 
$

 
$

Unproved
 
49

 
160

 
86

 
214

On the statement of consolidated operations, unproved leasehold impairments are recorded in exploration expense, and all other impairments of proved and unproved properties based on fair value assessments are recorded separately in impairments.
Revenue Recognition
On January 1, 2018, Apache adopted ASU 2014-09, “Revenue from Contracts with Customers (ASC 606),” using the modified retrospective method. The Company elected to evaluate all contracts at the date of initial application. While there was no impact to the opening balance of retained earnings as a result of the adoption, certain items previously netted in revenue are now recognized as “Gathering, transmission, and processing” in the Company’s statement of consolidated operations. The amounts reclassified are immaterial to the financial statements, and prior comparative periods have not been restated and continue to be reported under the accounting standards in effect for those periods. Adoption of the new standard is not anticipated to have a material impact on the Company’s net earnings on an ongoing basis.
The Company applies the provisions of ASC 606 for revenue recognition to contracts with customers. Sales of crude oil, natural gas, and NGLs are included in revenue when production is sold to a customer in fulfillment of performance obligations under the terms of agreed contracts. Performance obligations primarily comprise delivery of oil, gas, or NGLs at a delivery point, as negotiated within each contract. Each barrel of oil, million Btu (MMBtu) of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, the Company’s right to payment, and transfer of legal title. In each case, the term between delivery and when payments are due is not significant.
Apache markets its own United States (U.S.) natural gas and crude oil production based on market-priced contracts. Typically, these contracts are adjusted for quality, transportation, and other market-reflective differentials. Since the Company’s production may fluctuate as a result of operational issues, it is occasionally necessary to purchase third-party oil and gas to fulfill sales obligations and commitments. Sales proceeds related to third-party purchased oil and gas are determined to be revenue from a customer. Proceeds for these volumes totaled $124 million and $326 million for the third quarter and first nine months of 2018, respectively. Associated purchase costs for these volumes totaled $109 million and $308 million for the third quarter and first nine months of 2018, respectively. Proceeds and costs are both recorded as “Other” under “Revenues and Other” in the statement of consolidated operations.
Internationally, Apache sells its North Sea crude oil under contracts with a market-based index price. Natural gas from the North Sea Beryl field is processed through the SAGE gas plant. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. Apache’s gas production in Egypt is sold primarily under an industry-

8



pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. The Company’s Egypt oil production is sold at prices equivalent to the export market.
The Company’s Egyptian operations are conducted pursuant to production sharing contracts under which contractor partners pay all operating and capital costs for exploring and developing the concessions. A percentage of the production, generally up to 40 percent, is available to contractor partners to recover these operating and capital costs over contractually defined periods. The balance of the production is split among the contractor partners and the Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. Additionally, the contractor partner’s income taxes, which remain the liability of the contractor partners under domestic law, are paid by EGPC on behalf of the contractor partners out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of Apache as contract partner are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Revenues related to Egypt’s tax volumes are considered revenue from a non-customer.
For the third quarter of 2018, revenues from customers and non-customers were $1.9 billion and $198 million, respectively. For the first nine months of 2018, revenues from customers and non-customers were $5.4 billion and $534 million, respectively.
Apache records trade accounts receivable for its unconditional rights to consideration arising under sales contracts with customers. The carrying value of such receivables, net of the allowance for doubtful accounts, represents estimated net realizable value. The Company routinely assesses the collectability of all material trade and other receivables. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. Receivables from contracts with customers, net of allowance for doubtful accounts, totaled $1.3 billion and $1.1 billion as of September 30, 2018 and December 31, 2017, respectively.
Apache has concluded that disaggregating revenue by geographic area and by product appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. Refer to Note 11—Business Segment Information for a disaggregation of revenue by each product sold.
Practical Expedients and Exemptions
Apache does not disclose the value of unsatisfied performance obligations for contracts with an original expected length of one year or less or contracts for which variable consideration is allocated entirely to a wholly unsatisfied performance obligation.
Apache will utilize the practical expedient to expense incremental costs of obtaining a contract if the expected amortization period is one year or less. Costs to obtain a contract with expected amortization periods of greater than one year will be recorded as an asset and will be recognized in accordance with ASC 340, “Other Assets and Deferred Costs.” Currently, the Company does not have contract assets related to incremental costs to obtain a contract.
New Pronouncements Issued But Not Yet Adopted
In February 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-02, “Leases (Topic 842),” requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous GAAP. The guidance is effective for fiscal years beginning after December 15, 2018. Early adoption is permitted; however, the Company does not intend to early adopt. In January 2018, the FASB issued ASU 2018-01, which permits an entity an optional election to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases prior to the adoption of ASU 2016-02. In July 2018, the FASB issued ASU 2018-11, which adds a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the consolidated financial statements. Under this transition option, comparative reporting would not be required, and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. Apache intends to elect both transitional practical expedients.
In the normal course of business, the Company enters into various lease agreements for real estate, aircraft, and equipment related to its exploration and development activities that are currently accounted for as operating leases. To track these lease arrangements and facilitate compliance with this ASU, the Company is in the process of implementing a third-party lease accounting software solution and designing processes and internal controls. The Company continues to evaluate contracts, train departments affected by the standard, and monitor updates to the standard to determine the impact this ASU will have on its consolidated financial statements. At this time, the Company cannot reasonably estimate the financial impact this will have on its consolidated financial statements; however, the Company believes adoption and implementation of this ASU will significantly impact its balance sheet, resulting in an increase in both assets and liabilities relating to its leasing activities.

9



In June 2018, the FASB issued ASU 2018-07, “Improvements to Nonemployee Share-Based Payment Accounting,” to simplify the accounting for share-based transactions by expanding the scope of Topic 718 from only being applicable to share-based payments to employees to also include share-based payment transactions for acquiring goods and services from nonemployees. As a result, the same guidance that provides for employee share-based payments, including most of the requirements related to classification and measurement, applies to nonemployee share-based payment arrangements. ASU 2018-07 is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods. Early adoption is permitted. The Company anticipates adopting this guidance for the first quarter of 2019 and does not expect it to have a material impact on its consolidated financial statements.
In August 2018, the FASB issued ASU 2018-13, “Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement,” which changes the disclosure requirements for fair value measurements by removing, adding, and modifying certain disclosures. ASU 2018-13 is effective for financial statements issued for annual periods beginning after December 15, 2019, and interim periods within those annual periods. Early adoption is permitted. The company is currently evaluating the impact of adoption of this ASU on its related disclosures and does not expect it to have a material impact on its financial statements.
In August 2018, the FASB issued ASU 2018-14, “Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans,” which eliminates, modifies, and adds disclosure requirements for defined benefit plans. The ASU is effective for financial statements issued for fiscal years ending after December 15, 2020. Early adoption is permitted. The Company is currently evaluating the impact of adoption of this ASU on its related disclosures and does not expect it to have a material impact on its financial statements.
In August 2018, the FASB issued ASU 2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract.” This pronouncement clarifies the requirements for capitalizing implementation costs in cloud computing arrangements and aligns them with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. This pronouncement is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued. The Company is currently evaluating the impact of adoption of this ASU on its consolidated financial statements and does not expect it to have a material impact.
2.
ACQUISITIONS AND DIVESTITURES
2018 Activity
U.S. Divestitures
On August 8, 2018, Apache and Kayne Anderson Acquisition Corp. (KAAC) announced an agreement pursuant to which Apache will contribute Apache’s Alpine High midstream assets into a newly formed limited partnership, Altus Midstream LP. Upon closing, KAAC will contribute to the partnership approximately $952 million in cash, less anticipated transaction expenses and any amount associated with potential KAAC share redemptions. The partnership will be jointly owned by Apache and KAAC. Apache will own an estimated 71 percent ownership interest in Altus Midstream LP, adjusted accordingly for any KAAC share redemptions, and expects to fully consolidate the entity in its consolidated financial statements, with the corresponding noncontrolling interest of third-party ownership reflected separately in the financial statements. The transaction is subject to approval by KAAC shareholders, as well as other customary closing conditions. Closing is expected in the fourth quarter of 2018. Upon closing, KAAC will be renamed Altus Midstream Company.
During the first nine months of 2018, Apache completed the sale of certain non-core assets, primarily in the Permian region, in multiple transactions for cash proceeds of $51 million. The Company recognized gains of approximately $10 million during the first nine months of 2018 upon the closing of these transactions.
Leasehold and Property Acquisitions
During the third quarter and first nine months of 2018, Apache completed $48 million and $86 million, respectively, of leasehold and property acquisitions primarily in its U.S. onshore and Egypt regions.
2017 Activity
Canada Divestitures
On June 30, 2017, Apache completed the sale of its Canadian assets at Midale and House Mountain, located in Saskatchewan and Alberta, for aggregate cash proceeds of approximately $228 million. The Company recognized a $52 million loss during the second quarter of 2017 in association with this sale.

10



During the third quarter of 2017, Apache announced the sale of its subsidiary Apache Canada Ltd. (ACL) and complete exit of its Canadian operations for aggregate cash proceeds of approximately $478 million. The Company recognized a $74 million gain upon closing of these transactions in the third quarter of 2017.
A summary of the assets and liabilities at closing of the August transactions is detailed below:
 
 
(In millions)
ASSETS
 
 
Current assets
 
$
110

Property, plant & equipment
 
1,132

Total Assets
 
$
1,242

LIABILITIES
 
 
Current liabilities, excluding asset retirement obligation
 
$
120

Asset retirement obligation
 
780

Other long-term liabilities
 
46

Total Liabilities
 
$
946

The net carrying value of the assets disposed included a currency translation loss of $109 million, which was recorded in “Accumulated Other Comprehensive Loss” on the Company’s consolidated balance sheet at December 31, 2016. The currency translation loss was recognized as a reduction of the net gain on sale during the third quarter of 2017 upon closing of the transactions.
Apache’s Canadian operations recorded pretax losses of $12 million and $141 million for the third quarter and first nine months of 2017, respectively.
U.S. Divestitures
During the first nine months of 2017, Apache completed the sale of certain non-core assets, consisting primarily of leasehold acreage in the Permian and Midcontinent/Gulf Coast regions, in multiple transactions for cash proceeds of $783 million, subject to customary closing adjustments. A refundable deposit of $40 million was received in the fourth quarter of 2016 in connection with certain of these transactions. The Company recognized gains of approximately $594 million during the first nine months of 2017 in connection with these transactions.
Leasehold and Property Acquisitions
During the third quarter and first nine months of 2017, Apache purchased $75 million and $142 million, respectively, of leasehold and property acquisitions primarily in its U.S. onshore regions.
3.   CAPITALIZED EXPLORATORY WELL COSTS
The Company’s capitalized exploratory well costs were $300 million and $350 million at September 30, 2018 and December 31, 2017, respectively. The decrease is primarily attributable to successful transfers of well costs and dry hole write-offs, partially offset by additional drilling activities during the period. No suspended exploratory well costs previously capitalized for greater than one year at December 31, 2017 were charged to dry hole expense during the nine months ended September 30, 2018; however, during the third quarter of 2018, Apache announced an agreement to sell certain of its unproved properties in the North Sea. Exploratory well costs of approximately $70 million that have been capitalized greater than one year are included in the divestiture, which is anticipated to be completed prior to year-end.
Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether reserves can be attributed to these projects.
4.   DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Objectives and Strategies
The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production. Apache manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production. The Company utilizes various types of derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. Apache has elected not to designate any of its derivative contracts as cash flow hedges.

11



Counterparty Risk
The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, Apache utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2018, Apache had derivative positions with 15 counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, Apache may not realize the benefit of some of its derivative instruments resulting from lower commodity prices.
Derivative Instruments
As of September 30, 2018, Apache had the following open crude oil derivative positions:
 
 
 
 
Put Options(1)
Production Period
 
Settlement Index
 
Mbbls
 
Weighted Average Strike Price
October—December 2018
 
Dated Brent
 
3,680

 
$56.00
October—December 2018
 
NYMEX WTI
 
2,760

 
$53.00
(1)
The remaining unamortized premium paid as of September 30, 2018, was $12 million.
 
 
 
 
Collars
 
Call Options(2)
Production Period
 
Settlement Index
 
Mbbls
 
Weighted Average Floor Price
 
Weighted Average Ceiling Price
 
Mbbls
 
Strike Price
October—December 2018
 
NYMEX WTI
 
1,702

 
$45.00
 
$57.00
 
1,702

 
$60.03
(2)
The remaining unamortized premium paid as of September 30, 2018, was $3 million.
As of September 30, 2018, Apache had the following open crude oil financial basis swap contracts:
Production Period
 
Settlement Index
 
Mbbls
 
Weighted Average Price Differential
October—December 2018
 
Midland-WTI/Cushing-WTI
 
1,380

 
$(9.23)
January—September 2019
 
Midland-WTI/Cushing-WTI
 
7,371

 
$(8.60)
October—December 2019
 
Midland-WTI/Cushing-WTI
 
1,380

 
$(3.72)

As of September 30, 2018, Apache had the following open natural gas derivative positions:
 
 
 
 
Fixed-Price Swaps
Production Period
 
Settlement Index
 
MMBtu
(in 000’s)
 
Weighted Average Fixed Price
October—December 2018
 
NYMEX Henry Hub
 
16,790

 
$2.96

12



As of September 30, 2018, Apache had the following open natural gas financial basis swap contracts:
Production Period
 
Settlement Index
 
MMBtu
(in 000’s)
 
Weighted Average Price Differential
October—December 2018
 
NYMEX Henry Hub/Waha
 
17,940

 
$(0.53)
January—March 2019
 
NYMEX Henry Hub/Waha
 
1,350

 
$(0.54)
January—June 2019
 
NYMEX Henry Hub/Waha
 
32,580

 
$(0.53)
January—December 2019
 
NYMEX Henry Hub/Waha
 
14,600

 
$(0.45)

Fair Value Measurements
Apache’s commodity derivative instruments consist of variable-to-fixed price commodity swaps, options, and collars. The fair values of the Company’s derivatives are not actively quoted in the open market. The Company uses a market approach to estimate the fair values of its derivative instruments on a recurring basis, utilizing commodity futures pricing for the underlying commodities provided by a reputable third party, a Level 2 fair value measurement.
The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:
 
 
Fair Value Measurements Using
 
 
 
 
 
 
 
 
Quoted Price in Active Markets (Level 1)
 
Significant Other Inputs (Level 2)
 
Significant Unobservable Inputs
(Level 3)
 
Total Fair Value
 
Netting(1)
 
Carrying Amount
 
 
(In millions)
September 30, 2018
 
 
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Derivative Instruments
 
$

 
$
84

 
$

 
$
84

 
$
(36
)
 
$
48

Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Derivative Instruments
 

 
41

 

 
41

 
(36
)
 
5

December 31, 2017
 
 
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Derivative Instruments
 
$

 
$
67

 
$

 
$
67

 
$
(43
)
 
$
24

Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Derivative Instruments
 

 
107

 

 
107

 
(43
)
 
64

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

13



All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:
 
 
September 30, 2018
 
December 31, 2017
 
 
(In millions)
Current Assets: Prepaid assets and other
 
$
46

 
$
8

Other Assets: Deferred charges and other
 
2

 
16

Total Assets
 
$
48

 
$
24

 
 
 
 
 
Current Liabilities: Other current liabilities
 
$
4

 
$
64

Noncurrent Liabilities: Other
 
1

 

Total Liabilities
 
$
5

 
$
64


Derivative Activity Recorded in the Statement of Consolidated Operations
The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:

 
 
For the Quarter Ended September 30,
 
For the Nine Months Ended September 30,
2018
 
2017
 
2018
 
2017
 
 
(In millions)
Realized gain (loss):
 
 
 
 
 
 
 
 
Derivative settlements
 
$
7

 
$
23

 
$
(110
)
 
$
23

Amortization of call and put premium
 
(14
)
 
(50
)
 
(24
)
 
(50
)
Unrealized gain (loss)
 
(16
)
 
(83
)
 
88

 
(42
)
Derivative instrument gain (losses), net
 
$
(23
)
 
$
(110
)
 
$
(46
)
 
$
(69
)
Derivative instrument gains and losses are recorded in “Derivative instrument losses, net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains and losses for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument (gain) loss, net” in “Adjustments to reconcile net income to net cash provided by operating activities.”
5.
OTHER CURRENT LIABILITIES
The following table provides detail of the Company’s other current liabilities as of September 30, 2018 and December 31, 2017:
 
 
September 30, 2018
 
December 31, 2017
 
 
(In millions)
Accrued operating expenses
 
$
79

 
$
72

Accrued exploration and development
 
660

 
680

Accrued gathering, transmission, and processing
 
67

 
122

Accrued compensation and benefits
 
147

 
115

Accrued interest
 
99

 
145

Accrued income taxes
 
89

 
55

Current asset retirement obligation
 
38

 
43

Other
 
134

 
141

Total other current liabilities
 
$
1,313

 
$
1,373


14



6.
ASSET RETIREMENT OBLIGATION
The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the nine-month period ended September 30, 2018:
 
 
(In millions)
Asset retirement obligation at December 31, 2017
 
$
1,835

Liabilities incurred
 
27

Liabilities settled
 
(39
)
Accretion expense
 
81

Revisions in estimated liabilities
 
1

Asset retirement obligation at September 30, 2018
 
1,905

Less current portion
 
(38
)
Asset retirement obligation, long-term
 
$
1,867


15



7.
INCOME TAXES
The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments of the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur.
During the third quarter of 2018, Apache’s effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets. During the third quarter of 2017, Apache’s effective income tax rate was primarily impacted by gains on the sale of oil and gas properties, a $30 million current tax benefit associated with U.S. federal income tax credits, a deferred tax asset associated with its realizable capital loss on the sale of ACL, and a decrease in the Company’s deferred tax liability associated with its investment in foreign subsidiaries. For more information regarding the sale of ACL, please refer to Note 2—Acquisitions and Divestitures.
Apache’s 2018 year-to-date effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets. Apache’s 2017 year-to-date effective income tax rate was primarily impacted by the decrease in deferred taxes associated with its investments in foreign subsidiaries, gains on the sale of oil and gas properties, non-cash impairments of the Company’s PRT decommissioning asset, the current tax benefit associated with U.S. federal income tax credits, and the sale of ACL.
On December 22, 2017, the Tax Cuts and Jobs Act (the Act) was signed into law. In 2018, the Internal Revenue Service (IRS) issued additional guidance related to the Act’s deemed repatriation of foreign earnings (i.e., transition inclusion). In light of this new guidance, the Company continues to reevaluate the tax impact of the transition inclusion in 2017. Tax benefit associated with the change in transition inclusion is likely to be fully offset by a change in the Company’s valuation allowance against its U.S. deferred tax assets. The Company has not revised any other 2017 provisional estimates under Staff Accounting Bulletin No. 118, but is continuing to gather information and awaits further guidance from the IRS, SEC and FASB on the Act.
Apache and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. The Company is currently under IRS audit for the 2014-2016 tax years and is also under audit in various states and foreign jurisdictions as part of its normal course of business.
8.
DEBT AND FINANCING COSTS
The following table presents the carrying amounts and estimated fair values of the Company’s outstanding debt as of September 30, 2018 and December 31, 2017:
 
 
 
September 30, 2018
 
December 31, 2017
 
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
 
(In millions)
Commercial paper and committed bank facilities
 
$

 
$

 
$

 
$

Notes and debentures
 
8,203

 
8,293

 
8,484

 
9,244

Total Debt
 
$
8,203

 
$
8,293

 
$
8,484

 
$
9,244

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

16



The following table presents the carrying value of the Company’s debt as of September 30, 2018 and December 31, 2017:
 
 
September 30, 2018
 
December 31, 2017
 
 
(In millions)
Debt before unamortized discount and deferred loan costs
 
$
8,299

 
$
8,580

Unamortized discount
 
(45
)
 
(47
)
Debt issuance costs
 
(51
)
 
(49
)
Total debt
 
8,203

 
8,484

Current maturities
 
(150
)
 
(550
)
Long-term debt
 
$
8,053

 
$
7,934

As of September 30, 2018, current debt included $150 million of 7.625% senior notes due July 1, 2019. As of December 31, 2017, current debt included $150 million of 7.0% senior notes due February 1, 2018 that matured and were timely repaid and $400 million of 6.9% senior notes due September 15, 2018 that matured and were timely repaid.
On August 23, 2018, Apache closed an offering of $1.0 billion in aggregate principal amount of senior unsecured 4.375% notes due October 15, 2028. The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers, repay notes that matured in September 2018, and for general corporate purposes.
On August 24, 2018, the Company closed cash tender offers for certain outstanding notes. Apache accepted for purchase $731 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate of approximately $828 million reflecting principal, the discount to par, early tender premium, and accrued and unpaid interest. The Company recorded a net loss of $94 million on extinguishment of debt, including $5 million of unamortized debt issuance costs and discount, in connection with the note purchases.
In March 2018, the Company entered into a revolving credit facility that matures in March 2023 (subject to Apache’s two, one-year extension options) with commitments totaling $4.0 billion. The Company can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of September 30, 2018. The facility is for general corporate purposes and committed borrowing capacity fully supports Apache’s commercial paper program. As of September 30, 2018, letters of credit aggregating approximately £129.1 million and no borrowings were outstanding under this facility. In connection with entry into this facility, Apache terminated $3.5 billion and £900 million in commitments under two former credit facilities and wrote off $4 million of associated debt issuance costs, which is included in “Financing costs, net” in the Company’s consolidated statement of operations.
The Company’s $3.5 billion commercial paper program, which is subject to market availability, facilitates Apache borrowing funds for up to 270 days at competitive interest rates. As of September 30, 2018, the Company had no commercial paper outstanding.
Financing Costs, Net
The following table presents the components of Apache’s financing costs, net:
 
 
For the Quarter Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(In millions)
Interest expense
 
$
113

 
$
113

 
$
335

 
$
344

Amortization of deferred loan costs
 
2

 
3

 
8

 
7

Capitalized interest
 
(11
)
 
(12
)
 
(36
)
 
(39
)
Loss on extinguishment of debt
 
94

 

 
94

 
1

Interest income
 
(6
)
 
(3
)
 
(16
)
 
(13
)
Financing costs, net
 
$
192

 
$
101

 
$
385

 
$
300


17



9.
COMMITMENTS AND CONTINGENCIES
Legal Matters
Apache is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls. As of September 30, 2018, the Company has an accrued liability of approximately $39 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. Apache’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to Apache’s financial position, results of operations, or liquidity after consideration of recorded accruals. For material matters that Apache believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.
For additional information on each of the Legal Matters described below, please see Note 10—Commitments and Contingencies to the consolidated financial statements contained in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017.
Argentine Environmental Claims and Argentina Tariff
No material change in the status of the YPF Sociedad Anónima and Pioneer Natural Resources Company indemnities matters has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017.
Louisiana Restoration 
As more fully described in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, Louisiana surface owners often file lawsuits or assert claims against oil and gas companies, including Apache, claiming that operators and working interest owners in the chain of title are liable for environmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to its original condition, regardless of the value of the underlying property. From time to time restoration lawsuits and claims are resolved by the Company for amounts that are not material to the Company, while new lawsuits and claims are asserted against the Company. With respect to each of the pending lawsuits and claims, the amount claimed is not currently determinable or is not material, except as noted. Further, the overall exposure related to these lawsuits and claims is not currently determinable. While an adverse judgment against Apache is possible, Apache intends to actively defend these lawsuits and claims.
Starting in November of 2013 and continuing into 2018, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including Apache. These cases have all been removed to federal court after having once been remanded back to state court. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. While an adverse judgment against Apache might be possible, Apache intends to vigorously oppose these claims.
No other material change in the status of these matters has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017.
Apollo Exploration Lawsuit
In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and areas of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The Court granted motions filed by Apache reducing the plaintiffs’ alleged damages to an amount that is not material to the Company. Apache believes that plaintiffs’ claims lack merit and will vigorously oppose the claims. No other material change in the status of these matters has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017.

18



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 9th Circuit Court of Appeals. Apache believes that the claims made against it are baseless and intends to vigorously defend these lawsuits.
Environmental Matters
As of September 30, 2018, the Company had an undiscounted reserve for environmental remediation of approximately $4 million. The Company is not aware of any environmental claims existing as of September 30, 2018, that have not been provided for or that would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.
Commitments
During the third quarter of 2018, the Company executed a 10-year firm transportation agreement associated with the third-party Permian Highway Pipeline project to transport a minimum of 500,000 MMBtu per day at a fixed rate per MMBtu. The fees will commence when the pipeline accepts first commercial delivery, which is expected to begin service in late 2020, assuming timely receipt of regulatory approvals. Apache has entered into no other material commitments since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017.
10.
CAPITAL STOCK
Net Income per Common Share
A reconciliation of the components of basic and diluted net income per common share for the quarters and nine months ended September 30, 2018 and 2017, is presented in the table below.
 
 
 
For the Quarter Ended September 30,
 
 
2018
 
2017
 
 
Income
 
Shares
 
Per Share
 
Income
 
Shares
 
Per Share
 
 
(In millions, except per share amounts)
Basic:
 
 
 
 
 
 
 
 
 
 
 
 
Income attributable to common stock
 
$
81

 
383

 
$
0.21

 
$
63

 
381

 
$
0.16

Effect of Dilutive Securities:
 
 
 
 
 
 
 
 
 
 
 
 
Stock options and other
 
$


2


$

 
$

 
2

 
$

Diluted:
 
 
 
 
 
 
 
 
 
 
 
 
Income attributable to common stock
 
$
81

 
385

 
$
0.21

 
$
63

 
383

 
$
0.16



19



 
 
For the Nine Months Ended September 30,
 
 
2018
 
2017
 
 
Income
 
Shares
 
Per Share
 
Income
 
Shares
 
Per Share
 
 
(In millions, except per share amounts)
Basic:
 
 
 
 
 
 
 
 
 
 
 
 
Income attributable to common stock
 
$
421

 
383

 
$
1.10

 
$
848

 
381

 
$
2.23

Effect of Dilutive Securities:
 
 
 
 
 
 
 
 
 
 
 
 
Stock options and other
 
$

 
2

 
$
(0.01
)
 
$

 
2

 
$
(0.01
)
Diluted:
 
 
 
 
 
 
 
 
 
 
 
 
Income attributable to common stock
 
$
421

 
385

 
$
1.09

 
$
848

 
383

 
$
2.22

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 4.9 million and 8.4 million for the quarters ended September 30, 2018 and 2017, respectively, and 5.8 million and 7.5 million for the nine months ended September 30, 2018 and 2017, respectively.
Common Stock Dividends
For the quarters ended September 30, 2018 and 2017, Apache paid $96 million and $95 million, respectively, in dividends on its common stock. For the nine months ended September 30, 2018 and 2017, the Company paid $287 million and $285 million, respectively.
Stock Repurchase Program
In 2013 and 2014, Apache’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. Shares may be purchased either in the open market or through privately negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through September 30, 2018, had repurchased a total of 33.1 million shares at an average price of $87.77 per share. During the third quarter of 2018, the Company repurchased a total of 0.9 million shares at an average price of $46.38 per share. On October 30, 2018, the Company’s Board of Directors authorized the purchase of up to 40 million additional shares of the Company’s common stock. The Company is not obligated to acquire any specific number of shares.

20



11.
BUSINESS SEGMENT INFORMATION
Apache is engaged in a single line of business. Both domestically and internationally, the Company explores for, develops, and produces natural gas, crude oil, and natural gas liquids. At September 30, 2018, the Company had production in three reporting segments: the U.S., Egypt, and offshore the U.K. in the North Sea. Apache also has exploration interests in Suriname that may, over time, result in a reportable discovery and development opportunity. Financial information for each area is presented below:
 
 
United
States
 
Canada(1)
 
Egypt(2,3)
 
North Sea
 
Other
International
 
Total
 
 
(In millions)
For the Quarter Ended September 30, 2018
 
 
 
 
 
 
 
 
 
 
 

Oil revenues
 
$
583

 
$

 
$
669

 
$
303

 
$

 
$
1,555

Natural gas revenues
 
125

 

 
86

 
30

 

 
241

Natural gas liquids revenues
 
171

 

 
4

 
5

 

 
180

Total Oil and Gas Production Revenues
 
$
879

 
$

 
$
759

 
$
338

 
$

 
$
1,976

Operating Income (Loss)(4)
 
$
147

 
$

 
$
438

 
$
114

 
$
(1
)
 
$
698

Other Income (Expense):
 
 
 
 
 
 
 
 
 
 
 
 
Gain on divestitures, net
 
 
 
 
 
 
 
 
 
 
 
1

Derivative instrument losses, net
 
 
 
 
 
 
 
 
 
 
 
(23
)
Other(5)
 
 
 
 
 
 
 
 
 
 
 
29

General and administrative
 
 
 
 
 
 
 
 
 
 
 
(99
)
Transaction, reorganization, and separation
 
 
 
 
 
 
 
 
 
 
 
(8
)
Financing costs, net
 
 
 
 
 
 
 
 
 
 
 
(192
)
Income Before Income Taxes
 
 
 
 
 
 
 
 
 
 
 
$
406

 
 
 
 
 
 
 
 
 
 
 
 
 
For the Nine Months Ended September 30, 2018
 
 
 
 
 
 
 
 
 
 
 
 
Oil revenues
 
$
1,743

 
$

 
$
1,887

 
$
894

 
$

 
$
4,524

Natural gas revenues
 
331

 

 
263

 
81

 

 
675

Natural gas liquids revenues
 
421

 

 
11

 
14

 

 
446

Total Oil and Gas Production Revenues
 
$
2,495

 
$

 
$
2,161

 
$
989

 
$

 
$
5,645

Operating Income (Loss)(4)
 
$
523

 
$

 
$
1,176

 
$
327

 
$
(3
)
 
$
2,023

Other Income (Expense):
 
 
 
 
 
 
 
 
 
 
 
 
Gain on divestitures, net
 
 
 
 
 
 
 
 
 
 
 
10

Derivative instrument losses, net
 
 
 
 
 
 
 
 
 
 
 
(46
)
Other(5)
 
 
 
 
 
 
 
 
 
 
 
50

General and administrative
 
 
 
 
 
 
 
 
 
 
 
(330
)
Transaction, reorganization, and separation
 
 
 
 
 
 
 
 
 
 
 
(20
)
Financing costs, net
 
 
 
 
 
 
 
 
 
 
 
(385
)
Income Before Income Taxes
 
 
 
 
 
 
 
 
 
 
 
$
1,302

Total Assets
 
$
14,389

 
$

 
$
4,404

 
$
3,033

 
$
44

 
$
21,870

 
 
 
 
 
 
 
 
 
 
 
 
 

21



 
 
United
States
 
Canada(1)
 
Egypt(2)
 
North Sea
 
Other
International
 
Total
 
 
(In millions)
For the Quarter Ended September 30, 2017
 
 
 
 
 
 
 
 
 
 
 
 
Oil revenues
 
$
381

 
$
14

 
$
442

 
$
233

 
$

 
$
1,070

Natural gas revenues
 
97

 
19

 
98

 
24

 

 
238

Natural gas liquids revenues
 
72

 
3

 
3

 
3

 

 
81

Total Oil and Gas Production Revenues
 
$
550

 
$
36

 
$
543

 
$
260

 
$

 
$
1,389

Operating Income (Loss)(6)
 
$
(114
)
 
$
(1
)
 
$
226

 
$
16

 
$
(1
)
 
$
126

Other Income (Expense):
 
 
 
 
 
 
 
 
 
 
 
 
Gain on divestitures, net
 
 
 
 
 
 
 
 
 
 
 
296

Derivative instrument losses, net
 
 
 
 
 
 
 
 
 
 
 
(110
)
General and administrative
 
 
 
 
 
 
 
 
 
 
 
(98
)
Transaction, reorganization, and separation
 
 
 
 
 
 
 
 
 
 
 
(20
)
Financing costs, net
 
 
 
 
 
 
 
 
 
 
 
(101
)
Income Before Income Taxes
 
 
 
 
 
 
 
 
 
 
 
$
93

 
 
 
 
 
 
 
 
 
 
 
 
 
For the Nine Months Ended September 30, 2017
 
 
 
 
 
 
 
 
 
 
 
 
Oil revenues
 
$
1,133

 
$
110

 
$
1,351

 
$
698

 
$

 
$
3,292

Natural gas revenues
 
266

 
104

 
295

 
61

 

 
726

Natural gas liquids revenues
 
194

 
17

 
9

 
9

 

 
229

Total Oil and Gas Production Revenues
 
$
1,593

 
$
231

 
$
1,655

 
$
768

 
$

 
$
4,247

Operating Income (Loss)(6)
 
$
(71
)
 
$
(33
)
 
$
740

 
$
59

 
$
(24
)
 
$
671

Other Income (Expense):
 
 
 
 
 
 
 
 
 
 
 
 
Gain on divestitures, net
 
 
 
 
 
 
 
 
 
 
 
616

Derivative instrument losses, net
 
 
 
 
 
 
 
 
 
 
 
(69
)
Other
 
 
 
 
 
 
 
 
 
 
 
43

General and administrative
 
 
 
 
 
 
 
 
 
 
 
(307
)
Transaction, reorganization, and separation
 
 
 
 
 
 
 
 
 
 
 
(14
)
Financing costs, net
 
 
 
 
 
 
 
 
 
 
 
(300
)
Income Before Income Taxes
 
 
 
 
 
 
 
 
 
 
 
$
640

Total Assets
 
$
13,105

 
$

 
$
4,906

 
$
3,770

 
$
54

 
$
21,835

(1)
Apache exited its Canadian operations in the third quarter of 2017.
(2)
Includes a noncontrolling interest in Egypt.
(3)
Includes revenue from non-customers of $181 million, $16 million, and $1 million for oil, natural gas, and natural gas liquids, respectively, for the third quarter of 2018, and $485 million, $47 million, and $2 million, for oil, natural gas, and natural gas liquids, respectively, for the first nine months of 2018.
(4)
Operating income (loss) consists of oil and gas production revenues less lease operating expenses, gathering, transmission, and processing costs, taxes other than income, exploration costs, depreciation, depletion, and amortization, asset retirement obligation accretion, and impairments. The operating income of U.S. and North Sea includes leasehold and unproved impairments totaling $39 million and $10 million, respectively, for the third quarter of 2018. The operating income of U.S. and North Sea includes leasehold and unproved impairments totaling $76 million and $10 million, respectively, for the first nine months of 2018.
(5)
Included in Other are sales proceeds related to U.S. third-party purchased oil and gas totaling $124 million and $326 million for the third quarter and first nine months of 2018, respectively, which are determined to be revenue from customers.
(6)
The operating income (loss) of U.S. includes leasehold impairments totaling $160 million for the third quarter of 2017. The operating income (loss) of U.S., Canada, and North Sea includes leasehold and other asset impairments totaling $212 million, $2 million, and $8 million, respectively, for the first nine months of 2017.

22



ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion relates to Apache Corporation and its consolidated subsidiaries and should be read in conjunction with the Company’s consolidated financial statements and accompanying notes included under Part I, Item 1, “Financial Statements” of this Quarterly Report on Form 10-Q, as well as the Company’s consolidated financial statements, accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017.
Overview
Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. Apache currently has exploration and production operations in three geographic areas: the United States (U.S.), Egypt, and offshore the United Kingdom (U.K.) in the North Sea (North Sea). Apache also has exploration interests in Suriname that may, over time, result in a reportable discovery and development opportunity. In the third quarter of 2017, Apache completed the sale of its Canadian operations.
Apache reported third quarter net income of $81 million, or $0.21 per common share, an increase of $18 million, or $0.05 per common share, from the third quarter of 2017. The increase was driven by higher crude oil and natural gas liquid (NGL) price realizations and production, which more than offset the decrease related to a $296 million gain from asset sales benefiting the third quarter of 2017 and a $94 million charge for early extinguishment of debt in the third quarter of 2018.
Daily equivalent production in the third quarter of 2018 averaged 476 Mboe/d, an increase of 6 percent from the comparative prior-year quarter. Excluding asset divestitures, daily equivalent production increased 12 percent driven by the activity in the Permian Basin, including continued development of the Company’s Alpine High field and infrastructure. Realized oil prices have been considerably higher than budgeted this year, particularly Dated Brent, which has provided increased operating cash flow to reinvest in the Company’s core development areas without a material impact on its balance sheet.
The Company generated $2.7 billion in cash from operating activities during the first nine months of 2018, a 55 percent increase from the comparable prior-year period, and ended the quarter with $593 million of cash on hand. During the quarter, the Company took several steps to improve its debt portfolio: issuing $1.0 billion in aggregate principal amount of senior unsecured notes, concurrently repurchasing $731 million in aggregate principal amount of certain other outstanding notes, and paying off an additional $400 million of maturing debt in September. These transactions extended debt maturities, reduced the Company’s cost of debt, modernized its standard debenture terms, and, in conjunction with the repayment of $150 million of maturing debt in February, reduced debt by $281 million from 2017 year-end levels. During the quarter, the Company also re-initiated share repurchase activity under its existing authorization, which had 6.9 million shares remaining at the end of the quarter. In late October, the Company’s Board of Directors authorized the purchase of an additional 40 million shares of the Company’s common stock.
Apache achieved an important milestone during the third quarter with the announcement of Altus Midstream Company. This transaction enables Apache to maintain control of the midstream infrastructure buildout and establishes an entity capable of funding all future midstream investment at a lower cost of capital. For further information regarding this transaction, refer to “Operating Highlights” below.
Operating Highlights
Key operational highlights for the quarter include:
United States
U.S. onshore equivalent production increased 32 percent from the third quarter of 2017, a reflection of the success of the Midland Basin drilling program and the commencement and continued production ramp-up of the Company’s Alpine High development.
Third-quarter equivalent production from the Permian region, which accounts for 82 percent of Apache’s total U.S. production, increased 38 percent from the third quarter of 2017, driven by the Alpine High discovery and strong performance in the Midland Basin. Crude oil production in the region increased 16 percent between the comparative quarters.
In August 2018, the Company announced an agreement with Kayne Anderson Acquisition Corp. (KAAC) to create Altus Midstream Company (Altus Midstream).
Upon closing of the transaction, KAAC will contribute approximately $952 million of cash, less anticipated transaction costs and any amount associated with potential shareholder redemptions, into a newly formed

23



limited partnership, Altus Midstream LP, for an approximate 29 percent noncontrolling interest, adjusted accordingly for any KAAC share redemptions. The cash will fund future development of the Alpine High midstream assets.
Upon closing, Apache will contribute its Alpine High midstream assets, and Altus Midstream or its subsidiaries will hold options to acquire a noncontrolling equity participation in five planned long-haul pipelines from the Permian Basin to various points along the Texas Gulf Coast including the previously announced Gulf Coast Express, Salt Creek NGL Line, EPIC Crude, Shin Oak, and Permian Highway Pipeline projects.
In exchange for such contributions, Apache will receive an approximate 71 percent controlling ownership interest in Altus Midstream, adjusted accordingly for any KAAC share redemptions.
The transaction is subject to approval by KAAC shareholders, as well as other customary closing conditions. Closing is expected in the fourth quarter of 2018.
Drilling and infrastructure development activities continue at Alpine High; specifically:
First production from the Alpine High play was achieved in early May 2017. Net production for the third quarter of 2018 averaged approximately 48.8 Mboe/d, up from 19.8 Mboe/d for the fourth quarter of 2017.
During the third quarter of 2018, Apache invested $120 million in Alpine High infrastructure, with development ongoing. Inception-to-date investment in Alpine High infrastructure as of quarter-end was $1.1 billion.
International
The Egypt region averaged 12 rigs and drilled or participated in drilling 26 gross wells during the third quarter of 2018. Gross production remained relatively flat and cash flows for the region increased compared to the third quarter of 2017 despite a 3 percent decrease in net equivalent production, a result of the impact of higher Brent oil prices on cost recovery volumes as a function of the Company’s production sharing contracts.
The North Sea region average daily production decreased 15 percent from the third quarter of 2017 primarily as a result of natural decline. Production is expected to increase in the fourth quarter, as the Company brought its fourth development well online in the Callater field in September and plans to accelerate initial production at Garten from the first quarter of 2019 to the fourth quarter of 2018, only seven months after its discovery.


24



Results of Operations
Oil and Gas Revenues
The table below presents the third-quarter and year-to-date 2018 and 2017 revenues by geographic region and each region’s percent contribution to revenues.
 
 
For the Quarter Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
$
Value
 
%
Contribution
 
$
Value
 
%
Contribution
 
$
Value
 
%
Contribution
 
$
Value
 
%
Contribution
 
 
($ in millions)
Total Oil Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
$
583

 
37
%
 
$
381

 
36
%
 
$
1,743

 
39
%
 
$
1,133

 
35
%
Canada
 

 

 
14

 
1
%
 

 

 
110

 
3
%
North America
 
583

 
37
%
 
395

 
37
%
 
1,743

 
39
%
 
1,243

 
38
%
Egypt (1)
 
669

 
43
%
 
442

 
41
%
 
1,887

 
41
%
 
1,351

 
41
%
North Sea
 
303

 
20
%
 
233

 
22
%
 
894

 
20
%
 
698

 
21
%
International (1)
 
972

 
63
%
 
675

 
63
%
 
2,781

 
61
%
 
2,049

 
62
%
Total (1)
 
$
1,555

 
100
%
 
$
1,070

 
100
%
 
$
4,524

 
100
%
 
$
3,292

 
100
%
Total Natural Gas Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
$
125

 
52
%
 
$
97

 
41
%
 
$
331

 
49
%
 
$
266

 
37
%
Canada
 

 

 
19

 
8
%
 

 

 
104

 
14
%
North America
 
125

 
52
%
 
116

 
49
%
 
331

 
49
%
 
370

 
51
%
Egypt (1)
 
86

 
36
%
 
98

 
41
%
 
263

 
39
%
 
295

 
41
%
North Sea
 
30

 
12
%
 
24

 
10
%
 
81

 
12
%
 
61

 
8
%
International (1)
 
116

 
48
%
 
122

 
51
%
 
344

 
51
%
 
356

 
49
%
Total (1)
 
$
241

 
100
%
 
$
238

 
100
%
 
$
675

 
100
%
 
$
726

 
100
%
Total Natural Gas Liquids (NGL) Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
$
171

 
95
%
 
$
72

 
89
%
 
$
421

 
94
%
 
$
194

 
85
%
Canada
 

 

 
3

 
4
%
 

 

 
17

 
7
%
North America
 
171

 
95
%
 
75

 
93
%
 
421

 
94
%
 
211

 
92
%
Egypt (1)
 
4

 
2
%
 
3

 
4
%
 
11

 
3
%
 
9

 
4
%
North Sea
 
5

 
3
%
 
3

 
3
%
 
14

 
3
%
 
9

 
4
%
International (1)
 
9

 
5
%
 
6

 
7
%
 
25

 
6
%
 
18

 
8
%
Total (1)
 
$
180

 
100
%
 
$
81

 
100
%
 
$
446

 
100
%
 
$
229

 
100
%
Total Oil and Gas Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
$
879

 
44
%
 
$
550

 
40
%
 
$
2,495

 
44
%
 
$
1,593

 
38
%
Canada
 

 

 
36

 
2
%
 

 

 
231

 
5
%
North America
 
879

 
44
%
 
586

 
42
%
 
2,495

 
44
%
 
1,824

 
43
%
Egypt (1)
 
759

 
39
%
 
543

 
39
%
 
2,161

 
38
%
 
1,655

 
39
%
North Sea
 
338

 
17
%
 
260

 
19
%
 
989

 
18
%
 
768

 
18
%
International (1)
 
1,097

 
56
%
 
803

 
58
%
 
3,150

 
56
%
 
2,423

 
57
%
Total (1)
 
$
1,976

 
100
%
 
$
1,389

 
100
%
 
$
5,645

 
100
%
 
$
4,247

 
100
%
(1)
Includes revenues attributable to a noncontrolling interest in Egypt.





25



Production
The table below presents the third-quarter and year-to-date 2018 and 2017 production and the relative increase or decrease from the prior period.
 
 
For the Quarter Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2018
 
Increase
(Decrease)
 
2017
 
2018
 
Increase
(Decrease)
 
2017
Oil Volume – b/d
 
 
 

 
 
 
 
 
 
 
 
United States
 
103,538

 
14
 %
 
90,883

 
102,830

 
15
 %
 
89,228

Canada
 

 
NM
 
3,441

 

 
NM
 
8,881

North America
 
103,538

 
10
 %
 
94,324

 
102,830

 
5
 %
 
98,109

Egypt(1)(2)
 
97,129

 
4
 %
 
93,749

 
96,201

 
(1
)%
 
97,447

North Sea
 
42,769

 
(14
)%
 
49,945

 
45,076

 
(9
)%
 
49,274

International
 
139,898

 
(3
)%
 
143,694

 
141,277

 
(4
)%
 
146,721

Total
 
243,436

 
2
 %
 
238,018

 
244,107

 
 %
 
244,830

Natural Gas Volume – Mcf/d
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
651,782

 
61
 %
 
404,486

 
563,299

 
49
 %
 
378,625

Canada
 

 
NM
 
107,524

 

 
NM
 
175,787

North America
 
651,782

 
27
 %
 
512,010

 
563,299

 
2
 %
 
554,412

Egypt(1)(2)
 
331,681

 
(12
)%
 
378,426

 
338,813

 
(13
)%
 
389,533

North Sea
 
41,455

 
(17
)%
 
50,057

 
41,932

 
(2
)%
 
42,800

International
 
373,136

 
(13
)%
 
428,483

 
380,745

 
(12
)%
 
432,333

Total
 
1,024,918

 
9
 %
 
940,493

 
944,044

 
(4
)%
 
986,745

NGL Volume – b/d
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
60,239

 
23
 %
 
49,149

 
56,886

 
18
 %
 
48,063

Canada
 

 
NM
 
2,183

 

 
NM
 
3,780

North America
 
60,239

 
17
 %
 
51,332

 
56,886

 
10
 %
 
51,843

Egypt(1)(2)
 
753

 
(18
)%
 
916

 
939

 
2
 %
 
917

North Sea
 
1,008

 
(17
)%
 
1,219

 
1,092

 
5
 %
 
1,044

International
 
1,761

 
(18
)%
 
2,135

 
2,031

 
4
 %
 
1,961

Total
 
62,000

 
16
 %
 
53,467

 
58,917

 
10
 %
 
53,804

BOE per day(3)
 
 
 

 
 
 
 
 
 
 
 
United States
 
272,406

 
31
 %
 
207,447

 
253,599

 
27
 %
 
200,396

Canada
 

 
NM
 
23,544

 

 
NM
 
41,959

North America
 
272,406

 
18
 %
 
230,991

 
253,599

 
5
 %
 
242,355

Egypt(2)
 
153,163

 
(3
)%
 
157,737

 
153,609

 
(6
)%
 
163,286

North Sea(4)
 
50,686

 
(15
)
 
59,507

 
53,157

 
(7
)%
 
57,451

International
 
203,849

 
(6
)%
 
217,244

 
206,766

 
(6
)%
 
220,737

Total
 
476,255

 
6
 %
 
448,235

 
460,365

 
(1
)%
 
463,092

 
(1)
Gross oil, natural gas, and NGL production in Egypt for the third quarter and nine-month period of 2018 and 2017 were as follows:
 
 
For the Quarter Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2018
 
2017
 
2018
 
2017
Oil (b/d)
 
208,889

 
201,151

 
205,822

 
196,781

Natural Gas (Mcf/d)
 
766,128

 
818,350

 
775,405

 
813,880

NGL (b/d)
 
1,161

 
1,526

 
1,450

 
1,514

 
(2)
Includes production volumes per day attributable to a noncontrolling interest in Egypt for the third quarter and nine-month period of 2018 and 2017 of:
 
 
For the Quarter Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2018
 
2017
 
2018
 
2017
Oil (b/d)
 
32,385

 
31,275

 
32,077

 
32,573

Natural Gas (Mcf/d)
 
110,777

 
126,459

 
113,164

 
130,263

NGL (b/d)
 
251

 
305

 
313

 
306

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

(4)
Average sales volumes from the North Sea for the third quarter of 2018 and 2017 were 51,765 boe/d and 57,207 boe/d, respectively, and 53,985 boe/d and 57,963 boe/d for the first nine months of 2018 and 2017, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

NM — Not meaningful

26



Pricing
The table below presents third-quarter and year-to-date 2018 and 2017 pricing and the relative increase or decrease from the prior period.
 
 
 
For the Quarter Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2018
 
Increase
(Decrease)
 
2017
 
2018
 
Increase
(Decrease)
 
2017
Average Oil Price - Per barrel
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
$
61.20

 
34
 %
 
$
45.68

 
$
62.08

 
33
 %
 
$
46.54

Canada
 

 
NM
 
42.23

 

 
NM
 
45.25

North America
 
61.20

 
34
 %
 
45.56

 
62.08

 
34
 %
 
46.42

Egypt
 
74.92

 
46
 %
 
51.23

 
71.85

 
41
 %
 
50.78

North Sea
 
75.01

 
41
 %
 
53.11

 
71.32

 
39
 %
 
51.35

International
 
74.95

 
44
 %
 
51.87

 
71.68

 
41
 %
 
50.97

Total
 
69.12

 
40
 %
 
49.34

 
67.65

 
38
 %
 
49.15

Average Natural Gas Price - Per Mcf
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
$
2.09

 
(20
)%
 
$
2.62

 
$
2.15

 
(17
)%
 
$
2.58

Canada
 

 
NM
 
1.90

 

 
NM
 
2.17

North America
 
2.09

 
(15
)%
 
2.47

 
2.15

 
(12
)%
 
2.45

Egypt
 
2.85

 
1
 %
 
2.81

 
2.85

 
3
 %
 
2.77

North Sea
 
7.78

 
48
 %
 
5.27

 
7.07

 
34
 %
 
5.27

International
 
3.40

 
10
 %
 
3.10

 
3.31

 
10
 %
 
3.02

Total
 
2.56

 
(7
)%
 
2.75

 
2.62

 
(3
)%
 
2.70

Average NGL Price - Per barrel
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
$
30.84

 
96
 %
 
$
15.77

 
$
27.15

 
84
 %
 
$
14.75

Canada
 

 
NM
 
15.80

 

 
NM
 
16.39

North America
 
30.84

 
96
 %
 
15.77

 
27.15

 
83
 %
 
14.87

Egypt
 
45.92

 
26
 %
 
36.47

 
40.67

 
13
 %
 
35.98

North Sea
 
54.73

 
103
 %
 
26.92

 
47.16

 
55
 %
 
30.51

International
 
50.96

 
64
 %
 
31.02

 
44.16

 
34
 %
 
33.07

Total
 
31.42

 
92
 %
 
16.38

 
27.74

 
79
 %
 
15.53

NM — Not meaningful
Third-Quarter 2018 compared to Third-Quarter 2017
Crude Oil Revenues Crude oil revenues for the third quarter of 2018 totaled $1.6 billion, a $485 million increase from the comparative 2017 quarter. A 40 percent increase in average realized prices increased third-quarter 2018 revenues by $429 million compared to the prior-year quarter, while 2 percent higher average daily production increased revenues by $56 million. Crude oil accounted for 79 percent of oil and gas production revenues and 51 percent of worldwide production in the third quarter of 2018. Crude oil prices realized in the third quarter of 2018 averaged $69.12 per barrel, compared with $49.34 per barrel in the comparative prior-year quarter.
Worldwide oil production increased 5.4 Mb/d to 243.4 Mb/d in the third quarter of 2018 from the comparative prior-year period, primarily a result of an increase in Apache’s Permian region on the success of the Midland and Delaware basin drilling programs, partially offset by a decrease from natural decline in the North Sea.
Natural Gas Revenues Gas revenues for the third quarter of 2018 totaled $241 million, a $3 million increase from the comparative 2017 quarter. A 7 percent decrease in average realized prices decreased third-quarter revenues by $17 million compared to the prior-year quarter, while 9 percent higher average daily production increased revenues by $20 million. Natural gas accounted for 12 percent of Apache’s oil and gas production revenues and 36 percent of its equivalent production during the third quarter of 2018.

27



Worldwide natural gas production increased 84 MMcf/d to 1,025 MMcf/d in the third quarter of 2018 from the comparative prior-year period, primarily a result of an increase in Apache’s Permian region on the success of the Midland and Delaware basin drilling programs and the commencement of Alpine High production.
NGL Revenues NGL revenues for the third quarter of 2018 totaled $180 million, a $99 million increase from the comparative 2017 quarter. A 92 percent increase in average realized prices increased third-quarter 2018 revenues by approximately $74 million compared to the prior-year quarter, while 16 percent higher average daily production increased revenues by approximately $25 million. Approximately half of the increase in realized prices is the result of the reclassification of certain transportation charges from revenues to Gathering, Transmission, and Processing (GTP) expense as a result of the adoption of new revenue recognition accounting rules effective January 1, 2018. NGLs accounted for 9 percent of Apache’s oil and gas production revenues and 13 percent of its equivalent production during the third quarter of 2018.
Worldwide production of NGLs increased 8.5 Mb/d to 62.0 Mb/d in the third quarter of 2018 from the comparative prior-year period, primarily a result of the commencement of Alpine High production.
Year-to-Date 2018 compared to Year-to-Date 2017
Crude Oil Revenues Crude oil revenues for the first nine months of 2018 totaled $4.5 billion, a $1.2 billion increase from the comparative 2017 period. A 38 percent increase in average realized prices increased 2018 oil revenues by $1.2 billion compared to the prior-year period, while average daily production remained relatively flat. Crude oil accounted for 80 percent of oil and gas production revenues and 53 percent of worldwide production for the first nine months of 2018, compared to 78 percent and 53 percent, respectively, for the 2017 period. Crude oil prices realized in the first nine months of 2018 averaged $67.65 per barrel, compared with $49.15 per barrel in the comparative prior-year period.
Worldwide production decreased 0.7 Mb/d to 244.1 Mb/d in the first nine months of 2018 from the comparative prior-year period, primarily a result of a decrease from Apache’s exit from Canada, partially offset by an increase in its Permian region on the success of the Midland and Delaware basin drilling programs.
Natural Gas Revenues Gas revenues for the first nine months of 2018 totaled $675 million, a $51 million decrease from the comparative 2017 period. A 3 percent decrease in average realized prices decreased 2018 natural gas revenues by $20 million compared to the prior-year period, while 4 percent lower average daily production decreased revenues by $31 million. Natural gas accounted for 12 percent of the Company’s oil and gas production revenues and 34 percent of Apache’s equivalent production for the first nine months of 2018, compared to 17 percent and 36 percent, respectively, for the 2017 period.
Worldwide natural gas production decreased 42.7 MMcf/d to 944 MMcf/d in the first nine months of 2018 from the comparative prior-year period, primarily a result of Apache’s exit from Canada, partially offset by an increase from Alpine High production.
NGL Revenues NGL revenues for the first nine months of 2018 totaled $446 million, a $217 million increase from the comparative 2017 period. A 79 percent increase in average realized prices increased 2018 NGL revenues by $179 million compared to the prior-year period, while a 10 percent increase in average daily production increased revenues by $38 million. The increase in realized prices is primarily the result of the reclassification of certain transportation charges from revenues to GTP expense as a result of the adoption of new revenue recognition rules effective January 1, 2018. NGLs accounted for nearly 8 percent of the Company’s oil and gas production revenues and 13 percent of Apache’s equivalent production for the first nine months of 2018, compared to 5 percent and 11 percent, respectively, for the 2017 period.
Worldwide production of NGLs increased 5.1 Mb/d to 58.9 Mb/d in the first nine months of 2018 from the comparative prior-year period, primarily a result of an increase in Apache’s Permian region on the success of the Midland and Delaware basin drilling programs and the commencement of Alpine High production, more than offsetting a decrease from Apache’s exit from Canada.

28



Operating Expenses
The table below presents a comparison of Apache’s expenses on an absolute dollar basis and a boe basis. Apache’s discussion may reference expenses on a boe basis, on an absolute dollar basis or both, depending on their relevance. Operating expenses include costs attributable to a noncontrolling interest in Egypt.
 
 
 
For the Quarter Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
 
 
(In millions)
 
(Per boe)
 
(In millions)
 
(Per boe)
Lease operating expenses(1)
 
$
382

 
$
353

 
$
8.69

 
$
8.62

 
$
1,087

 
$
1,059

 
$
8.63

 
$
8.37

Gathering, transmission, and processing(1)
 
92

 
44

 
2.10

 
1.03

 
260

 
151

 
2.06

 
1.19

Taxes other than income
 
58

 
46

 
1.31

 
1.12

 
162

 
117

 
1.29

 
0.93

Exploration
 
99

 
231

 
2.26

 
5.60

 
251

 
431

 
2.00

 
3.41

General and administrative
 
99

 
98

 
2.25

 
2.39

 
330

 
307

 
2.62

 
2.43

Transaction, reorganization, and separation
 
8

 
20

 
0.19

 
0.48

 
20

 
14

 
0.16

 
0.11

Depreciation, depletion, and amortization:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil and gas property and equipment(1)
 
575

 
524

 
13.10

 
12.76

 
1,666

 
1,598

 
13.23

 
12.63

Other assets
 
35

 
35

 
0.79

 
0.83

 
105

 
109

 
0.83

 
0.86

Asset retirement obligation accretion
 
27

 
30

 
0.62

 
0.75

 
81

 
103

 
0.64

 
0.82

Impairments
 
10

 

 
0.24

 

 
10

 
8

 
0.08

 
0.06

Financing costs, net
 
192

 
101

 
4.38

 
2.45

 
385

 
300

 
3.06

 
2.38

(1)
For expenses impacted by the timing of liftings in the North Sea, per-boe calculations are based on sales volumes rather than production volumes.
Lease Operating Expenses (LOE) LOE increased $29 million and $28 million for the third quarter and first nine months of 2018, respectively, on an absolute dollar basis relative to the comparable periods of 2017. On a per-unit basis, LOE increased 1 percent to $8.69 per boe for the third quarter of 2018, and increased 3 percent to $8.63 per boe for the first nine months of 2018 as compared to the prior-year periods. The increase on an absolute dollar basis for both comparative periods is primarily the result of general cost increases in a higher commodity price environment, partially offset by a decrease from the sale of Apache’s Canadian operations in the third quarter of 2017.
Gathering, Transmission, and Processing GTP costs totaled $92 million and $260 million in the third quarter and first nine months of 2018, respectively, an increase of $48 million from the third quarter of 2017 and $109 million from the first nine months of 2017. The increase is primarily the result of the reclassification of certain transportation charges from revenues to GTP expense as a result of the adoption of new revenue recognition accounting rules effective January 1, 2018, as well as the ramp-up of midstream operations at Alpine High, partially offset by Apache’s exit from Canada.
Taxes Other Than Income Taxes other than income totaled $58 million and $162 million for the third quarter and first nine months of 2018, an increase of $12 million and $45 million from the third quarter and first nine months of 2017, respectively. Third-quarter and year-to-date 2018 expense consists primarily of severance and ad valorem taxes, which combined increased $12 million and $30 million, respectively. The increase for both comparative periods is primarily the result of an increase in severance taxes on higher commodity prices and increased U.S. production driven by the ramp-up of operations at Alpine High. In addition, in the first nine months of 2017, Apache recognized a $14 million benefit related to the U.K. Petroleum Revenue Tax (PRT). The U.K. PRT rate, historically assessed on qualifying fields in the U.K. North Sea, was reduced to zero during 2016.

29



Exploration Expense Exploration expense includes unproved leasehold impairments, exploration dry hole expense, geological and geophysical expenses, and the costs of maintaining and retaining unproved leasehold properties. Exploration expenses in the third quarter and first nine months of 2018 decreased $132 million and $180 million, respectively, compared to the prior-year period.
The following table presents a summary of exploration expense:
 
 
For the Quarter Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(In millions)
Unproved leasehold impairments
 
$
39

 
$
160

 
$
76

 
$
214

Dry hole expense
 
21

 
38

 
57

 
136

Geological and geophysical expense
 
6

 
12

 
41

 
24

Exploration overhead and other
 
33

 
21

 
77

 
57

 
 
$
99

 
$
231

 
$
251

 
$
431

Unproved leasehold impairments in the third quarter and first nine months of 2018 decreased $121 million and $138 million, respectively, from the comparative prior-year periods, primarily a result of stabilizing commodity and leasehold prices. Dry hole expense decreased $17 million and $79 million in the third quarter and first nine months of 2018, respectively, from the comparative prior-year periods on lower exploration drilling activity. Geological and geophysical expense decreased $6 million and increased $17 million in the third quarter and first nine months of 2018, respectively, from the comparative prior-year periods. The increase in the first nine months of 2018 is primarily driven by 3-D seismic acquisition in Egypt for the Khalda Extension 3 and various other concessions.
General and Administrative (G&A) Expenses G&A expense for the third quarter and first nine months of 2018 were $1 million and $23 million higher than the comparative 2017 periods, respectively. The increase in G&A expense was primarily related to non-cash stock-based compensation expense, which was impacted by a change in vesting terms for certain retirement eligible employees.
Transaction, Reorganization, and Separation (TRS) Costs TRS costs for the third quarter of 2018 were $12 million lower than the comparative 2017 period primarily a result of costs incurred during the third quarter of 2017 associated with the Canadian divestiture. TRS costs for the first nine months of 2018 were $6 million higher than the comparative 2017 period primarily a result of an increase in the market value of stock awards outstanding for former employees.
Depreciation, Depletion, and Amortization (DD&A) Oil and gas property DD&A expense of $575 million in the third quarter of 2018 increased $51 million compared to the third quarter of 2017. For the first nine months of 2018, oil and gas property DD&A expense increased $68 million compared to the prior-year period. The Company’s oil and gas property DD&A rate increased $0.34 per boe and $0.60 per boe in the third quarter and first nine months of 2018, respectively, compared to the comparable prior-year periods. The primary factor driving higher absolute dollar expense was an increase in capital spending primarily in the Permian and Alpine High regions as a result of drilling and development activity. The increase on an absolute dollar basis was partially offset by the sale of Apache’s Canadian operations in the third quarter of 2017.
Impairments The Company recorded asset impairments totaling $10 million for each of the third quarter and first nine months of 2018 in connection with fair value assessments on North Sea unproved assets to be divested. The Company did not record any asset impairments in the third quarter of 2017. For the nine-month period ended September 30, 2017, the Company recorded asset impairments totaling $8 million for a U.K. PRT decommissioning asset that is no longer expected to be realizable from future abandonment activities in the North Sea. For more information regarding asset impairments, please refer to “Fair Value Measurements” within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q.

30



Financing Costs, Net Financing costs incurred during the period comprised the following:
 
 
 
For the Quarter Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(In millions)
Interest expense
 
$
113

 
$
113

 
$
335

 
$
344

Amortization of deferred loan costs
 
2

 
3

 
8

 
7

Capitalized interest
 
(11
)
 
(12
)
 
(36
)
 
(39
)
Loss on extinguishment of debt
 
94

 

 
94

 
1

Interest income
 
(6
)
 
(3
)
 
(16
)
 
(13
)
Financing costs, net
 
$
192

 
$
101

 
$
385

 
$
300

Net financing costs increased $91 million and $85 million in the third quarter and first nine months of 2018, respectively, compared to the same prior-year periods primarily a result of a $94 million loss on extinguishment of debt incurred in the third quarter of 2018.
Provision for Income Taxes The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments of the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur.
During the third quarter of 2018, Apache’s effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets. During the third quarter of 2017, Apache’s effective income tax rate was primarily impacted by gains on the sale of oil and gas properties, a $30 million current tax benefit associated with U.S. federal income tax credits, a deferred tax asset associated with its realizable capital loss on the sale of Apache Canada Ltd. (ACL), and a decrease in the Company’s deferred tax liability associated with its investment in foreign subsidiaries. For more information regarding the sale of ACL, please refer to Note 2—Acquisitions and Divestitures.
Apache’s 2018 year-to-date effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets. Apache’s 2017 year-to-date effective income tax rate was primarily impacted by the decrease in deferred taxes associated with its investments in foreign subsidiaries, gains on the sale of oil and gas properties, non-cash impairments of the Company’s PRT decommissioning asset, the current tax benefit associated with U.S. federal income tax credits, and the sale of ACL.
Apache recorded a full valuation allowance against its U.S. net deferred tax assets as of December 31, 2017. Apache will continue to maintain a full valuation allowance on its U.S. net deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance. However, given our current earnings and anticipated future earnings, we believe that there is a reasonable possibility that within the next 12 months, sufficient positive evidence may become available to allow us to reach a conclusion that a significant portion of the valuation allowance will no longer be needed. Release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to deferred income tax expense for the period the release is recorded. However, the exact timing and amount of the valuation allowance release are subject to change on the basis of the level of profitability that we are able to actually achieve.
On December 22, 2017, the Tax Cuts and Jobs Act (the Act) was signed into law. In 2018, the Internal Revenue Service (IRS) issued additional guidance related to the Act’s deemed repatriation of foreign earnings (i.e., transition inclusion). In light of this new guidance, the Company continues to reevaluate the tax impact of the transition inclusion in 2017. Tax benefit associated with the change in transition inclusion is likely to be fully offset by a change in the Company’s valuation allowance against its U.S. deferred tax assets. The Company has not revised any other 2017 provisional estimates under Staff Accounting Bulletin No. 118, but is continuing to gather information and awaits further guidance from the IRS, SEC and FASB on the Act.
Apache and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. The Company is currently under IRS audit for the 2014-2016 tax years and is also under audit in various states and foreign jurisdictions as part of its normal course of business.

31



Capital Resources and Liquidity
Operating cash flows are the Company’s primary source of liquidity. The Company may also elect to utilize available cash on hand, committed borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets for all other liquidity and capital resource needs.
Apache’s operating cash flows, both in the short-term and the long-term, are impacted by highly volatile oil and natural gas prices, as well as costs and sales volumes. Significant changes in commodity prices impact Apache’s revenues, earnings, and cash flows. These changes potentially impact Apache’s liquidity if costs do not trend with changes in commodity prices. Historically, costs have trended with commodity prices, albeit on a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term.
Apache’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of Apache’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves.
Apache believes the liquidity and capital resource alternatives available to the Company, combined with proactive measures to adjust its capital budget to reflect volatile commodity prices and anticipated operating cash flows, will be adequate to fund short-term and long-term operations, including Apache’s capital spending program, repayment of debt maturities, payment of dividends, any repurchases of shares of the Company’s common stock, and any amount that may ultimately be paid in connection with commitments and contingencies.
For additional information, please see Part I, Items 1 and 2, “Business and Properties,” and Item 1A, “Risk Factors,” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.
Sources and Uses of Cash
The following table presents the sources and uses of the Company’s cash, cash equivalents, and restricted cash for the periods presented.
 
 
For the Nine Months Ended September 30,
 
 
2018
 
2017
 
 
(In millions)
Sources of Cash, Cash Equivalents, and Restricted Cash:
 
 
 
 
Net cash provided by operating activities
 
$
2,734

 
$
1,760

Proceeds from sale of oil and gas properties
 
51

 
1,404

Fixed-rate debt borrowings
 
992

 

 
 
3,777

 
3,164

Uses of Cash, Cash Equivalents, and Restricted Cash:
 
 
 
 
Capital expenditures(1)
 
$
2,750

 
$
1,855

Leasehold and property acquisitions
 
86

 
142

Payments on fixed-rate debt
 
1,370

 
70

Dividends paid
 
287

 
285

Distributions to noncontrolling interest
 
256

 
212

Other
 
103

 
35

 
 
4,852

 
2,599

Increase (decrease) in cash, cash equivalents, and restricted cash
 
$
(1,075
)
 
$
565

(1)
The table presents capital expenditures on a cash basis; therefore, the amounts may differ from those discussed elsewhere in this document, which include accruals.
Net Cash Provided by Operating Activities Operating cash flows are Apache’s primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile oil and natural gas prices. The factors that determine operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation (ARO) accretion, and deferred income tax expense.

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Net cash provided by operating activities for the first nine months of 2018 totaled $2.7 billion, an increase of $974 million from the first nine months of 2017. The increase primarily reflects higher commodity prices compared to the prior-year period.
For a detailed discussion of commodity prices, production, and expenses, refer to the “Results of Operations” of this Item 2. For additional detail on the changes in operating assets and liabilities and the non-cash expenses that do not impact net cash provided by operating activities, please see the statement of consolidated cash flows in Part I, Item 1, Financial Statements of this Quarterly Report on Form 10-Q.
Asset Divestitures The Company recorded proceeds from asset divestitures totaling $51 million and $1.4 billion in the first nine months of 2018 and 2017, respectively. For more information regarding the Company’s acquisitions and divestitures, please see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q.
Fixed-Rate Debt Borrowings On August 23, 2018, Apache closed an offering of $1.0 billion in aggregate principal amount of senior unsecured 4.375% notes due October 15, 2028. The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The net proceeds from the sale of the notes of $992 million were used to purchase certain outstanding notes in cash tender offers, repay notes that matured in September 2018, and for general corporate purposes.
Capital Expenditures Worldwide exploration and development (E&D) cash expenditures for the first nine months of 2018 totaled $2.3 billion, compared to $1.5 billion for the first nine months of 2017. Expenditures for the first nine months of 2018 were primarily in the Permian region as Apache continued development of its Alpine High play. Apache operated an average of 33 drilling rigs worldwide during the third quarter of 2018.
Apache’s cash expenditures in GTP facilities totaled $412 million and $384 million in the first nine months of 2018 and 2017, respectively, and are primarily comprised of investments in infrastructure for the Alpine High play. Cash from the Altus Midstream transaction is expected to fund future development of the Company’s Alpine High midstream assets upon anticipated closing of the transaction in the fourth quarter of 2018.
Leasehold and Property Acquisitions Apache completed leasehold and property acquisitions for cash consideration totaling $86 million and $142 million during the first nine months of 2018 and 2017, respectively.
Payments on Fixed-Rate Debt On August 24, 2018, the Company closed cash tender offers for certain outstanding notes. Apache accepted for purchase $731 million aggregate principal amount of notes for approximately $828 million, which included principal, the discount to par, and an early tender premium totaling $820 million, as well as accrued and unpaid interest of $8 million. The Company recorded a net loss of $94 million on extinguishment of debt, including $5 million of unamortized debt issuance costs and discount, in connection with the note purchases.
Apache also made repayments of current year note maturities totaling $550 million during the first nine months of 2018.
Dividends The Company paid $287 million and $285 million in dividends on its common stock for the nine-month periods ended September 30, 2018 and 2017, respectively.

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Liquidity
The following table presents a summary of the Company’s key financial indicators at the dates presented:
 
 
September 30, 2018
 
December 31, 2017
 
 
(In millions)
Cash and cash equivalents
 
$
593

 
$
1,668

Total debt
 
8,203

 
8,484

Equity
 
8,946

 
8,791

Available committed borrowing capacity
 
3,832

 
3,500

Cash and cash equivalents The Company had $593 million in cash and cash equivalents as of September 30, 2018, compared to $1.7 billion at December 31, 2017. The majority of the cash is invested in highly liquid, investment grade securities with maturities of three months or less at the time of purchase.
Debt As of September 30, 2018, outstanding debt, which consisted of unsecured notes and debentures, totaled $8.2 billion. Current debt as of September 30, 2018, included $150 million of 7.625% senior notes due July 1, 2019.
On August 23, 2018, Apache closed an offering of $1.0 billion in aggregate principal amount of senior unsecured 4.375% notes due October 15, 2028. The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers, repay notes that matured in September 2018, and for general corporate purposes.
In March 2018, the Company entered into a revolving credit facility that matures in March 2023 (subject to Apache’s two, one-year extension options) with commitments totaling $4.0 billion. The Company can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of September 30, 2018. The facility is for general corporate purposes and committed borrowing capacity fully supports Apache’s commercial paper program. As of September 30, 2018, letters of credit aggregating approximately £129.1 million and no borrowings were outstanding under this facility. In connection with entry into this facility, Apache terminated $3.5 billion and £900 million in commitments under two former credit facilities and wrote off $4 million of associated debt issuance costs, which is included in “Financing costs, net” in the Company’s consolidated statement of operations.

The Company’s $3.5 billion commercial paper program, which is subject to market availability, facilitates Apache borrowing funds for up to 270 days at competitive interest rates. As of September 30, 2018, the Company had no commercial paper outstanding.
The Company was in compliance with the terms of its credit facilities as of September 30, 2018.
Equity During the third quarter of 2018, the Company re-initiated share repurchase activity under its existing authorization, which had 6.9 million shares remaining at the end of the quarter. On October 30, 2018, the Company’s Board of Directors authorized the purchase of up to 40 million additional shares of the Company’s common stock. The Company is not obligated to acquire any specific number of shares.



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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Risk
The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices the Company receives for its crude oil, natural gas, and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather, political climate, and global supply and demand. The Company’s average crude oil realizations have increased 40 percent to $69.12 per barrel in the third quarter of 2018 from $49.34 per barrel in the comparable period of 2017. The Company’s average natural gas price realizations have decreased 7 percent to $2.56 per Mcf in the third quarter of 2018 from $2.75 per Mcf in the comparable period of 2017. Based on average daily production for the third quarter of 2018, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the quarter by approximately $22 million, and a $0.10 per Mcf change in the weighted average realized price of natural gas would have increased or decreased revenues for the quarter by approximately $9 million.
Apache periodically enters into derivative positions on a portion of its projected oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Apache periodically uses futures contracts, swaps, and options to mitigate commodity price risk. Apache does not hold or issue derivative instruments for trading purposes. As of September 30, 2018, the Company had open natural gas derivatives not designated as cash flow hedges in an asset position with a fair value of $61 million. A 10 percent increase in gas prices would decrease the asset by approximately $7 million, while a 10 percent decrease in prices would increase the asset by approximately $7 million. As of September 30, 2018, the Company had open oil derivatives not designated as cash flow hedges in a liability position with a fair value of $18 million. A 10 percent increase in oil prices would decrease the liability by approximately $7 million, while a 10 percent decrease in prices would increase the liability by approximately $6 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2018. See Note 4—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q for notional volumes and terms with the Company’s derivative contracts.
Foreign Currency Risk
The Company’s cash flow stream relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. The Company’s North Sea production is sold under U.S. dollar contracts, and the majority of costs incurred are paid in British pounds. In Egypt, all oil and gas production is sold under U.S. dollar contracts, and the majority of the costs incurred are denominated in U.S. dollars. Revenue and disbursement transactions denominated in British pounds are converted to U.S. dollar equivalents based on average exchange rates during the period.
Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Currency gains and losses are included as either a component of “Other” under “Revenues and Other” or, as is the case when the Company re-measures its foreign tax liabilities, as a component of the Company’s provision for income tax expense on the statement of consolidated operations. A foreign currency net gain or loss of $2 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of September 30, 2018.

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ITEM 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
John J. Christmann IV, the Company’s Chief Executive Officer and President, in his capacity as principal executive officer, and Stephen J. Riney, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2018, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that information we are required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
We periodically review the design and effectiveness of our disclosure controls, including compliance with various laws and regulations that apply to our operations both inside and outside the United States. We make modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if our reviews identify deficiencies or weaknesses in our controls.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

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

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

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table presents information on shares of common stock repurchased by the Company during the quarter ended September 30, 2018:
Issuer Purchases of Equity Securities
Period
 
Total Number of Shares Purchased
 
Average Price Paid per Share
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)
 
Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs(1)
July 1 to July 31, 2018
 

 
$

 

 
7,827,352

August 1 to August 31, 2018
 

 

 

 
7,827,352

September 1 to September 30, 2018
 
924,131

 
46.38

 
924,131

 
6,903,221

Total
 
924,131

 
$
46.38

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

ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None

ITEM 4. MINE SAFETY DISCLOSURES
None

ITEM 5. OTHER INFORMATION
None


37



ITEM 6. EXHIBITS
3.1
3.2
3.3
4.1
*31.1
*31.2
*32.1
*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.


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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
 
 
 
 
APACHE CORPORATION
 
 
 
Dated:
November 1, 2018
 
/s/ STEPHEN J. RINEY
 
 
 
Stephen J. Riney
 
 
 
Executive Vice President and Chief Financial Officer
 
 
 
(Principal Financial Officer)
 
 
 
Dated:
November 1, 2018
 
/s/ REBECCA A. HOYT
 
 
 
Rebecca A. Hoyt
 
 
 
Senior Vice President, Chief Accounting Officer, and Controller
 
 
 
(Principal Accounting Officer)


39