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, 20172021
ORor
¨

☐		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________ to _________
Commission File NumberNumber: 1-4300
  apachelogoa06.jpg
APACHE CORPORATION
(exactExact name of registrant as specified in its charter)
    _______________________________________________________________________
Delaware41-0747868
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification Number)
No.)
One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400
(Address of principal executive offices) (Zip Code)
Registrant’s Telephone Number, Including Area Code: (713) 296-6000

(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: None
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 ¨☐
Note: The registrant is a voluntary filer of reports required to be filed by certain companies under Sections 13 or 15(d) of the Securities Exchange Act of 1934.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerý☒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, 20172021 (100% owned by APA Corporation)380,942,6291,000 

OMISSION OF CERTAIN INFORMATION
The registrant meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this Quarterly Report on Form 10-Q with the reduced disclosure format.


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


TABLE OF CONTENTS
Forward-Looking Statements and Risk
ItemPage
PART I - FINANCIAL INFORMATION
1.
1
STATEMENT OF CONSOLIDATED OPERATIONS
1
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)
2
STATEMENT OF CONSOLIDATED CASH FLOWS
3
CONSOLIDATED BALANCE SHEET
4
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST
5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7
2.
30
3.
39
4.
39
PART II - OTHER INFORMATION
1.
40
1A.
40
6.
41


FORWARD-LOOKING STATEMENTS AND RISKS
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended.amended (the Exchange Act). All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding ourthe Company’s 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 ourthe Company’s examination of historical operating trends, the information that was used to prepare ourits estimate of proved reserves as of December 31, 2016,2020, and other data in ourthe Company’s 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”“continue,” “seek,” “guidance,” “might,” “outlook,” “possibly,” “potential,” “prospect,” “should,” “would,” or similar terminology.terminology, but the absence of these words does not mean that a statement is not forward looking. Although we believethe Company believes that the expectations reflected in such forward-looking statements are reasonable weunder the circumstances, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from ourthe Company’s expectations include, but are not limited to, ourits assumptions about:
•the scope, duration, and reoccurrence of any epidemics or pandemics (including, specifically, the coronavirus disease 2019 (COVID-19) pandemic and any related variants) and the actions taken by third parties, including, but not limited to, governmental authorities, customers, contractors, and suppliers, in response to such epidemics or pandemics;
•the mandate, availability, and effectiveness of vaccine programs and therapeutics related to the treatment of COVID-19;
•the market prices of oil, natural gas, natural gas liquids (NGLs), and other products or services;

our•the Company’s commodity hedging arrangements;

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

•production and reserve levels;

•drilling risks;

•economic and competitive conditions;

•the availability of capital resources;

•capital expenditureexpenditures and other contractual obligations;

•currency exchange rates;

•weather conditions;

•inflation rates;

•the availability of goods and services;

•legislative, regulatory, or policy changes;changes, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring, or water disposal;

•the Company’s performance on environmental, social, and governance measures;
•terrorism or cyber-attacks;cyberattacks;

•the occurrence of property acquisitions or divestitures;

•the integration of acquisitions;

•the Company’s ability to access the capital markets;
the securities or capital markets and related•market-related risks, such as general credit, liquidity, market, and interest-rate risks;
•the Company’s expectations with respect to the new operating structure implemented pursuant to the Holding Company Reorganization (as defined in the Notes to the Company’s Consolidated Financial Statements set forth in Part I, Item 1—Financial Statements of this Quarterly Report on Form 10-Q) and the associated disclosure implications;



•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 filedthe Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020;
•other risks and uncertainties disclosed in ourthe Company’s third-quarter 20172021 earnings release, release;
•other factors disclosed under Part II, Item 1A—Risk Factors in the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2021;
•other factors disclosed under Part II, Item 1A—Risk Factorsof this Quarterly Report on Form 10-Q,10-Q; and
•other factors disclosed in the other filings that we makethe Company makes with the Securities and Exchange Commission.
Other factors or events that could cause the Company’s actual results to differ materially from the Company’s expectations may emerge from time to time, and it is not possible for the Company to predict all such factors or events. 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 dutyAll forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. Except as required by law, the Company disclaims any obligation to update or revise our forward-lookingthese statements, whether based on changes in internal estimates or expectations, new information, future developments, or otherwise.




DEFINITIONS
All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this Quarterly Report on Form 10-Q. As used herein:
“3-D” means three-dimensional.
“4-D” means four-dimensional.
“b/d” means barrels of oil or natural gas liquids per day.
“bbl” or “bbls” means barrel or barrels of oil or natural gas liquids.
“bcf” means billion cubic feet of natural gas.
“bcf/d” means one bcf per day.
“boe” means barrel of oil equivalent, determined by using the ratio of one barrel of oil or NGLs to six Mcf of gas.
“boe/d” means boe per day.
“Btu” means a British thermal unit, a measure of heating value.
“Liquids” means oil and natural gas liquids.
“LNG” means liquefied natural gas.
“Mb/d” means Mbbls per day.
“Mbbls” means thousand barrels of oil or natural gas liquids.
“Mboe” means thousand boe.
“Mboe/d” means Mboe per day.
“Mcf” means thousand cubic feet of natural gas.
“Mcf/d” means Mcf per day.
“MMbbls” means million barrels of oil or natural gas liquids.
“MMboe” means million boe.
“MMBtu” means million Btu.
“MMBtu/d” means MMBtu per day.
“MMcf” means million cubic feet of natural gas.
“MMcf/d” means MMcf per day.
“NGL” or “NGLs” means natural gas liquids, which are expressed in barrels.
“NYMEX” means New York Mercantile Exchange.
“oil” includes crude oil and condensate.
“PUD” means proved undeveloped.
“SEC” means United States Securities and Exchange Commission.
“Tcf” means trillion cubic feet of natural gas.
“U.K.” means United Kingdom.
“U.S.” means United States.
With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.
References to “Apache,” the “Company,” “we,” “us,” and “our” refer to Apache Corporation and its consolidated subsidiaries, unless otherwise specifically stated. References to “APA” refer to APA Corporation, the Company’s parent holding company, and its consolidated subsidiaries, including the Company, unless otherwise specifically stated.


PART I – FINANCIAL INFORMATION
ITEM 1 –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,
2021202020212020
 (In millions)
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues$1,685 $1,046 $4,630 $2,979 
Purchased oil and gas sales374 74 1,056 237 
Total revenues2,059 1,120 5,686 3,216 
Derivative instrument gains (losses), net— 16 45 (262)
Gain (loss) on divestitures, net(2)(1)65 24 
Loss on previously sold Gulf of Mexico properties(446)— (446)— 
Other, net40 9 175 41 
1,651 1,144 5,525 3,019 
OPERATING EXPENSES:
Lease operating expenses316 259 891 858 
Gathering, processing, and transmission68 63 187 206 
Purchased oil and gas costs396 75 1,152 207 
Taxes other than income54 34 149 90 
Exploration21 58 86 187 
General and administrative64 52 226 214 
Transaction, reorganization, and separation4 7 8 44 
Depreciation, depletion, and amortization335 398 1,028 1,382 
Asset retirement obligation accretion29 27 85 81 
Impairments18 — 18 4,492 
Financing costs, net192 99 393 168 
1,497 1,072 4,223 7,929 
NET INCOME (LOSS) BEFORE INCOME TAXES154 72 1,302 (4,910)
Current income tax provision183 58 463 120 
Deferred income tax benefit(29)(27)(51)(71)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS— 41 890 (4,959)
Net income (loss) attributable to noncontrolling interest - Egypt49 24 132 (138)
Net income (loss) attributable to noncontrolling interest - Altus4 2 32 (7)
Net income attributable to Altus Preferred Unit limited partners30 19 73 56 
NET INCOME (LOSS) ATTRIBUTABLE TO APA CORPORATION$(83)$(4)$653 $(4,870)
  For the Quarter Ended September 30, For the Nine Months Ended September 30,
  2017 2016 2017 2016
  (In millions, except per common share data)
REVENUES AND OTHER:        
Oil and gas production revenues        
Oil revenues $1,070
 $1,117
 $3,292
 $3,057
Gas revenues 238
 263
 726
 695
Natural gas liquids revenues 81
 59
 229
 160
  1,389
 1,439
 4,247
 3,912
Derivative instrument losses, net (110) —
 (69) —
Gain on divestitures 296
 5
 616
 21
Other —
 (6) 43
 (30)
  1,575
 1,438
 4,837
 3,903
OPERATING EXPENSES:        
Lease operating expenses 358
 382
 1,066
 1,119
Gathering and transportation 39
 51
 144
 155
Taxes other than income 46
 9
 117
 85
Exploration 231
 161
 431
 347
General and administrative 98
 102
 307
 298
Transaction, reorganization, and separation 20
 12
 14
 36
Depreciation, depletion, and amortization:        
Oil and gas property and equipment 524
 610
 1,598
 1,875
Other assets 35
 38
 109
 120
Asset retirement obligation accretion 30
 40
 103
 116
Impairments —
 836
 8
 1,009
Financing costs, net 101
 102
 300
 311
  1,482
 2,343
 4,197
 5,471
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 93
 (905) 640
 (1,568)
Current income tax provision 99
 150
 413
 284
Deferred income tax benefit (111) (529) (758) (755)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST 105
 (526) 985
 (1,097)
Net loss from discontinued operations, net of tax —
 (33) —
 (33)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST 105

(559)
985

(1,130)
Net income attributable to noncontrolling interest 42
 48
 137
 93
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK $63
 $(607) $848
 $(1,223)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS:        
Net income (loss) from continuing operations attributable to common shareholders $63
 $(574) $848
 $(1,190)
Net loss from discontinued operations —
 (33) —
 (33)
Net income (loss) attributable to common shareholders $63
 $(607) $848
 $(1,223)
NET INCOME (LOSS) PER COMMON SHARE:        
Basic net income (loss) from continuing operations per share $0.16
 $(1.51) $2.23
 $(3.14)
Basic net loss from discontinued operations per share —
 (0.09) —
 (0.08)
Basic net income (loss) per share $0.16
 $(1.60) $2.23
 $(3.22)
DILUTED NET INCOME (LOSS) PER COMMON SHARE:        
Diluted net income (loss) from continuing operations per share $0.16
 $(1.51) $2.22
 $(3.14)
Diluted net loss from discontinued operations per share —
 (0.09) —
 (0.08)
Diluted net income (loss) per share $0.16
 $(1.60) $2.22
 $(3.22)
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:        
Basic 381
 380
 381
 379
Diluted 383
 380
 383
 379
DIVIDENDS DECLARED PER COMMON SHARE $0.25
 $0.25
 $0.75
 $0.75

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

1


APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)
(Unaudited)
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
 2021202020212020
 (In millions)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS$— $41 $890 $(4,959)
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Share of equity method interests other comprehensive income— 1 1 — 
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS— 42 891 (4,959)
Comprehensive income (loss) attributable to noncontrolling interest - Egypt49 24 132 (138)
Comprehensive income (loss) attributable to noncontrolling interest - Altus4 2 32 (7)
Comprehensive income attributable to Altus Preferred Unit limited partners30 19 73 56 
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO APA CORPORATION$(83)$(3)$654 $(4,870)

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

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

2



APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Unaudited)
For the Nine Months Ended
September 30,
 20212020
 (In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) including noncontrolling interests$890 $(4,959)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized derivative instrument losses, net18 142 
Gain on divestitures, net(65)(24)
Exploratory dry hole expense and unproved leasehold impairments57 138 
Depreciation, depletion, and amortization1,028 1,382 
Asset retirement obligation accretion85 81 
Impairments18 4,492 
Deferred income tax benefit(51)(71)
Loss (gain) on extinguishment of debt104 (152)
Loss on previously sold Gulf of Mexico properties446 — 
Other, net(42)45 
Changes in operating assets and liabilities:
Receivables(274)202 
Inventories(19)16 
Drilling advances and other current assets20 (5)
Deferred charges and other long-term assets(46)(12)
Accounts payable195 (211)
Accounts payable to APA Corporation33 — 
Accrued expenses29 (211)
Deferred credits and noncurrent liabilities(8)37 
NET CASH PROVIDED BY OPERATING ACTIVITIES2,418 890 
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas property(673)(1,075)
Additions to Altus gathering, processing, and transmission (GPT) facilities(2)(27)
Leasehold and property acquisitions(6)(3)
Contributions to Altus equity method interests(27)(286)
Proceeds from sale of oil and gas properties239 132 
Other, net44 (17)
NET CASH USED IN INVESTING ACTIVITIES(425)(1,276)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from Apache credit facility, net290 87 
Proceeds from Altus credit facility, net33 184 
Proceeds from note payable to APA Corporation, net139 — 
Fixed-rate debt borrowings— 1,238 
Payments on fixed-rate debt(1,795)(980)
Distributions to noncontrolling interest - Egypt(203)(61)
Distributions to Altus Preferred Unit limited partners(34)(11)
Distributions to APA Corporation(311)— 
Dividends paid(9)(113)
Other, net(17)(43)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES(1,907)301 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS86 (85)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR262 247 
CASH AND CASH EQUIVALENTS AT END OF PERIOD$348 $162 
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest$365 $341 
Income taxes paid, net of refunds415 153 
  For the Nine Months Ended September 30,
  2017 2016
  (In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:    
Net income (loss) including noncontrolling interest $985
 $(1,130)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:    
Loss from discontinued operations —
 33
Unrealized derivative instrument losses, net 42
 —
Gain on divestitures (616) (21)
Exploratory dry hole expense and unproved leasehold impairments 350
 260
Depreciation, depletion, and amortization 1,707
 1,995
Asset retirement obligation accretion 103
 116
Impairments 8
 1,009
Deferred income tax benefit (758) (755)
Other 167
 126
Changes in operating assets and liabilities:    
Receivables (70) 192
Inventories 17
 (2)
Drilling advances (72) (36)
Deferred charges and other (60) 40
Accounts payable 2
 (93)
Accrued expenses (65) (67)
Deferred credits and noncurrent liabilities 20
 (33)
NET CASH PROVIDED BY OPERATING ACTIVITIES 1,760
 1,634
     
CASH FLOWS FROM INVESTING ACTIVITIES:    
Additions to oil and gas property (1,471) (1,281)
Leasehold and property acquisitions (142) (169)
Additions to gas gathering, transmission, and processing facilities (384) (33)
Proceeds from sale of Canadian assets, net of cash divested 661
 —
Proceeds from sale of oil and gas properties 743
 74
Other, net (30) 47
NET CASH USED IN INVESTING ACTIVITIES (623) (1,362)
     
CASH FLOWS FROM FINANCING ACTIVITIES:    
Payments on fixed-rate debt (70) (1)
Distributions to noncontrolling interest (212) (215)
Dividends paid (285) (284)
Other (5) (9)
NET CASH USED IN FINANCING ACTIVITIES (572) (509)
     
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS, AND RESTRICTED CASH 565
 (237)
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF YEAR 1,377
 1,467
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD $1,942
 $1,230
     
SUPPLEMENTARY CASH FLOW DATA:    
Interest paid, net of capitalized interest $341
 $345
Income taxes paid, net of refunds 315
 256

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

3




APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)
  September 30, 2017 December 31, 2016
  (In millions)
ASSETS    
CURRENT ASSETS:    
Cash and cash equivalents $1,846
 $1,377
Restricted cash 96
 —
Receivables, net of allowance 1,145
 1,128
Inventories 396
 476
Drilling advances 151
 81
Prepaid assets and other 135
 179
  3,769
 3,241
PROPERTY AND EQUIPMENT:    
Oil and gas, on the basis of successful efforts accounting:    
Proved properties 38,569
 42,693
Unproved properties and properties under development 1,810
 1,969
Gathering, transmission, and processing facilities 1,363
 976
Other 1,012
 1,111
  42,754
 46,749
Less: Accumulated depreciation, depletion, and amortization (25,099) (27,882)
  17,655
 18,867
OTHER ASSETS:    
Deferred charges and other 411
 411
  $21,835
 $22,519
LIABILITIES AND SHAREHOLDERS’ EQUITY    
CURRENT LIABILITIES:    
Accounts payable $583
 $585
Current debt 550
 —
Other current liabilities (Note 5) 1,332
 1,258
  2,465
 1,843
LONG-TERM DEBT 7,933
 8,544
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:    
Income taxes 948
 1,710
Asset retirement obligation 1,831
 2,432
Other 281
 311
  3,060
 4,453
COMMITMENTS AND CONTINGENCIES (Note 9) 
 
EQUITY:    
Common stock, $0.625 par, 860,000,000 shares authorized, 414,108,944 and 412,612,102 shares issued, respectively 259
 258
Paid-in capital 12,186
 12,364
Accumulated deficit (2,544) (3,385)
Treasury stock, at cost, 33,171,015 and 33,172,426 shares, respectively (2,887) (2,887)
Accumulated other comprehensive loss (3) (112)
APACHE SHAREHOLDERS’ EQUITY 7,011
 6,238
Noncontrolling interest 1,366
 1,441
TOTAL EQUITY 8,377
 7,679
  $21,835
 $22,519
September 30,
2021
December 31,
2020
(In millions, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ($109 and $24 related to Altus VIE)$348 $262 
Receivables, net of allowance of $99 and $951,167 908 
Other current assets (Note 6) ($9 and $5 related to Altus VIE)
599 676 
Accounts receivable from APA Corporation55 — 
2,169 1,846 
PROPERTY AND EQUIPMENT:
Oil and gas properties40,205 41,819 
Gathering, processing, and transmission facilities ($207 and $206 related to Altus VIE)673 670 
Other ($4 and $3 related to Altus VIE)1,124 1,140 
Less: Accumulated depreciation, depletion, and amortization ($22 and $13 related to Altus VIE)(33,889)(34,810)
8,113 8,819 
OTHER ASSETS:
Equity method interests (Note 7) ($1,538 and $1,555 related to Altus VIE)
1,538 1,555 
Decommissioning security for sold Gulf of Mexico properties (Note 12)
740 — 
Deferred charges and other ($8 and $5 related to Altus VIE)514 526 
Note receivable from APA Corporation (Note 2)
1,352 — 
$14,426 $12,746 
LIABILITIES, NONCONTROLLING INTEREST, AND EQUITY
CURRENT LIABILITIES:
Accounts payable ($9 and $6 related to Altus VIE)$643 $444 
Note payable to APA Corporation243 — 
Current debt215 2 
Other current liabilities (Note 8) ($15 and $4 related to Altus VIE)
937 862 
2,038 1,308 
LONG-TERM DEBT (Note 10) ($657 and $624 related to Altus VIE)
7,193 8,770 
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes169 215 
Asset retirement obligation (Note 9) ($67 and $64 related to Altus VIE)
1,912 1,888 
Decommissioning contingency for sold Gulf of Mexico properties (Note 12)
1,186 — 
Other ($126 and $144 related to Altus VIE)527 602 
3,794 2,705 
REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 13)
635 608 
EQUITY (DEFICIT):
Common stock, $0.625 par, 1,000 and 860,000,000 shares authorized, respectively, 1,000 and 418,429,375 shares issued, respectively— 262 
Paid-in capital9,532 11,735 
Accumulated deficit(9,726)(10,461)
Treasury stock, at cost, 0 and 40,946,745 shares, respectively— (3,189)
Accumulated other comprehensive income15 14 
DEFICIT ATTRIBUTABLE TO APA CORPORATION(179)(1,639)
Noncontrolling interest - Egypt854 925 
Noncontrolling interest - Altus91 69 
TOTAL EQUITY (DEFICIT)766 (645)
$14,426 $12,746 

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 (DEFICIT) AND NONCONTROLLING INTEREST
(Unaudited)
Redeemable Noncontrolling Interest - Altus Preferred Unit Limited PartnersCommon
Stock		Paid-In
Capital		Accumulated DeficitTreasury
Stock		Accumulated
Other
Comprehensive
Income		PARENT COMPANY
DEFICIT		Noncontrolling
Interests		TOTAL
EQUITY (DEFICIT)
(In millions)
For the Quarter Ended September 30, 2020
Balance at June 30, 2020$592 $262 $11,744 $(10,467)$(3,189)$15 $(1,635)$999 $(636)
Net loss attributable to APA Corporation— — — (4)— — (4)— (4)
Net income attributable to noncontrolling interest - Egypt— — — — — — — 24 24 
Net income attributable to noncontrolling interest - Altus— — — — — — — 2 2 
Net income attributable to Altus Preferred Unit holders19 — — — — — — — — 
Distributions payable to Altus Preferred Unit limited partners(11)— — — — — — — — 
Distributions to noncontrolling interest - Egypt— — — — — — — (21)(21)
Common dividends declared ($0.025 per share)— — (10)— — — (10)— (10)
Other— — 7 — — 1 8 — 8 
Balance at September 30, 2020$600 $262 $11,741 $(10,471)$(3,189)$16 $(1,641)$1,004 $(637)
For the Quarter Ended September 30, 2021
Balance at June 30, 2021$617 $— $9,535 $(9,642)$— $15 $(92)$1,040 $948 
Net loss attributable to APA Corporation— — — (83)— — (83)— (83)
Net income attributable to noncontrolling interest - Egypt— — — — — — — 49 49 
Net income attributable to noncontrolling interest - Altus— — — — — — — 4 4 
Net income attributable to Altus Preferred Unit limited partners30 — — — — — — — — 
Distributions payable to Altus Preferred Unit limited partners(12)— — — — — — — — 
Distributions to noncontrolling interest - Egypt— — — — — — — (143)(143)
Distributions to APA Corporation— — (9)— — — (9)— (9)
Other— — 6 (1)— — 5 (5)— 
Balance at September 30, 2021$635 $— $9,532 $(9,726)$— $15 $(179)$945 $766 

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

5



APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST - Continued
(Unaudited)
Redeemable Noncontrolling Interest - Altus Preferred Unit Limited PartnersCommon
Stock		Paid-In
Capital		Accumulated DeficitTreasury
Stock		Accumulated
Other
Comprehensive
Income		PARENT
COMPANY
DEFICIT		Noncontrolling
Interests		TOTAL
EQUITY (DEFICIT)
(In millions)
For the Nine Months Ended September 30, 2020
Balance at December 31, 2019$555 $261 $11,769 $(5,601)$(3,190)$16 $3,255 $1,210 $4,465 
Net loss attributable to APA Corporation— — — (4,870)— — (4,870)— (4,870)
Net loss attributable to noncontrolling interest - Egypt— — — — — — — (138)(138)
Net loss attributable to noncontrolling interest - Altus— — — — — — — (7)(7)
Net income attributable to Altus Preferred Unit holders56 — — — — — — — — 
Distributions to Altus Preferred Unit limited partners(11)— — — — — — — — 
Distributions to noncontrolling interest - Egypt— — — — — — — (61)(61)
Common dividends declared ($0.075 per share)— — (29)— — — (29)— (29)
Other— 1 1 — 1 — 3 — 3 
Balance at September 30, 2020$600 $262 $11,741 $(10,471)$(3,189)$16 $(1,641)$1,004 $(637)
For the Nine Months Ended September 30, 2021
Balance at December 31, 2020$608 $262 $11,735 $(10,461)$(3,189)$14 $(1,639)$994 $(645)
Net income attributable to APA Corporation— — — 653 — — 653 — 653 
Net income attributable to noncontrolling interest - Egypt— — — — — — — 132 132 
Net income attributable to noncontrolling interest - Altus— — — — — — — 32 32 
Net income attributable to Altus Preferred Unit limited partners73 — — — — — — — — 
Distributions payable to Altus Preferred Unit limited partners(12)— — — — — — — — 
Distributions paid to Altus Preferred Unit limited partners(34)— — — — — — — — 
Distributions to noncontrolling interest - Egypt— — — — — — — (203)(203)
Distributions to APA Corporation— — (19)— — — (19)— (19)
Common dividends declared ($0.1125 per share)— — (9)— — — (9)— (9)
APA Corporation share exchange— (262)(2,927)— 3,189 — — — — 
Holding Company Reorganization— — 757 82 — — 839 — 839 
Other— — (5)— — 1 (4)(10)(14)
Balance at September 30, 2021$635 $— $9,532 $(9,726)$— $15 $(179)$945 $766 

The accompanying notes to consolidated financial statements are an integral part of this statement.
6

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.statements, with the exception of recently adopted accounting pronouncements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP)(GAAP) have been condensed or 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’sthe Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016,2020, which contains a summary of the Company’s significant accounting policies and other disclosures.
On January 4, 2021, Apache announced plans to implement a holding company reorganization (the Holding Company Reorganization), which was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization, Apache became a direct, wholly-owned subsidiary of APA Corporation (APA), and all of Apache’s outstanding shares were automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to Apache pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized the Company’s operating and legal structure making it more consistent with other companies that have affiliates operating around the globe. Refer to Note 2—Transactions with Parent Affiliate for more detail.
1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
1.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
As of September 30, 2017, Apache’s2021, the Company's significant accounting policies are consistent with those discussed in Note 1—Summary of Significant Accounting Policies of its consolidated financial statementsthe Notes to Consolidated Financial Statements contained in Apache’sthe Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016,2020. The Company’s financial statements for prior periods include reclassifications that were made to conform to the current-year presentation.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. Apache’s consolidated financial statements reflect the impacts of the Holding Company Reorganization on a prospective basis, and results prior to completion of the Holding Company Reorganization have not been restated. Refer to Note 2—Transactions with Parent Affiliate for more detail.
The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the exceptionfinancial and operating decisions. Noncontrolling interests represent third-party ownership in the net assets of Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) 2016-09, “Improvementsa consolidated subsidiary of Apache and are reflected separately in the Company’s financial statements.
Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. Additionally, third-party investors own a minority interest of approximately 21 percent of Altus Midstream Company (ALTM), which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. ALTM qualifies as a variable interest entity under GAAP, for which Apache consolidates because a wholly-owned subsidiary of Apache has a controlling financial interest and was determined to Employee Share-Based Payment Accounting”be the primary beneficiary.
Investments in which the Company has significant influence, but not control, are accounted for under the equity method of accounting. These investments are recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company’s proportionate share of the results of operations generated by the equity method interests are recorded as a component of “Other, net” under “Revenues and ASU 2016-18, “StatementOther” in the Company’s statement of Cash Flows (Topic 230): Restricted Cash” (see “Recently Adopted Accounting Pronouncements” in this consolidated operations. Refer to Note 1 below).7—Equity Method Interests for further detail.
7

Use of Estimates
The preparationPreparation of financial statements in conformity with U.S. GAAP requiresand disclosure of contingent assets and liabilities require management to make estimates and assumptions that affect the reported amounts of assets and liabilities atas of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements and changes in these estimates are recorded when known.
Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 3—Acquisitions and Divestitures), the assessment of asset retirement obligations (refer to Note 9—Asset Retirement Obligation), the estimation of the contingent liability representing Apache’s potential obligation to decommission sold properties in the Gulf of Mexico (refer to Note 12—Commitments and Contingencies), the estimate of income taxes (refer to Note 11—Income Taxes), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, the assessment of asset retirement obligations, the estimates of fair value for long-lived assets and goodwill, and the estimate of income taxes. Actual results could differ from those estimates.therefrom.
Fair Value Measurements
Certain assets and liabilities are reported at fair value on a recurring basis in Apache’sthe Company’s consolidated balance sheet. The Company determines fair value measurements in accordance with Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), which provides a hierarchy that prioritizes and defines the types of inputs used to measurebase fair value.value measurements. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.
The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
Apache also usesRefer to Note 5—Derivative Instruments and Hedging Activities, Note 10—Debt and Financing Costs, and Note 13—Redeemable Noncontrolling Interest - Altus for further detail regarding the Company’s fair value measurements recorded on a recurring basis.
Fair value measurements are recorded on a nonrecurring basis when certain qualitative assessments of itsthe Company’s assets indicate a potential impairment. The CompanyAsset impairments recorded no asset impairments in connection with fair value assessments inwere as follows:
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2021202020212020
(In millions)
Oil and gas proved property$— $— $— $4,319 
Gathering, processing, and transmission facilities— — — 68 
Goodwill— — — 87 
Inventory and other18 — 18 18 
Total Impairments$18 $— $18 $4,492 
During the third quarter and first nine months of 2017. For the nine-month period ended September 30, 2017,2021, the Company recorded $18 million of asset impairments totaling $8 millionin connection with inventory valuations and expected equipment dispositions in the North Sea.
8

During the first nine months of 2020, the Company recognized total asset impairments of $4.5 billion in connection with fair value assessments.
In 2016, Given the U.K. government enacted Finance Bill 2016, providing tax relief to explorationcrude oil price collapse on lower demand and production (E&P) companies operatingeconomic activity resulting from the coronavirus disease 2019 (COVID-19) global pandemic and related governmental actions, the Company assessed its oil and gas property and gathering, processing, and transmission (GPT) facilities for impairment. The Company recognized proved property impairments of $3.9 billion, $374 million, and $7 million in the U.K.U.S., Egypt, and North Sea. UnderSea, respectively, to reduce the enacted legislation,carrying value of its oil and gas properties to the U.K. Petroleum Revenue Tax (PRT) rate was reducedestimated fair values as a result of lower forecasted commodity prices, changes to zero fromplanned development activity, and increasing market uncertainty. Similarly, the previously enacted 35 percent rateCompany recognized GPT facility impairments of $68 million in effect from January 1, 2016. PRT expense ceased prospectively from that date. Egypt. These impairments are discussed in further detail below in “Property and Equipment - Oil and Gas Property” and “Property and Equipment - Gathering, Processing, and Transmission Facilities.”
During the first quarter of 2017,2020, the Company fully impairedseparately recognized impairments of $13 million for the aggregate remaining valueearly termination of drilling rig leases and $5 million for inventory revaluations, both in the U.S.
The Company also performed an interim impairment analysis of the recoverable PRT decommissioning asset of $8 million that would have been realized from future abandonment activities. The recoverablegoodwill related to its Egypt reporting segment. Reductions in the estimated net present value of the PRT decommissioning asset was estimated using the income approach. The expected future cash flows used in the determination were based on anticipated spending and timing of planned future abandonment activities for applicable fields, considering all available information at the date of review. Apache has classified this fair value measurement as Level 3 in the fair value hierarchy.


For the quarter ended September 30, 2016, the Company recorded asset impairments totaling $836 million in connection with fair value assessments including $355 million for provedfrom oil and gas properties resulted in Canada and $481 million forfair values below the impairmentcarrying values of the recoverableCompany’s Egypt reporting unit. As a result of these assessments, the Company recognized non-cash impairments of the entire amount of recorded goodwill in the Egypt reporting unit of $87 million.
Accounts Receivable from / Accounts Payable to APA
Accounts receivable from or payable to APA represents the net result of Apache’s administrative and support services provided to APA and other miscellaneous cash management transactions to be settled between the two affiliated entities. Generally, cash in this amount will be transferred to Apache or paid to APA in subsequent periods, after current period transactions are processed and net results of operations are determined. However, from time to time, Apache may estimate and transfer the cash settlement amount in the month the transactions are processed in order to minimize affiliate working capital balances. Refer to Note 2—Transactions with Parent Affiliate for more detail.
Property and Equipment
The carrying value of the PRT decommissioning asset.Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For the nine-month period ended September 30, 2016, the Company recorded asset impairments totaling $1.0 billion in connection with fair value assessments including $423 million for proved oilbusiness combinations, property and gas properties inequipment cost is based on the U.S. and Canada, $481 million for the impairment of the recoverable value of the PRT decommissioning asset, and $105 million for the impairment of certain gas gathering, transmission, and processing (GTP) assets, which were written down to their fair values of $175 million.at the acquisition date.
Oil and Gas Property
The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.
Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations.
9

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.associated proved oil and gas properties. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized costs of exploratory wells and developmentwell costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.
Oil and gas properties are grouped for depreciation in accordance with ASC 932 “Extractive Activities - Activities—Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
When circumstances indicate that the carrying value of proved oil and gas properties may not be impaired,recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on Apache’sthe Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820. If applicable, the Company utilizes prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement.
The significant decline in crude oil and natural gas prices, as well as longer-term commodity price outlooks, related to reduced demand for oil and natural gas as a result of the COVID-19 pandemic and related governmental actions indicated possible impairment of the Company’s proved and unproved oil and gas properties in early 2020. In addition to estimating risk-adjusted reserves and future production volumes, estimated future commodity prices operatingare the largest driver in variability of undiscounted pre-tax cash flows. Expected cash flows were estimated based on management’s views of published West Texas Intermediate (WTI), Brent, and Henry Hub forward pricing as of the balance sheet dates. Other significant assumptions and inputs used to calculate estimated future cash flows include estimates for future development activity, exploration plans and remaining lease terms. A 10 percent discount rate, based on a market-based weighted-average cost of capital estimate, was applied to the undiscounted cash flow estimate to value all of the Company’s asset groups that were subject to impairment charges in the first and second quarters of 2020.
The following table represents non-cash impairment charges of the carrying value of the Company’s proved and unproved properties:
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2021202020212020
(In millions)
Proved Properties:
U.S.$— $— $— $3,938 
Egypt— — — 374 
North Sea— — — 7 
Total proved properties$— $— $— $4,319 
Unproved Properties:
U.S.$2 $34 $19 $80 
Egypt2 2 6 6 
North Sea1 — 1 — 
Total unproved properties$5 $36 $26 $86 
Proved properties impaired during the first nine months of 2020 had an aggregate fair value of $1.9 billion.
Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction. Refer to Note 3—Acquisitions and Divestitures for more detail.
10

Gathering, Processing, and Transmission Facilities
GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether Apache-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields.
The Company assesses the carrying amount of its GPT facilities whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value.
The Company assessed its long-lived infrastructure assets for impairment as of March 31, 2020, and recorded an impairment of $68 million on its GPT facilities in Egypt during the first quarter of 2020. The fair values of the impaired assets, which were determined to be $46 million, were estimated using the income approach, which considers internal estimates based on future throughput volumes from applicable development concessions in Egypt and estimated costs and capital investment plans, considering all available information at the date of review.to operate. These assumptions arewere applied based on throughput assumptions developed in relation to the oil and gas proved property impairment assessment, as discussed above, to develop future cash flow projections that arewere then discounted to estimated fair value, using a 10 percent discount rate, believed to be consistent with those applied by market participants. Apachebased on a market-based weighted-average cost of capital estimate. The Company has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy.

Revenue Recognition

There have been no significant changes to the Company’s contracts with customers during the nine months ended September 30, 2021 and 2020.
Payments under all contracts with customers are typically due and received within a short-term period of one year or less after physical delivery of the product or service has been rendered. Receivables from contracts with customers, net of allowance for credit losses, were $1.1 billion and $670 million as of September 30, 2021 and December 31, 2020, respectively. Refer to Note 15—Business Segment Information for a disaggregation of oil, gas, and natural gas production revenue by product and reporting segment.
Oil and gas production revenues from non-customers represent income taxes paid to the Arab Republic of Egypt by Egyptian General Petroleum Corporation on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil, natural gas, and natural gas liquids production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations.
The following table represents non-cash impairmentspresents the Company’s revenues generated from contracts with customers and non-customers:
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2021202020212020
 (In millions)
Production revenues from customers$1,562 $1,002 $4,294 $2,905 
Production revenues from non-customers123 44 336 74 
Total production revenues$1,685 $1,046 $4,630 $2,979 
In accordance with the provisions of ASC 606, “Revenue from Contracts with Customers,” variable market prices for each short-term commodity sale are allocated entirely to each performance obligation as the terms of payment relate specifically to the Company’s efforts to satisfy its obligations. As such, the Company has elected the practical expedients available under the standard to not disclose the aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the carrying valueend of the reporting period.
11

Transaction, Reorganization, and Separation (TRS)
In recent years, the Company streamlined its portfolio through strategic divestitures and centralized certain operational activities in an effort to capture greater efficiencies and cost savings through shared services. In light of the continued streamlining of the Company’s provedasset portfolio through divestitures and unproved propertystrategic transactions, in late 2019, management initiated a comprehensive redesign of the Company’s organizational structure and equipment foroperations. Efforts related to this reorganization were substantially completed during 2020. The Company incurred and paid a cumulative total of $79 million of reorganization costs through December 31, 2020. An additional $4 million and $8 million of reorganization costs were incurred in the third quartersquarter and first nine months of 20172021, respectively, primarily related to ongoing consulting and 2016:separation activities in the Company’s international operations.
  Quarter Ended September 30, Nine Months Ended September 30,
  2017 2016 2017 2016
  (In millions)
Oil and Gas Property:        
Proved $—
 $355
 $—
 $423
Unproved 160
 114
 214
 222
Proved properties impairedThe Company recorded $7 million and $44 million of TRS costs during the secondthird quarter and third quartersfirst nine months of 2016 had aggregate fair values2020, respectively. TRS costs incurred in the first nine months of $1432020 relate to $41 million of separation costs associated with the reorganization, $2 million for transaction consulting fees, and $1 million of office closure costs.
2.    TRANSACTIONS WITH PARENT AFFILIATE
The Company completed the Holding Company Reorganization on March 1, 2021 and sold to APA all of the equity in the 3 Apache subsidiaries through which Apache’s interests in Suriname and the Dominican Republic were held. The reorganization gave rise to a note payable by APA to Apache. The note has a seven-year term, maturing on February 29, 2028, and bears interest at a rate of 4.5 percent per annum, payable semi-annually, subject to APA’s option to allow accrued interest to convert to principal (PIK) during the first 5.5 years of the note’s term (to August 31, 2026). The note is guaranteed by each of the 3 subsidiaries sold by Apache to APA.
The Company recognized interest income of approximately $15 million and $163$35 million respectively.
Onon this note during the third quarter and first nine months of 2021, respectively, which is reflected in “Financing costs, net” on the Company’s statement of consolidated operations, unproved impairments are recorded in exploration expense, and proved impairments are recorded in impairments.operations. Apache allowed interest accrued from March 1, 2021 through August 31, 2021 to PIK pursuant to the note.
Recently Adopted Accounting Pronouncements
Stock Compensation
In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting.” ASU 2016-09 simplifies several aspects of accounting for share-based payment transactions including income tax consequences, classification of awards as either equity or liabilities, and the classification on the statement of cash flows. The guidance was effective for fiscal years beginning after December 15, 2016. The Company adopted ASU 2016-09 effective January 1, 2017.
Upon adoption,accounted for the divestiture of its subsidiaries as a transfer to an affiliate entity under common control and no longer consolidates the subsidiaries for periods subsequent to the Holding Company elected to account for forfeitures as they occur rather than estimate expected forfeitures using a modified retrospective transition method. As a result of this election, the Company recorded a cumulative-effect adjustment of $11 million, representing an increase in accumulated deficit, with the offset to paid-in capital. During the first quarter of 2017, the Company recorded a $4 million deferred tax asset related to this adjustment, with the offset to accumulated deficit.
ASU 2016-09 requires excess tax benefits and deficiencies to be recognized prospectively as partReorganization. The carrying value of the provision for income taxes rather than paid-in capital. The adoption did not have a material impact on the Company’s accountingnet assets transferred was $483 million, which included approximately $292 million of provision for income taxes. ASU 2016-09 also requires excess tax benefits to be presented as a component of operating cash flows rather than financing cash flows. The Company has adopted this requirement prospectively and accordingly, prior periods have not been adjusted. Excess tax benefits were not material for all periods presented.
Additionally, ASU 2016-09 requires that employee taxes paid when an employer withholds shares for tax-withholding purposes be reported as financing activities in the consolidated statements of cash flows, which is how the Company has historically classified these amounts.
Restricted Cash
In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash.” ASU 2016-18 requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents, when reconciling the total beginning$163 million of Oil and ending amounts for the periods shown on the statement of cash flows. The guidance is effective for annualgas properties, and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The Company adopted ASU 2016-18 in the third quarter of 2017. Other than the change in presentation within the statement of consolidated cash flows, the adoption of ASU 2016-18 did not have an impact on the Company’s consolidated financial statements.


The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheet to the amounts shown in the statement of consolidated cash flows:
  September 30, 2017 December 31, 2016
  (In millions)
Cash and cash equivalents $1,846
 $1,377
Restricted cash 96
 —
Total cash, cash equivalents, and restricted cash shown in the statement of consolidated cash flows $1,942
 $1,377
For information regarding the restricted cash balance, please refer to Note 2—Acquisitions and Divestitures.
New Pronouncements Issued But Not Yet Adopted
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous U.S. GAAP. The guidance is effective for fiscal years beginning after December 15, 2018, and the Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. Early adoption is permitted; however, the Company does not intend to early adopt. As part of the assessment to date, the Company has formed an implementation work team and is continuing to evaluate contracts to determine the impact this ASU will have on its consolidated financial statements. At this time, the Company cannot reasonably estimate the financial impact this will have on its consolidated financial statements; however, the Company believes adoption and implementation of this ASU will significantly impact its balance sheet, resulting in an increase in both assets and liabilities relating to its leasing activities.
In May 2014, the FASB and the International Accounting Standards Board (IASB) issued a joint revenue recognition standard, ASU 2014-09, “Revenue from Contracts with Customers (Topic 606).” The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers, and increases disclosure requirements. The codification was amended through additional ASUs and, as amended, requires companies to recognize revenue to depict the transfer of goods or services to customers in amounts that reflect the consideration to which the company expects to be entitled in exchange for those goods or services. The guidance is effective for annual and interim periods beginning after December 15, 2017. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet.working capital items. The Company continues to make progress on evaluatinghold its existing assets in the accounting implications of this ASUU.S., Egypt, and U.K., and its assessment of contracts with customers is largely complete. Based on the Company’s evaluation to date, it does not expect the adoption of this ASU to have a material impact on net earnings, however, the Company is analyzing whether the classification of certain itemscurrent economic interests in revenueALTM and expense will be impacted. its subsidiary, Altus Midstream LP.
The Company continues to evaluateprovide administrative and support operations to APA related to activities performed for the disclosure requirements, develop accounting policies,Suriname and assess changes to the relevant business processes and the control activities within them as a result of the provisions of this ASU.Dominican Republic subsidiaries. The Company will adoptis reimbursed by APA for employee costs, certain internal costs, and third-party costs paid by the new standardCompany in connection with its role as service provider. All reimbursements are based on January 1, 2018, utilizingactual costs incurred and no market premium is applied by the modified retrospective approach.


2.ACQUISITIONS AND DIVESTITURES

2017 Activity
Canada Divestitures
During the third quarter, Apache announced the sale of its subsidiary Apache Canada Ltd. (ACL) and complete exit of its Canadian operations. On June 30, 2017, Apache completed the sale of its Canadian assets at Midale and House Mountain, located in Saskatchewan and Alberta, for aggregate cash proceeds of approximately $228 million.Company to APA. The Company recognized a $52incurred $5 million loss during the second quarter of 2017 in association with this sale.
In August of 2017, Apache completed the sale of its remaining Canadian operations for aggregate cash proceeds of approximately $478 million. The Company recognized a $74 million gain upon closing of these transactions in the third quarter of 2017. The Company has classified $96 million of proceeds as “Restricted cash” on the Company’s consolidated balance sheet, pending the Alberta Energy Regulator’s clearance of the transfer of Provost area licenses from ACL to the buyer.
A summary of the assets and liabilities at closing of the August transactions is detailed below:
  (In millions)
ASSETS  
Current assets $110
Property, plant & equipment 1,132
Total Assets $1,242
LIABILITIES  
Current liabilities, excluding asset retirement obligation $120
Asset retirement obligation 780
Other long-term liabilities 46
Total Liabilities $946
The net carrying value of the assets disposed included a currency translation loss of $109 million, which was recorded in “Accumulated Other Comprehensive Loss” on the Company’s consolidated balance sheet at December 31, 2016. The currency translation loss was recognized as a reduction of the net gain on sale during the third quarter of 2017 upon closing of the transactions.
Apache’s Canadian operations recorded pretax losses of $12 million and $141 millionin reimbursable corporate overhead charges for the third quarter and first nine months of 2017, respectively, compared2021, respectively.
In August 2021, Apache entered into an promissory note with APA under which Apache may borrow up to pretax losses$250 million from APA at APA’s discretion. The note has a term of $483one year, maturing on August 4, 2022, and bears interest at a variable rate per annum equal to the monthly, short-term applicable federal rate, payable semi-annually. As of September 30, 2021, there was $243 million outstanding under this note, which is reflected as “Note payable to APA Corporation” on the Company’s consolidated balance sheet.
3.    ACQUISITIONS AND DIVESTITURES
2021 Activity
During the second quarter of 2021, the Company completed the sale of certain non-core assets in the Permian Basin with a net carrying value of $157 million for cash proceeds of $174 million and $644the assumption of asset retirement obligations of $44 million. The Company has recognized a gain of approximately $63 million respectively, forin connection with the comparable periods in 2016.

U.S. Divestituressale. The transaction is subject to normal post-closing adjustments.
During the first nine months of 2017, Apache2021, the Company also completed the sale of certainother non-core assets primarilyand leasehold, acreageprimarily in the Permian and Midcontinent/Gulf Coast regions,Basin, in multiple transactions for total cash proceeds of $783$65 million. The Company recognized a gain of approximately $2 million subject to customaryupon 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
12

During the first nine months of 2017 in connection with these transactions.

North Sea GTP Divestiture
During2021, the fourth quarter of 2016, Apache entered into an agreement to sell its 30.28 percent interest in the Scottish Area Gas Evacuation system (SAGE) and its 60.56 percent interest in the Beryl pipeline in the North Sea to Ancala Midstream Acquisitions Limited (Ancala). The transaction is subject to regulatory and third-party approvals, which are ongoing in 2017. The Company received a refundable deposit in connection with this transaction, which is recorded in “Other current liabilities” on the consolidated balance sheet. The refundable deposit was $149 million as of September 30, 2017.
Leasehold and Property Acquisitions
During the third quarter and first nine months of 2017, Apache purchased $75 million and $142 million, respectively, ofcompleted leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $6 million.
On October 21, 2021, ALTM announced that it will combine with privately-owned BCP Raptor Holdco LP (BCP) in an all-stock transaction. BCP is the parent company of EagleClaw Midstream, which includes EagleClaw Midstream Ventures, the Caprock Midstream and Pinnacle Midstream businesses, and a 26.7 percent interest in the Permian Highway Pipeline.
As consideration for the transaction, ALTM will issue 50 million Class C common shares (and its North America onshore regions.subsidiary, Altus Midstream LP, will issue corresponding common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. The transaction is expected to close during the first quarter of 2022, following completion of customary closing conditions, including ALTM shareholder approval and regulatory reviews. Upon closing of the transaction, management will reevaluate whether Apache has a controlling financial interest and is the primary beneficiary of ALTM such that consolidation would continue to be required under the VIE model.


20162020 Activity
Leasehold and Property Acquisitions
During the third quarter and first nine months of 2016, Apache purchased $512020, the Company completed non-core asset and leasehold sales, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $53 million. The Company recognized a gain of approximately $5 million and $169 million, respectively,upon closing of these transactions.
The Company also completed leasehold and property acquisitions, primarily in its North America onshore regionsthe Permian Basin, for total cash consideration of $3 million.
4.    CAPITALIZED EXPLORATORY WELL COSTS
The Company’s capitalized exploratory well costs were $54 million and Egypt.
Discontinued Operations
Apache$197 million as of September 30, 2021 and December 31, 2020, respectively. The decrease is primarily attributable to the completion of the Holding Company Reorganization in which the Company sold its operationsinterests in ArgentinaSuriname, including approximately $135 million of exploratory well costs as of December 31, 2020, to APA. Refer to Note 2—Transactions with Parent Affiliate for more detail. The remaining exploratory well costs relate to North Sea offshore wells and Australia in 2014 and 2015, respectively. The resultsEgypt onshore wells where additional drilling activity was offset by dry hole write-offs during the period.
Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of operations relateddrilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to the Argentina and Australia dispositions and the losses on disposals were classified as discontinued operations in the Company’s financial statements. During 2016, the Company incurred additional losses onjustify potential development. Management is actively pursuing efforts to assess whether proved reserves can be attributed to these dispositions. The components of the Company’s loss from discontinued operations were as follows:projects.
  For the Quarter Ended September 30, For the Nine Months Ended September 30,
  2017 2016 2017 2016
  (In millions)
Loss from Australia divestiture $—
 $(23) $—
 $(23)
Loss from Argentina divestiture —
 (10) —
 (10)
Loss from discontinued operations, net of tax $—
 $(33) $—
 $(33)
Transaction, Reorganization, and Separation
During the third quarter and first nine months of 2017, Apache recorded $20 million and $14 million, respectively, in expense related to asset divestitures in the U.S. and Canada and employee separation. During the third quarter and first nine months of 2016, Apache recorded $12 million and $36 million, respectively, in expense related to various asset divestitures, company reorganization, and employee separation.



3.5.    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. ApacheThe Company 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 utilizesproduction by utilizing various types of financial instruments. The Company has elected not to designate any of its derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company’s derivatives are not designatedcontracts as cash flow hedges, therefore, changes in fair value are recognized currently in earnings.hedges.
Counterparty Risk
The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, Apachethe Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2017, Apache2021, the Company had derivative positions with 1411 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, Apachethe Company may not realize the benefit of some of its derivative instruments resulting from lower commodity prices.
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Derivative Instruments
Commodity Derivative Instruments
As of September 30, 2017, Apache2021, the Company had the following open crude oil derivative positions:
    
Put Options(1)(2)
Production Period Settlement Index Mbbls Weighted Average Strike Price
October—December 2017 NYMEX WTI 8,464 $50.00
October—December 2017 Dated Brent 7,636 $51.00
(1)The remaining unamortized premium paid as of September 30, 2017, was $50 million.
(2)Subsequent to September 30, 2017, Apache entered into put option contracts settling against Dated Brent totaling 3,650 Mbbls with a strike price of $50 for the calendar year 2018.
    Fixed-Price Swaps 
Collars(3)
 
Call Options(4)
Production Period Settlement Index Mbbls Weighted Average Fixed Price Mbbls Weighted Average Floor Price Weighted Average Ceiling Price Mbbls Strike Price
January—June 2018 NYMEX WTI 2,715 $51.23 2,715 $45.00 $56.45 — —
January—June 2018 Dated Brent 2,172 $54.57 2,172 $50.00 $58.77 — —
January—December 2018 NYMEX WTI — — 6,023 $45.00 $57.02 6,023 $60.00
(3)Subsequent to September 30, 2017, Apache entered into crude oil contracts settling against NYMEX WTI totaling 730 Mbbls with a floor and ceiling of $45.00 and $56.90, respectively, for the calendar year 2018.
(4)The remaining unamortized premium paid as of September 30, 2017, was $9 million.


Fixed-Price Swaps
Production PeriodSettlement IndexMbblsWeighted Average Fixed Price
October—December 2021NYMEX WTI1,012 $58.59
October—December 2021Dated Brent828 $61.44
As of September 30, 2017, Apache2021, the Company had the following open natural gas derivative positions:crude oil financial basis swap contracts:
Production PeriodSettlement IndexMbblsWeighted Average Price Differential
October—December 2021Midland-WTI/Cushing-WTI1,012 $0.70
    
Fixed-Price Swaps(1)
Production Period Settlement Index 
MMBtu
(in 000’s)
 Weighted Average Fixed Price
October—December 2017 NYMEX Henry Hub 4,370 $3.32
January—March 2018 NYMEX Henry Hub 13,500 $3.39
January—June 2018 NYMEX Henry Hub 22,625 $3.17
April—June 2018 NYMEX Henry Hub 16,835 $2.92
July—December 2018 NYMEX Henry Hub 18,400 $2.97
(1)Subsequent to September 30, 2017, Apache entered into fixed-price natural gas swaps settling against NYMEX Henry Hub totaling 15,180,000 MMBtu with a weighted average fixed-price of $2.95 for the second half of 2018.
As of September 30, 2017, Apache2021, the Company had the following open natural gas financial basis swap contracts:
Basis Swap PurchasedBasis Swap Sold
Production PeriodSettlement IndexMMBtu
(in 000’s)		Weighted Average Price DifferentialMMBtu
(in 000’s)		Weighted Average Price Differential
October—December 2021NYMEX Henry Hub/IF Waha11,050 $(0.42)— —
October—December 2021NYMEX Henry Hub/IF HSC— —11,050 $(0.07)
January—December 2022NYMEX Henry Hub/IF Waha43,800 $(0.45)— —
January—December 2022NYMEX Henry Hub/IF HSC— —43,800 $(0.08)
January—December 2023NYMEX Henry Hub/IF Waha29,200 $(0.40)— —
January—December 2023NYMEX Henry Hub/IF HSC— —29,200 $0.02
Embedded Derivatives
Altus Preferred Units Embedded Derivative
During the second quarter of 2019, Altus Midstream LP, a subsidiary of ALTM, issued and sold Series A Cumulative Redeemable Preferred Units (Preferred Units). Certain redemption features embedded within the Preferred Units require bifurcation and measurement at fair value. For further discussion of this derivative, refer to “Fair Value Measurements” below and Note 13—Redeemable Noncontrolling Interest - Altus.
Pipeline Capacity Embedded Derivatives
During the fourth quarter of 2019 and first quarter of 2020, the Company entered into an agreement to assign a portion of its contracted capacity under an existing transportation agreement to a third party. Embedded in this agreement is an arrangement under which the Company has the potential to receive payments calculated based on pricing differentials between Houston Ship Channel and Waha during calendar years 2020 and 2021. This feature requires bifurcation and measurement of the change in market value for each period. Unrealized gains or losses in the fair value of this feature are recorded as “Derivative instrument gains (losses), net” under “Revenues and Other” in the statement of consolidated operations. Any proceeds received are deferred and reflected in income over the original tenure of the host contract.
14
Production Period Settlement Index 
MMBtu
(in 000’s)
 Weighted Average Price Differential
January—March 2018 NYMEX Henry Hub/Waha 9,450 $(0.43)
July—December 2018 NYMEX Henry Hub/Waha 33,120 $(0.53)
October—December 2018 NYMEX Henry Hub/Waha 1,380 $(0.51)
January—March 2019 NYMEX Henry Hub/Waha 1,350 $(0.54)
January—June 2019 NYMEX Henry Hub/Waha 32,580 $(0.53)
January—December 2019 NYMEX Henry Hub/Waha 14,600 $(0.45)

Fair Value Measurements
Apache’s commodity derivative instruments consist of variable-to-fixed price commodity swaps, options, and collars. The fair values of the Company’s derivatives are not actively quoted in the open market. The Company uses a market approach to estimate the fair values of its derivative instruments on a recurring basis, utilizing commodity futures pricing for the underlying commodities provided by a reputable third party, a Level 2 fair value measurement.
The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:
  Fair Value Measurements Using      
  Quoted Price in Active Markets (Level 1) Significant Other Inputs (Level 2) 
Significant Unobservable Inputs
(Level 3)
 Total Fair Value 
Netting(1)
 Carrying Amount
  (In millions)
September 30, 2017            
Assets:            
Commodity Derivative Instruments $—
 $24
 $—
 $24
 $(7) $17
Liabilities:            
Commodity Derivative Instruments —
 7
 —
 7
 (7) —
December 31, 2016            
Assets:            
Commodity Derivative Instruments $—
 $—
 $—
 $—
 $—
 $—
Liabilities:            
Commodity Derivative Instruments —
 —
 —
 —
 —
 —
Fair Value Measurements Using
Quoted Price in Active Markets
(Level 1)		Significant Other Inputs
(Level 2)		Significant Unobservable Inputs
(Level 3)		Total
Fair Value
Netting(1)
Carrying Amount
(In millions)
September 30, 2021
Liabilities:
Commodity derivative instruments— 32 — 32 — 32 
Pipeline capacity embedded derivatives— 47 — 47 — 47 
Preferred Units embedded derivative— — 120 120 — 120 
December 31, 2020
Assets:
Commodity derivative instruments$— $11 $— $11 $— $11 
Liabilities:
Pipeline capacity embedded derivative— 53 — 53 — 53 
Preferred Units embedded derivative— — 139 139 — 139 
(1)    The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.
The fair values of the Company’s derivative instruments and pipeline capacity embedded derivatives are not actively quoted in the open market. The Company primarily uses a market approach to estimate the fair values of these derivatives on a recurring basis, utilizing futures pricing for the underlying positions provided by a reputable third party, a Level 2 fair value measurement.
The fair value of the Preferred Units embedded derivative is calculated using the income approach, a Level 3 fair value measurement, and based on a range of factors, including expected future interest rates using the Black-Karasinski model, Altus’ imputed interest rate, interest rate volatility, the expected timing of periodic cash distributions, the estimated timing for the potential exercise of the exchange feature, and anticipated dividend yields of the Preferred Units. As of the September 30, 2021 valuation date, the Company used the forward B-rated Energy Bond Yield curve to develop the following key unobservable inputs used to value this embedded derivative:
(1)TheQuantitative Information About Level 3 Fair Value Measurements
Fair Value as of
September 30, 2021
Valuation TechniqueSignificant Unobservable InputsRange/Value
(In millions)
Preferred Units embedded derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.$120 Option ModelAltus’ Imputed
Interest Rate		5.53-11.54%
Interest Rate
Volatility		38.03%


A one percent increase in the imputed interest rate assumption would significantly increase the value of the embedded derivative as of September 30, 2021, while a one percent decrease would lead to a similar decrease in value as of September 30, 2021. The assumed expected timing until exercise of the exchange option as of September 30, 2021 was 4.70 years.
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Derivative Activity Recorded in the Consolidated Balance Sheet
All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:
  September 30, 2017 December 31, 2016
  (In millions)
Current Assets: Prepaid assets and other $13
 $—
Other Assets: Deferred charges and other 4
 —
Total Assets $17
 $—
September 30,
2021
December 31,
2020
(In millions)
Current Assets: Other current assets$— $6 
Other Assets: Deferred charges and other— 5 
Total derivative assets$— $11 
Current Liabilities: Other current liabilities$31 $— 
Deferred Credits and Other Noncurrent Liabilities: Other168 192 
Total derivative liabilities$199 $192 
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,
2021202020212020
 (In millions)
Realized:
Commodity derivative instruments$(37)$(83)$63 $(119)
Foreign currency derivative instruments— — — (1)
Realized gain (loss), net(37)(83)63 (120)
Unrealized:
Commodity derivative instruments29 91 (43)(3)
Pipeline capacity embedded derivatives3 8 6 (62)
Foreign currency derivative instruments— 3 — (1)
Preferred units embedded derivative5 (3)19 (76)
Unrealized loss, net37 99 (18)(142)
Derivative instrument gains (losses), net$— $16 $45 $(262)
  For the Quarter Ended September 30, For the Nine Months Ended September 30,
  2017 2016 2017 2016
  (In millions)
Realized gain (loss):        
Derivative settlements, realized gain $23
 $—
 $23
 $—
Amortization of put premium, realized loss (50) —
 (50) —
Unrealized loss (83) —
 (42) —
Derivative instrument losses, net $(110) $—
 $(69) $—
UnrealizedDerivative instrument gains and losses are recorded in “Derivative instrument gains (losses), net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains (losses) for derivative activity recorded in the statement of consolidated operations isare reflected in the statement of consolidated cash flows separately as a component of “Unrealized derivative instrument losses (gains), net” in “Adjustments to reconcile net income (loss) to net cash provided by operating activities.”


4.   CAPITALIZED EXPLORATORY WELL COSTS
The Company’s capitalized exploratory well costs were $369 millionCompany seeks to maintain a balance between “first of month” and $264 million at September 30, 2017“gas daily pricing” for its U.S. natural gas portfolio and December 31, 2016, respectively. The increase is primarily attributable to additional drillingsales activities in a given month as part of its ordinary course of business. This is typically implemented through a combination of physical and financial contracts that settle monthly. In January 2021, the U.S. duringCompany entered into financial contracts that increased its exposure to “gas daily pricing” and reduced its exposure to “first of month” pricing for February 2021. The Company realized a gain of $147 million in connection with these contracts in the period, partially offset by successful transfers and dry hole write-offs. No suspended exploratory well costs previously capitalized for greater than one year at December 31, 2016 were charged to dry hole expense during the nine months ended September 30, 2017. Projects with suspended exploratory well costs capitalized forfirst quarter of 2021 as a period greater than one year since the completionresult 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.extreme daily gas price volatility across Texas in February resulting from Winter Storm Uri.
16
5.OTHER CURRENT LIABILITIES

6.    OTHER CURRENT ASSETS
The following table provides detail of the Company’s other current liabilities asassets:
September 30,
2021
December 31,
2020
 (In millions)
Inventories$441 $492 
Drilling advances102 113 
Prepaid assets and other56 71 
Total Other current assets$599 $676 
7.    EQUITY METHOD INTERESTS
As of September 30, 20172021 and December 31, 2016:2020, the Company, through its ownership of Altus, had the following equity method interests in 4 Permian Basin long-haul pipeline entities, which are accounted for under the equity method of accounting. For each of the equity method interests, Altus has the ability to exercise significant influence based on certain governance provisions and its participation in activities and decisions that impact the management and economic performance of the equity method interests. The table below presents the ownership percentages held by the Company and associated carrying values for each entity:
Interest
September 30,
2021
December 31,
2020
(In millions)
Gulf Coast Express Pipeline, LLC16.0%$277 $284 
EPIC Crude Holdings, LP15.0%165 176 
Permian Highway Pipeline, LLC26.7%632 615 
Shin Oak Pipeline (Breviloba, LLC)33.0%464 480 
Total Altus equity method interests$1,538 $1,555 
As of September 30, 2021 and December 31, 2020, unamortized basis differences included in the equity method interest balances were $37 million and $38 million, respectively. These amounts represent differences in Altus’ contributions to date and Altus’ underlying equity in the separate net assets within the financial statements of the respective entities. Unamortized basis differences will be amortized into net income over the useful lives of the underlying pipeline assets.
The following table presents the activity in Altus’ equity method interests for the nine months ended September 30, 2021:
Gulf Coast Express
Pipeline LLC		EPIC Crude
Holdings, LP		Permian Highway
Pipeline LLC		Breviloba, LLCTotal
(In millions)
Balance at December 31, 2020$284 $176 $615 $480 $1,555 
Capital contributions— 2 25 — 27 
Distributions(37)— (52)(39)(128)
Equity income (loss), net30 (14)44 23 83 
Accumulated other comprehensive income— 1 — — 1 
Balance at September 30, 2021$277 $165 $632 $464 $1,538 
Summarized Combined Financial Information
The following table presents summarized selected income statement data for Altus’ equity method interests (on a 100 percent basis):
For the Nine Months Ended
September 30,
20212020
(In millions)
Operating revenues$812 $531 
Operating income401 267 
Net income340 217 
Other comprehensive income (loss)4 (1)
17
  September 30, 2017 December 31, 2016
  (In millions)
Accrued operating expenses $73
 $110
Accrued exploration and development 691
 463
Accrued compensation and benefits 99
 201
Accrued interest 108
 145
Accrued income taxes 68
 22
Current asset retirement obligation 35
 66
Refundable deposits 149
 174
Other 109
 77
Total other current liabilities $1,332
 $1,258

8.    OTHER CURRENT LIABILITIES
6.ASSET RETIREMENT OBLIGATION
The following table provides detail of the Company’s other current liabilities:
September 30,
2021
December 31,
2020
 (In millions)
Accrued operating expenses$135 $91 
Accrued exploration and development167 167 
Accrued compensation and benefits180 170 
Accrued interest92 140 
Accrued income taxes54 25 
Current asset retirement obligation56 56 
Current operating lease liability87 116 
Current portion of derivatives at fair value31 — 
Other135 97 
Total Other current liabilities$937 $862 
9.    ASSET RETIREMENT OBLIGATION
The following table describes changes to the Company’s asset retirement obligation (ARO) liability forliability:
September 30,
2021
(In millions)
Asset retirement obligation, December 31, 2020$1,944 
Liabilities incurred3 
Liabilities settled(20)
Liabilities divested(44)
Accretion expense85 
Asset retirement obligation, September 30, 20211,968 
Less current portion(56)
Asset retirement obligation, long-term$1,912 
10.    DEBT AND FINANCING COSTS
The following table presents the nine-month periodcarrying values of the Company’s debt:
September 30,
2021
December 31,
2020
(In millions)
Notes and debentures before unamortized discount and debt issuance costs(1)
$6,344 $8,052 
Altus credit facility(2)
657 624 
Apache credit facility(2)
440 150 
Finance lease obligations36 38 
Unamortized discount(29)(35)
Debt issuance costs(40)(57)
Total debt7,408 8,772 
Current maturities(215)(2)
Long-term debt$7,193 $8,770 
(1)    The fair values of the Company’s notes and debentures were $7.0 billion and $8.5 billion as of September 30, 2021 and December 31, 2020, respectively.
Apache uses a market approach to determine the fair values of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).
(2)    The carrying value of borrowings on credit facilities approximates fair value because interest rates are variable and reflective of market rates.
As of September 30, 2021, current debt included $213 million, net of discount, of 3.25% senior notes due April 15, 2022 and $2 million of finance lease obligations. As of December 31, 2020, current debt included $2 million of finance lease obligations.
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During the quarter ended September 30, 2017:2021, Apache closed cash tender offers for certain outstanding notes and accepted for purchase $1.7 billion aggregate principal amount of certain notes. Apache paid holders an aggregate $1.8 billion, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $105 million loss on extinguishment of debt, including $98 million of unamortized debt discount and issuance costs, in connection with the note purchases.
During the nine months ended September 30, 2021, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $22 million for an aggregate purchase price of $20 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $2 million. The Company recognized a $1 million net gain on extinguishment of debt as part of these transactions.
The Company intends to reduce debt outstanding under its indentures from time to time.
In March 2018, the Company entered into a revolving credit facility with commitments totaling $4.0 billion. In March 2019, the term of this facility was extended by one year to March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exercise of an extension option. The Company can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of September 30, 2021. The facility is for general corporate purposes. As of September 30, 2021, there were $440 million of borrowings and an aggregate £478 million and $20 million in letters of credit outstanding under this facility. As of December 31, 2020, there were $150 million of borrowings and an aggregate £633 million and $40 million in letters of credit outstanding under this facility. The outstanding letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced the Company’s credit rating from BBB to BB+ on March 26, 2020.
There were no borrowings outstanding under the Company’s commercial paper program as of September 30, 2021 and December 31, 2020. The Company did not use its commercial paper program during the first six months of 2021 and terminated the program during the third quarter of 2021.
Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2021, there were no borrowings and £118 million and $17 million in letters of credit outstanding under these facilities. As of December 31, 2020, there were no borrowings and £34 million and $17 million in letters of credit outstanding under these facilities.
In November 2018, Altus Midstream LP entered into a revolving credit facility for general corporate purposes that matures in November 2023 (subject to Altus Midstream LP’s 2, one-year extension options). The agreement for this facility, as amended, provides aggregate commitments from a syndicate of banks of $800 million. All aggregate commitments include a letter of credit subfacility of up to $100 million and a swingline loan subfacility of up to $100 million. Altus Midstream LP may increase commitments up to an aggregate $1.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. As of September 30, 2021, there were $657 million of borrowings and a $2 million letter of credit outstanding under this facility. As of December 31, 2020, there were $624 million of borrowings and no letters of credit outstanding under this facility. The Altus Midstream LP credit facility is unsecured and is not guaranteed by Apache, APA Corporation, or any of its subsidiaries.
Financing Costs, Net
The following table presents the components of the Company’s financing costs, net:
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
 2021202020212020
 (In millions)
Interest expense$102 $113 $324 $327 
Amortization of debt issuance costs1 2 6 6 
Capitalized interest— (3)— (9)
Loss (gain) on extinguishment of debt105 (12)104 (152)
Interest income(1)(1)(6)(4)
Interest income from APA Corporation, net(15)— (35)— 
Financing costs, net$192 $99 $393 $168 
19
  (In millions)
Asset retirement obligation at December 31, 2016 $2,498
Liabilities incurred 39
Liabilities divested (810)
Liabilities settled (30)
Accretion expense 103
Revisions in estimated liabilities 66
Asset retirement obligation at September 30, 2017 1,866
Less current portion 35
Asset retirement obligation, long-term $1,831



11.    INCOME TAXES
7.INCOME TAXES
The Company estimates its annual effective income tax rate for continuing operations in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments ofon the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur.
In August 2017, Apache completedDuring the sale of ACL. For more information regarding this transaction, please refer to Note 2—Acquisitions and Divestitures. As a result of this transaction, Apache recorded a deferred tax asset associated with its realizable capital loss on the sale of ACL, and a decrease in the Company’s deferred tax liability associated with its investment in foreign subsidiaries. In the third and second quarters of 2017, the Company recorded a $2 million deferred income tax expense and a $674 million deferred income tax benefit, respectively, in connection with these transactions.
Apache’s third quarter of 20172021, the Company’s effective income tax rate was primarily impacted by gainsa loss on offshore decommissioning contingency and an increase in the saleamount of oil and gas properties and a $30 million currentvaluation allowance against its U.S. deferred tax benefit associated with U.S. federal income tax credits. On September 15, 2016, U.K. Finance Act 2016 received Royal Assent. Under the enacted legislation, the corporate income tax rate on North Sea oil and gas profits was reduced from 50 percent to 40 percent effective January 1, 2016. As a result of the enacted legislation, inassets. During the third quarter of 20162020, the Company recorded a deferred tax benefit of $235 million related to the remeasurement of the Company’s December 31, 2015 U.K. deferred income tax liability.
Apache’s 2017 year-to-date effective income tax rate iswas primarily impacted by an increase in the decrease inamount of valuation allowance against its U.S. deferred taxes associated with its investments in foreign subsidiaries, gains on the sale of oil and gas properties, non-cash impairments of thetax assets. The Company’s PRT decommissioning asset, and the current tax benefit associated with U.S. federal income tax credits. Apache’s 20162021 year-to-date effective income tax rate was primarily impacted by non-cash impairmentsa loss contingency in connection with decommissioning of previously sold Gulf of Mexico properties and a decrease in the carrying valueamount of thevaluation allowance against its U.S. deferred tax assets. The Company’s 2020 year-to-date effective income tax rate was primarily impacted by oil and gas properties, non-cashasset impairments, of the Company’s PRT decommissioning asset, the impact of the change in U.K. statutory income tax rate,a goodwill impairment, and an increase in the amount of valuation allowances onallowance against its U.S. and Canadian deferred tax assets.
Apache and its subsidiaries areThe Company is subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. In April 2017,The Company is currently under audit by the Internal Revenue Service (IRS) began their audit offor the Company’s 2014 income2014-2017 tax year. The Companyyears and is also under audit in various states and in most of the Company’s foreign jurisdictions as part of its normal course of business.


12.    COMMITMENTS AND CONTINGENCIES
8.DEBT AND FINANCING COSTS
The following table presents the carrying amounts and estimated fair values of the Company’s outstanding debt as of September 30, 2017 and December 31, 2016:
  September 30, 2017 December 31, 2016
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
  (In millions)
Commercial paper and committed bank facilities $—
 $—
 $—
 $—
Notes and debentures 8,483
 9,094
 8,544
 9,183
Total Debt $8,483
 $9,094
 $8,544
 $9,183
The Company’s debt is recorded at the carrying amount, net of related unamortized discount and debt issuance costs, on its consolidated balance sheet. When recorded, the carrying amount of the Company’s commercial paper, committed bank facilities, and uncommitted bank lines approximates fair value because the interest rates are variable and reflective of market rates. Apache uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).
The following table presents the carrying value of the Company’s debt as of September 30, 2017 and December 31, 2016:
  September 30, 2017 December 31, 2016
  (In millions)
Debt before unamortized discount and debt issuance costs $8,580
 $8,650
Unamortized discount (48) (50)
Debt issuance costs (49) (56)
Total debt 8,483
 8,544
Current maturities (550) —
Long-term debt $7,933
 $8,544

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

As of September 30, 2017, the Company had a revolving credit facility that matures in June 2020, subject to Apache’s two one-year extension options. The facility provides for aggregate commitments of $3.5 billion (including a $750 million letter of credit subfacility), with rights to increase commitments up to an aggregate $4.5 billion. Proceeds from borrowings may be used for general corporate purposes. Apache’s available borrowing capacity under this facility supports its $3.5 billion commercial paper program. The commercial paper program, which is subject to market availability, facilitates Apache borrowing funds for up to 270 days at competitive interest rates. As of September 30, 2017, the Company had no commercial paper or borrowings under committed bank facilities or uncommitted bank lines outstanding.

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

In November 2016, the Company initiated a program to purchase in the open market up to $250 million in aggregate principal amount of senior notes issued under its indentures. In the fourth quarter of 2016, the Company purchased and canceled $181 million aggregate principal amount of its senior notes through open market repurchases for $182 million in cash, including accrued interest and $0.5 million of premium.



In January 2017, the Company purchased and canceled an additional $69 million aggregate principal amount of senior notes for $71 million in cash, including accrued interest and $1 million of premium, which completed the open market repurchase program. These repurchases resulted in a $1 million net loss on extinguishment of debt, which is included in “Financing costs, net” in the Company’s consolidated statement of operations. The net loss includes an acceleration of related discount and deferred financing costs.

In August 2017, the Company assumed the obligations of Apache Finance Canada Corporation (AFCC) in respect of $300 million 7.75% notes due in 2029 which AFCC issued and the Company guaranteed pursuant to the governing indenture. The assumption was permitted by the indenture and effected pursuant to a supplemental indenture thereto. As a result of the assumption, the Company is the obligor under the notes and indenture, and AFCC is released from its obligations thereunder. The $300 million 7.75% notes historically have been included in the Company’s long-term debt; accordingly, the assumption did not change the Company’s long-term debt or total debt.
Financing Costs, Net
The following table presents the components of Apache’s financing costs, net:
  For the Quarter Ended September 30, For the Nine Months Ended September 30,
  2017 2016 2017 2016
  (In millions)
Interest expense $113
 $116
 $344
 $348
Amortization of deferred loan costs 3
 2
 7
 5
Capitalized interest (12) (13) (39) (36)
Loss on extinguishment of debt —
 —
 1
 —
Interest income (3) (3) (13) (6)
Financing costs, net $101
 $102
 $300
 $311



9.COMMITMENTS AND CONTINGENCIES
Legal Matters
ApacheThe Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls.controls, which also may include controls related to the potential impacts of climate change. As of September 30, 2017,2021, the Company has an accrued liability of approximately $37$68 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. Apache’sThe Company’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’sthe Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. For material matters that Apachethe Company 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 seerefer to Note 10—11—Commitments and Contingencies to the consolidated financial statements contained in Apache’sthe Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.2020.
Argentine Environmental Claims and Argentina Tariff
No material change in the status of the YPF Sociedad Anónima and Pioneer Natural Resources Company indemnities mattersmatter has occurred since the filing of Apache’sthe Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.2020.
Louisiana Restoration
As more fully described in Apache’sthe Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016, numerous2020, Louisiana surface owners have filedoften file lawsuits or assert claims or sent demand letters to variousagainst oil and gas companies, including Apache,the Company, claiming that under either express or implied lease terms or Louisiana law,operators and working interest owners in the companieschain of title are liable for damageenvironmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to theirits original condition, as well as damages for contamination and cleanup.
On July 24, 2013, a lawsuit captioned Board of Commissionersregardless of the Southeast Louisiana Flood Protection Authority – East v. Tennessee Gas Pipelinevalue of the underlying property. From time to time, restoration lawsuits and claims are resolved by the Company et al., Case No. 2013-6911 was filed in the Civil District Court for the Parish of Orleans, State of Louisiana, in which plaintiff on behalf of itself and as the board governing the levee districts of Orleans, Lake Borgne Basin, and East Jefferson allegedamounts that Louisiana coastal lands have been damaged as a result of oil and gas industry activity, including a network of canals for access and pipelines. The defendants removed the case from state court to federal court and, on February 13, 2015, the federal court entered judgment in favor of defendants dismissing all of plaintiff’s claims with prejudice. Plaintiff appealed the lower court’s dismissalare not material to the 5th Circuit Court of AppealsCompany, while new lawsuits and additionally challengedclaims are asserted against the defendants’ rightCompany. With respect to remove the case to federal court. On March 3, 2017, the 5th Circuit Court of Appeals affirmed the propriety of federal jurisdiction based in part on Apache’s argument that plaintiff’s state-based claims required a resolution of substantial questions of federal law and also affirmed the dismissaleach of the action. The Plaintiff filed a Petition for a Writ of Certiorari withpending lawsuits and claims, the United States Supreme Court. On October 30, 2017,amount claimed is not currently determinable or is not material. Further, the United States Supreme Court denied reviewoverall exposure related to these lawsuits and declinedclaims is not currently determinable. While adverse judgments against the Company are possible, the Company intends to consider the plaintiff’s Petition of Certiorari.actively defend these lawsuits and claims.
20

Starting in November of 2013 and continuing into 2017,2021, several Parishesparishes in Louisiana have pending lawsuits against many oil and gas producers, including Apache.the Company. These cases are pending inwere all removed to federal and state courts in Louisiana. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable state law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. While an adverse judgmentjudgments against Apachethe Company might be possible, Apachethe Company intends to vigorously oppose these claims.
No other material change in the status of these matters has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.



Apollo Exploration Lawsuit
In a fourth amended petition filed on March 21, 2016, in a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs have reduced their alleged damages to approximately $500in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to certain purchase and sale agreements, mineral leases, and areasarea of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The Court recently granted twotrial court entered final judgment in favor of Apache’s motionsthe Company, ruling that the plaintiffs take nothing by their claims and awarding the Company its attorneys’ fees and costs incurred in defending the lawsuit. The court of appeals affirmed in part and reversed in part the trial court’s judgment thereby reinstating some of plaintiff’s claims. Further appeal is pending.
Australian Operations Divestiture Dispute
Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant 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, the Company filed suit against Quadrant for summary judgment further limitingbreach of the plaintiffs’ theoriesQuadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and potential damages. Apachea counterclaim seeking approximately AUD $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.
Canadian Operations Divestiture Dispute
Pursuant to a Sale and Purchase Agreement dated July 6, 2017 (Paramount SPA), the Company and its subsidiaries divested their remaining Canadian operations to Paramount Resources LTD (Paramount). Closing occurred on August 16, 2017. On September 11, 2019, 4 ex-employees of Apache Canada on behalf of themselves and individuals employed by Apache Canada LTD on July 6, 2017, filed an Amended Statement of Claim in a matter styled Stephen Flesch et. al. v Apache Corporation et. al., No. 1901-09160 Court of Queen’s Bench of Alberta against the Company and others seeking class certification and a finding that the Paramount SPA amounted to a Change of Control of the Company, entitling them to accelerated vesting under the Company’s equity plans. In the suit, the purported class seeks approximately $60 million USD and punitive damages. The Company believes that Plaintiffs’ claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity.
California and Delaware Litigation
On July 17, 2017, in 3 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 and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in 2 separate actions, the City of Santa Cruz and Santa Cruz County and in a separate action on January 22, 2018, the City of Richmond, filed similar lawsuits against many of the same defendants. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants. After removal of all such lawsuits to federal court, the district court remanded them back to state court. The 9th Circuit Court of Appeals’ affirmance of this remand decision was appealed to the U.S. Supreme Court. That appeal was decided by the U.S. Supreme Court ruling in a similar case, BP p.l.c. v. Mayor and City Council of Baltimore. As a result, the California cases have been sent back to the 9th Circuit for further appellate review of the decision to remand the cases to state court. Further activity in the cases, has been stayed pending further appellate review.
On September 10, 2020, the State of Delaware filed suit, individually and on behalf of the people of the State of Delaware, against over 25 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories.
21

The Company believes that it is not subject to jurisdiction of the California courts and that claims made against it in the Delaware litigation are baseless. The Company intends to challenge jurisdiction in California and to vigorously defend the Delaware lawsuit.
Castex Lawsuit
In a case styled Apache Corporation v. Castex Offshore, Inc, et. al., Cause No. 2015-48580, in the 113th Judicial District Court of Harris County, Texas, Castex filed claims for alleged damages of approximately $200 million, relating to overspend on the Belle Isle Gas Facility upgrade, and the drilling of 5 sidetracks on the Potomac #3 well. After a jury trial, a verdict of approximately $60 million, plus fees, costs, and interest was entered against the Company. The Fourteenth Court of Appeals of Texas reversed the judgment, in part, reducing the judgment to approximately $13.5 million, plus fees, costs, and interest against the Company. Further appeal is pending.
Oklahoma Class Actions
The Company is a party to 2 purported class actions in Oklahoma styled Bigie Lee Rhea v. Apache Corporation, Case No. 6:14-cv-00433-JH, and Albert Steven Allen v. Apache Corporation, Case No. CJ-2019-00219. The Rhea case has been certified and includes a class of royalty owners seeking damages of approximately $200 million for alleged breach of the implied covenant to market relating to post-production deductions and alleged NGL uplift value. The Allen case has not been certified and seeks to represent a group of owners who have allegedly received late royalty and other payments under Oklahoma statutes. The amount of this claim is not yet reasonably determinable. While adverse judgments against the Company are possible, the Company intends to vigorously defend these lawsuits and claims.
Shareholder and Derivative Lawsuits
On February 23, 2021, a case captioned Plymouth County Retirement System v. Apache Corporation, et al. was filed in the United States District Court for the Southern District of Texas (Houston Division) against the Company and certain current and former officers. The complaint, which is a shareholder lawsuit styled as a class action, (1) alleges that the Company intentionally used unrealistic assumptions regarding the amount and composition of available oil and gas in Alpine High; (2) alleges that the Company did not have the proper infrastructure in place to safely and/or economically drill and/or transport those resources even if they existed in the amounts purported; (3) alleges that these statements and omissions artificially inflated the value of the Company’s operations in the Permian Basin; and (4) alleges that, as a result, the Company’s public statements were materially false and misleading. On March 4, 2021, another lawsuit, captioned Brian Schwegel v. Apache Corporation, et al., was filed in the United States District Court for the Southern District of Texas (Houston Division) alleging identical allegations. The Company believes that all plaintiffs’ claims lack merit and further that plaintiffs’ alleged damages, even as amended, are grossly inflated. Apache willintends to vigorously oppose the claims. No other material changedefend these lawsuits.
On March 16, 2021, a case captioned William Wessels, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the status334th District Court of these matters has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.
Escheat Audits
There has been no material change with respectHarris County, Texas. The case purports to the reviewbe a derivative action brought against senior management and Company directors over many of the bookssame allegations included in the Plymouth County Retirement System matter and recordsasserts claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. The defendants believe the Companyplaintiff’s claims lack merit and its subsidiaries and related entities by the State of Delaware, Department of Finance (Unclaimed Property),intend to determine compliance with the Delaware Escheat Laws, since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.vigorously defend this lawsuit.
Environmental Matters
As of September 30, 2017,2021, the Company had an undiscounted reserve for environmental remediation of approximately $4$2 million.
On September 11, 2020, the Company received a Notice of Violation and Finding of Violation, and accompanying Clean Air Act Information Request, from the U.S. Environmental Protection Agency (EPA) following site inspections in April 2019 at several of the Company’s oil and natural gas production facilities in Lea and Eddy Counties, New Mexico. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings; however, at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.
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On December 29, 2020, the Company received a Notice of Violation and Opportunity to Confer, and accompanying Clean Air Act Information Request, from the EPA following helicopter flyovers in September 2019 of several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings; however, at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.
The Company is not aware of any environmental claims existing as of September 30, 2017,2021 that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.
ACL, a formerPotential Obligation to Decommission Sold Properties
In 2013, Apache sold its Gulf of Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the Company, previously reported produced water spillspurchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a remote areabeneficiary and which were funded by 2 net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the Bellow FieldU.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a hydrogen sulfidesingle Trust (Trust A) funded by both remaining NPIs. Currently, Apache holds 2 bonds (Bonds) and oil emulsion leak5 Letters of Credit to secure Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets.
On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets will be used to fund decommissioning of Legacy GOM Assets.
In September 2021, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund its decommissioning obligations on certain of the Legacy GOM Assets that GOM Shelf is currently required to perform. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notification to BSEE. Apache expects to receive such orders on the other Legacy GOM Properties included in GOM Shelf’s notification letter. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the Zama area. The Company sold ACL infuture and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.
As and when Apache incurs costs to decommission any Legacy GOM Asset and GOM Shelf does not reimburse Apache, Apache will obtain reimbursement from Trust A, the Bonds, and the Letters of Credit until such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a transactionstandby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets.
If the combination of GOM Shelf’s net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that was completedApache may be ordered by BSEE to perform or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, Apache may be forced to effectively use its available cash to fund the deficit.
23

As of September 30, 2021, Apache estimates that its potential liability to fund decommissioning of GOM Legacy Assets it may be ordered to perform ranges from $1.2 billion to $1.4 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, in the third quarter of 2017.2021, the Company recorded a contingent liability of $1.2 billion, representing the estimated costs of decommissioning it may be required to perform on GOM Legacy Assets under the caption “Decommissioning contingency for sold Gulf of Mexico properties” in the Company’s consolidated balance sheet. The Canadian environmental litigationCompany also recorded a $740 million asset, which represents the amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and liabilities remained with ACLthe Letters of Credit for decommissioning it may be required to perform on GOM Legacy Assets under the caption “Decommissioning security for sold Gulf of Mexico properties”. A “Loss on previously sold Gulf of Mexico properties” in the amount of $446 million was recognized in the third quarter of 2021 to reflect the net impact to the Company’s statement of consolidated operations. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and are now the responsibilityplanned abandonment logistics could result in a liability in excess of the acquirer.
amount accrued. In addition, tosignificant changes in the matters for which the Company has already accrued, on July 17, 2017, in three separate actions, San Mateo County, California, Marin County, California, and the Citymarket price 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 damagesnatural gas liquids could further impact Apache’s estimate of its contingent liability to decommission GOM Legacy Assets.
13.    REDEEMABLE NONCONTROLLING INTEREST - ALTUS
Preferred Units Issuance
On June 12, 2019, Altus Midstream LP issued and sold Preferred Units for an aggregate issue price of $625 million in a private offering exempt from the registration requirements of the Securities Act (the Closing). Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers.
Classification
The carrying amount of the Preferred Units are recorded as “Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners” classified as temporary equity on the Company’s consolidated balance sheet based on the terms of the Preferred Units, including the redemption rights with respect thereto.
Measurement
Altus applies a two-step approach to subsequent measurement of the redeemable noncontrolling interest related to the Preferred Units by first allocating a portion of the net income of Altus Midstream LP in accordance with the terms of the partnership agreement. An additional adjustment to the carrying value of the Preferred Unit redeemable noncontrolling interest at each period end may be recorded, if applicable. The amount of such adjustment is determined based upon the accreted value method to reflect the passage of time until the Preferred Units are exchangeable at the option of the holder. Pursuant to this method, the net transaction price is accreted using the effective interest method to the Redemption Price calculated at the seventh anniversary of the Closing. The total adjustment is limited to an amount such that the carrying amount of the Preferred Unit redeemable noncontrolling interest at each period end is equal to the greater of (a) the sum of (i) the carrying amount of the Preferred Units, plus (ii) the fair value of the embedded derivative liability and (b) the accreted value of the net transaction price.
24

Activity related to the Preferred Units is as follows:
Units
Outstanding
Financial
Position(1)
(In millions, except unit data)
Redeemable noncontrolling interest — Preferred Unit at: December 31, 2019638,163 $555 
Distribution of in-kind additional Preferred Units22,531 — 
Cash distributions to Altus Preferred Unit limited partners— (23)
Allocation of Altus Midstream LP net incomeN/A76 
Redeemable noncontrolling interest — Preferred Unit at: December 31, 2020660,694 608 
Cash distributions to Altus Preferred Unit limited partners— (34)
Dividends payable to Altus Preferred Unit limited partners— (12)
Allocation of Altus Midstream LP net incomeN/A60 
Accreted value adjustmentN/A13 
Redeemable noncontrolling interest — Preferred Unit at: September 30, 2021660,694 635 
Preferred Units embedded derivative(2)
120 
$755 
(1)    The Preferred Units are redeemable at Altus Midstream LP’s option at a redemption price (the Redemption Price), which as of September 30, 2021 is calculated as the greater of (i) an 11.5 percent internal rate of return and (ii) a 1.3 times multiple of invested capital. As of September 30, 2021, the Redemption Price would have been based on a 1.3 times multiple of invested capital, which was $813 million, less certain cash distributions. This was greater than using an 11.5 percent internal rate of return, which would equate to a redemption value of $730 million.
(2)    Certain redemption features embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. Refer to Note 5—Derivative Instruments and Hedging Activities for discussion of the fair value changes in the embedded derivative liability during the period.
N/A - not applicable.
14.    CAPITAL STOCK AND EQUITY
Upon consummation of the Holding Company Reorganization, each outstanding share of Apache common stock automatically converted into a share of APA common stock on a 1-for-one basis. As a result, each stockholder of Apache now owns the same number of shares of APA common stock that such stockholder owned of Apache common stock immediately prior to the Holding Company Reorganization. As a result of global warming. Plaintiffs seek unspecified damagesthe Holding Company Reorganization, Apache recorded various intercompany activities during the first quarter ended March 31, 2021, as capital transactions, which are reflected in Apache’s Statement of Consolidated Changes in Equity (Deficit) and abatementNoncontrolling Interest. Refer to Note 2—Transactions with Parent Affiliate for more detail.
Additionally, in connection with the Holding Company Reorganization, Apache transferred to APA, and APA assumed, sponsorship of all of Apache’s stock plans along with all of Apache’s rights and obligations under various tort theories.each plan. Subsequent to the Holding Company Reorganization, stock-based compensation associated with APA equity awards granted and outstanding to Apache believes that the claims made against itemployees are baseless and intendsreflected as capital contributions from APA to vigorously defend these lawsuits.Apache.
Australian Operations Divestiture Dispute
By a Sale and Purchase Agreement dated April 9, 2015 (SPA), the Company and its subsidiaries divested their remaining Australian operations to Viraciti Energy Pty Ltd, which has since been renamed Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. By letter dated June 6, 2016, Quadrant provided the Company with a placeholder notice of claim under the SPA concerning tax and other issues totaling approximately $200 million in the aggregate. The Company believes that these claims lack merit and intends to vigorously defend against them. Moreover, on September 22, 2017, subsidiaries of the Company filed suit against Quadrant for breaching the SPA and wrongfully withholding tax refunds owed under the SPA. This claim totals approximately $80 million AUD.


10.CAPITAL STOCK
Net Income (Loss) per Common Share
A reconciliation of the components of basic and diluted netNet income (loss) per common share for Apache is no longer required, as its shares are not publicly traded, and Apache is now a direct, wholly-owned subsidiary of APA.
Common Stock Dividends
During the quartersthird quarter and the first nine months ended September 30, 20172020, the Company paid $9 million and 2016, is presented$113 million, respectively, in dividends on its common stock. During the first quarter of 2020, the Company’s Board of Directors approved a reduction in the table below.
  For the Quarter Ended September 30,
  2017 2016
  Income Shares Per Share Loss Shares Per Share
  (In millions, except per share amounts)
Basic:            
Income (loss) from continuing operations $63
 381
 $0.16
 $(574) 380
 $(1.51)
Loss from discontinued operations —
 381
 —
 (33) 380
 (0.09)
Income (loss) attributable to common stock $63
 381
 $0.16
 $(607) 380
 $(1.60)
Effect of Dilutive Securities:            
Stock options and other $—
 2
 $—
 $—
 —
 $—
Diluted:            
Income (loss) from continuing operations $63
 383
 $0.16
 $(574) 380
 $(1.51)
Loss from discontinued operations —
 383
 —
 (33) 380
 (0.09)
Income (loss) attributable to common stock $63
 383
 $0.16
 $(607) 380
 $(1.60)
  For the Nine Months Ended September 30,
  2017 2016
  Income Shares Per Share Loss Shares Per Share
  (In millions, except per share amounts)
Basic:            
Income (loss) from continuing operations $848
 381
 $2.23
 $(1,190) 379
 $(3.14)
Loss from discontinued operations —
 381
 —
 (33) 379
 (0.08)
Income (loss) attributable to common stock $848
 381
 $2.23
 $(1,223) 379
 $(3.22)
Effect of Dilutive Securities:            
Stock options and other $—
 2
 $(0.01) $—
 —
 $—
Diluted:            
Income (loss) from continuing operations $848
 383
 $2.22
 $(1,190) 379
 $(3.14)
Loss from discontinued operations —
 383
 —
 (33) 379
 (0.08)
Income (loss) attributable to common stock $848
 383
 $2.22
 $(1,223) 379
 $(3.22)

The diluted earningsCompany’s quarterly dividend from $0.25 per share calculation excludes options and restricted stock units that were anti-dilutive totaling 8.4 million and 4.7 millionto $0.025 per share, effective for all dividends payable after March 12, 2020.
During the quarters ended September 30, 2017 and 2016, respectively, and 7.5 million and 6.5 million for the nine months ended September 30, 2017 and 2016, respectively.
Common Stock Dividends
For eachfirst quarter of 2021, prior to completion of the quarters ended September 30, 2017, and 2016, ApacheHolding Company Reorganization, the Company paid $95$9 million in dividends on its common stock. ForDuring the nine months ended September 30, 2017 and 2016,2021, the Company paid $285$19 million and $284 million, respectively.
Stock Repurchase Program
Apache’s Board of Directors has authorized the purchase of upin capital distributions to 40 million shares ofits parent, APA, which is reflected as “Distributions to APA Corporation” on 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 throughstatement of consolidated cash flows.
25

15.    BUSINESS SEGMENT INFORMATION
As of September 30, 2017, had repurchased a total of 32.2 million shares at an average price of $88.96 per share. The2021, the Company is not obligated to acquire any specific number of shares and has not purchased any shares during 2017.


11.ACCUMULATED OTHER COMPREHENSIVE LOSS
The following table describes changes to the Company’s accumulated other comprehensive loss by component for the nine-month period ended September 30, 2017:
  Currency Translation Adjustment Pension and Postretirement Benefit Plan Total
  (In millions)
Accumulated other comprehensive loss at December 31, 2016 $(109) $(3) $(112)
Currency translation adjustment divested(1)
 109
 —
 109
Accumulated other comprehensive loss at September 30, 2017 $—
 $(3) $(3)
(1)Currency translation adjustments resulting from translating the Canadian subsidiaries’ financial statements into U.S. dollar equivalents, prior to adoption of the U.S. dollar as their functional currency, were reported separately and accumulated in other comprehensive loss. This currency translation loss was recognized as a reduction of the net gain on divestiture during the third quarter of 2017 in connection with the Canada divestitures. For more information regarding these divestitures, please refer to Note 2—Acquisitions and Divestitures.
12.BUSINESS SEGMENT INFORMATION
Apache is engaged in a single line of business. Both domesticallyexploration and internationally, the Companyproduction (Upstream) activities across 3 operating segments: Egypt, North Sea, and U.S. The Company’s Upstream business explores for, develops, and produces crude oil, natural gas, crude oil, and natural gas liquids. At September 30, 2017, theThe Company’s Midstream business is operated by Altus Midstream Company, had production in three reporting segments: the United States, Egypt,which owns, develops, and offshore the United Kingdomoperates a midstream energy asset network 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.Permian Basin of West Texas. Financial information for each areasegment is presented below:
EgyptNorth SeaU.S.Altus Midstream
Intersegment
Eliminations
& Other(4)
Total(3)
Upstream
For the Quarter Ended September 30, 2021(In millions)
Revenues:
Oil revenues$465 $233 $484 $— $— $1,182 
Natural gas revenues63 42 188 — — 293 
Natural gas liquids revenues2 6 202 — — 210 
Oil, natural gas, and natural gas liquids production revenues530 281 874 — — 1,685 
Purchased oil and gas sales— — 374 — — 374 
Midstream service affiliate revenues— — — 35 (35)— 
530 281 1,248 35 (35)2,059 
Operating Expenses:
Lease operating expenses117 101 98 — — 316 
Gathering, processing, and transmission4 8 82 9 (35)68 
Purchased oil and gas costs— — 396 — — 396 
Taxes other than income— — 52 2 — 54 
Exploration14 4 3 — — 21 
Depreciation, depletion, and amortization128 61 143 3 — 335 
Asset retirement obligation accretion— 20 8 1 — 29 
Impairments— 18 — — — 18 
263 212 782 15 (35)1,237 
Operating Income(1)
$267 $69 $466 $20 $— 822 
Other Income (Expense):
Loss on offshore decommissioning contingency(446)
Loss on divestitures, net(2)
Other, net40 
General and administrative(64)
Transaction, reorganization, and separation(4)
Financing costs, net(192)
Income Before Income Taxes$154 
26


EgyptNorth SeaU.S.Altus Midstream
Intersegment
Eliminations
& Other(4)
Total(3)
 
United
States
 
Canada(1)
 
Egypt(2)
 North Sea 
Other
International
 TotalUpstream
For the Nine Months Ended September 30, 2021For the Nine Months Ended September 30, 2021(In millions)
Revenues:Revenues:
Oil revenuesOil revenues$1,299 $690 $1,325 $— $— $3,314 
Natural gas revenuesNatural gas revenues198 100 533 — — 831 
Natural gas liquids revenuesNatural gas liquids revenues6 16 463 — — 485 
Oil, natural gas, and natural gas liquids production revenuesOil, natural gas, and natural gas liquids production revenues1,503 806 2,321 — — 4,630 
Purchased oil and gas salesPurchased oil and gas sales— — 1,050 6 — 1,056 
Midstream service affiliate revenuesMidstream service affiliate revenues— — — 99 (99)— 
 (In millions)1,503 806 3,371 105 (99)5,686 
For the Quarter Ended September 30, 2017            
Oil and Gas Production Revenues $550
 $36
 $543
 $260
 $—
 $1,389
Operating Income (Loss)(3)
 $(114) $(1) $226
 $16
 $(1) $126
Operating Expenses:Operating Expenses:
Lease operating expensesLease operating expenses335 274 283 — (1)891 
Gathering, processing, and transmissionGathering, processing, and transmission8 28 225 24 (98)187 
Purchased oil and gas costsPurchased oil and gas costs— — 1,147 5 — 1,152 
Taxes other than incomeTaxes other than income— — 139 10 — 149 
ExplorationExploration36 27 21 — 2 86 
Depreciation, depletion, and amortizationDepreciation, depletion, and amortization395 208 416 9 — 1,028 
Asset retirement obligation accretionAsset retirement obligation accretion— 59 23 3 — 85 
ImpairmentsImpairments— 18 — — — 18 
774 614 2,254 51 (97)3,596 
Operating Income (Loss)(1)
Operating Income (Loss)(1)
$729 $192 $1,117 $54 $(2)2,090 
Other Income (Expense):            Other Income (Expense):
Derivative instrument gains, netDerivative instrument gains, net45 
Loss on offshore decommissioning contingencyLoss on offshore decommissioning contingency(446)
Gain on divestitures, net           296
Gain on divestitures, net65 
Derivative instrument losses, net           (110)
Other, netOther, net175 
General and administrative           (98)General and administrative(226)
Transaction, reorganization, and separation           (20)Transaction, reorganization, and separation(8)
Financing costs, net           (101)Financing costs, net(393)
Income Before Income Taxes           $93
Income Before Income Taxes$1,302 
            
For the Nine Months Ended September 30, 2017            
Oil and Gas Production Revenues $1,593
 $231
 $1,655
 $768
 $—
 $4,247
Operating Income (Loss)(3)
 $(71) $(33) $740
 $59
 $(24) $671
Other Income (Expense):            
Gain on divestitures, net           616
Derivative instrument losses, net           (69)
Other           43
General and administrative           (307)
Transaction, reorganization, and separation           (14)
Financing costs, net           (300)
Income Before Income Taxes           $640
Total Assets $13,105
 $—
 $4,906
 $3,770
 $54
 $21,835
            
Total Assets(2)
Total Assets(2)
$2,887 $2,080 $7,606 $1,853 $— $14,426 



27

  
United
States
 
Canada(1)
 
Egypt(2)
 North Sea 
Other
International
 Total
  (In millions)
For the Quarter Ended September 30, 2016            
Oil and Gas Production Revenues $524
 $87
 $581
 $247
 $—
 $1,439
Operating Income (Loss)(4)
 $(17) $(466) $263
 $(455) $(13) $(688)
Other Income (Expense):            
Gain on divestitures, net           5
Other           (6)
General and administrative           (102)
Transaction, reorganization, and separation           (12)
Financing costs, net           (102)
Loss From Continuing Operations Before Income Taxes           $(905)
             
For the Nine Months Ended September 30, 2016            
Oil and Gas Production Revenues $1,453
 $243
 $1,515
 $701
 $—
 $3,912
Operating Income (Loss)(4)
 $(283) $(586) $525
 $(557) $(13) $(914)
Other Income (Expense):            
Gain on divestitures, net           21
Other           (30)
General and administrative           (298)
Transaction, reorganization, and separation           (36)
Financing costs, net           (311)
Loss From Continuing Operations Before Income Taxes           $(1,568)
Total Assets $12,299
 $1,630
 $5,320
 $3,851
 $49
 $23,149
(1)During the third quarter of 2017, Apache completed the sale of its Canadian operations. For more information regarding this divestiture, please refer to Note 2—Acquisitions and Divestitures.
(2)Includes a noncontrolling interest in Egypt.
(3)Operating income (loss) consists of oil and gas production revenues less lease operating expenses, gathering and transportation costs, taxes other than income, exploration costs, depreciation, depletion, and amortization, asset retirement obligation accretion, and impairments. The operating income (loss) of U.S. includes leasehold impairments totaling $160 million for the third quarter of 2017. The operating income (loss) of U.S., Canada, and North Sea includes leasehold and other asset impairments totaling $212 million, $2 million, and $8 million, respectively, for the first nine months of 2017.
(4)The operating income (loss) of U.S., Canada, and North Sea includes leasehold, property, and other asset impairments totaling $46 million, $423 million, and $481 million, respectively, for the third quarter of 2016. The operating income (loss) of U.S., Canada, and North Sea includes leasehold, property, and other asset impairments totaling $212 million, $433 million, and $586 million, respectively, for the first nine months of 2016.

EgyptNorth SeaU.S.Altus Midstream
Intersegment
Eliminations
& Other
Total(3)
Upstream
For the Quarter Ended September 30, 2020(In millions)
Revenues:
Oil revenues$303 $179 $303 $— $— $785 
Natural gas revenues74 13 77 — — 164 
Natural gas liquids revenues2 5 90 — — 97 
Oil, natural gas, and natural gas liquids production revenues379 197 470 — — 1,046 
Purchased oil and gas sales— — 73 1 — 74 
Midstream service affiliate revenues— — — 39 (39)— 
379 197 543 40 (39)1,120 
Operating Expenses:
Lease operating expenses102 79 79 — (1)259 
Gathering, processing, and transmission8 10 74 9 (38)63 
Purchased oil and gas costs— — 74 1 — 75 
Taxes other than income— — 30 4 — 34 
Exploration10 10 34 — 4 58 
Depreciation, depletion, and amortization144 90 161 3 — 398 
Asset retirement obligation accretion— 18 8 1 — 27 
264 207 460 18 (35)914 
Operating Income (Loss)(1)
$115 $(10)$83 $22 $(4)206 
Other Income (Expense):
Derivative instrument gains, net16 
Loss on divestitures, net(1)
Other, net9 
General and administrative(52)
Transaction, reorganization, and separation(7)
Financing costs, net(99)
Income Before Income Taxes$72 

28
ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS


EgyptNorth SeaU.S.Altus Midstream
Intersegment
Eliminations
& Other
Total(3)
Upstream
For the Nine Months Ended September 30, 2020(In millions)
Revenues:
Oil revenues$823 $578 $929 $— $— $2,330 
Natural gas revenues209 39 169 — — 417 
Natural gas liquids revenues6 15 211 — — 232 
Oil, natural gas, and natural gas liquids production revenues1,038 632 1,309 — — 2,979 
Purchased oil and gas sales— — 235 2 — 237 
Midstream service affiliate revenues— — — 111 (111)— 
1,038 632 1,544 113 (111)3,216 
Operating Expenses:
Lease operating expenses312 234 313 — (1)858 
Gathering, processing, and transmission31 37 219 29 (110)206 
Purchased oil and gas costs— — 205 2 — 207 
Taxes other than income— — 79 11 — 90 
Exploration51 26 100 — 10 187 
Depreciation, depletion, and amortization463 278 632 9 — 1,382 
Asset retirement obligation accretion— 54 24 3 — 81 
Impairments529 7 3,956 — — 4,492 
1,386 636 5,528 54 (101)7,503 
Operating Income (Loss)(1)
$(348)$(4)$(3,984)$59 $(10)(4,287)
Other Income (Expense):
Derivative instrument losses, net(262)
Gain on divestitures24 
Other, net41 
General and administrative(214)
Transaction, reorganization, and separation(44)
Financing costs, net(168)
Loss Before Income Taxes$(4,910)
Total Assets(2)
$3,052 $2,238 $5,708 $1,741 $136 $12,875 
(1)    Operating income of U.S., Egypt, and North Sea includes leasehold and other asset impairments of $2 million, $2 million, and $19 million, respectively, for the third quarter of 2021.
Operating income of U.S., Egypt, and North Sea includes leasehold and other asset impairments of $19 million, $6 million, and $19 million, respectively, for the first nine months of 2021.
Operating loss of U.S. and Egypt includes leasehold and other asset impairments of $34 million and $2 million, respectively, for the third quarter of 2020.
Operating loss of U.S., Egypt, and North Sea includes leasehold and other asset impairments of $4.0 billion, $535 million, and $7 million, respectively, for the first nine months of 2020.
(2)    Intercompany balances are excluded from total assets.
(3)    Includes noncontrolling interests in Egypt and Altus.
(4)    On March 1, 2021, the Company sold its Suriname and Dominican Republic operations to APA. Refer to Note 2—Transactions with Parent Affiliate for more details on the transaction.

29

ITEM 2.    MANAGEMENT’S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
The following discussion relates to Apache Corporation (Apache or the Company) and its consolidated subsidiaries and should be read in conjunctiontogether with the Company’s consolidated financial statementsConsolidated Financial Statements and accompanying notes included underin Part I, Item 1, “Financial Statements”1—Financial Statements of this Quarterly Report on Form 10-Q, as well as related information set forth in the Company’s consolidated financial statements,Consolidated Financial Statements, accompanying notesNotes to Consolidated Financial Statements, and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.2020.
On January 4, 2021, the Company announced plans to implement a holding company reorganization (the Holding Company Reorganization), which was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization, the Company became a direct, wholly-owned subsidiary of APA Corporation (APA), and all of the Company’s outstanding shares were automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to the Company pursuant to Rule 12g-3(a) under the Exchange Act and replaced the Company as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized the Company’s operating and legal structure making it more consistent with other companies that have affiliates operating around the globe. Refer to Note 2—Transactions with Parent Affiliate for more detail.
Overview
Apache, Corporation, a Delaware corporation formed in 1954,direct, wholly-owned subsidiary of APA, is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids.liquids (NGLs). The CompanyCompany’s upstream business currently has exploration and production operations in three geographic areas: the United States (U.S.)U.S., Egypt, and offshore the United Kingdom (U.K.)U.K. in the North Sea (North Sea). Apache also has exploration interestsThe Company’s midstream business is operated by Altus Midstream Company (Nasdaq: ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owns, develops, and operates a midstream energy asset network in Suriname that may, over time, resultthe Permian Basin of West Texas.
The Company’s mission is to grow in a reportable discoveryan innovative, safe, environmentally responsible, and development opportunity.profitable manner for the long-term benefit of its stakeholders. The Company is focused on rigorous portfolio management, disciplined financial structure, and optimization of returns.
During the quarter, Apache completed its strategic exit from Canada that was enabled by its Alpine High discovery. We believe this portfolio shift is a significant upgrade to the Company’s portfolio of assets, as the Alpine High discovery offers higher returns and significantly more long-term growth potential. Apache’s U.S. assets are complemented by its international assets in EgyptThe global economy and the North Sea, eachenergy industry have been deeply impacted by the effects of which addsthe coronavirus disease 2019 (COVID-19) pandemic and related governmental actions. Uncertainty in the commodity and financial markets during 2020 and 2021 continue to impact oil supply and demand. Despite these uncertainties, the Company’s deep inventory of explorationCompany remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio; (2) to invest for long-term returns over production growth; and development opportunities and(3) to budget conservatively to generate cash flowsflow in excess of currentits capital investments, facilitatingprogram that can be directed on a priority basis to debt reduction. The Company continues to aggressively manage its cost structure regardless of the Company’s abilityoil price environment and closely monitors hydrocarbon pricing fundamentals to develop Alpine High while maintaining financial flexibility.reallocate capital as part of its ongoing planning process.
ApacheIn the third quarter of 2021, the Company reported third-quartera net incomeloss of $63$83 million or $0.16 per common share, compared to a net loss of $607$4 million or $1.60 per common share, in the third quarter of 2016.2020. The increase in net incomeloss compared to the prior-year quarterperiod is primarily the result of gainsa non-cash $446 million loss on divestiturespreviously sold Gulf of Mexico properties, which represents the Company’s estimate of decommissioning Apache may be required to perform or pay for on assets sold to Fieldwood in 2013 in excess of securities available to the Company to recover costs incurred with respect to such decommissioning. For additional details of this loss, please refer to Note 12—Commitments and Contingencies in the current-yearNotes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q. Absent this charge, the quarter as well as lower impairment chargesbenefited from significantly improved commodity prices that had collapsed in the current period. Revenue gains from significant increases in realizedprior year when the COVID-19 pandemic negatively affected economic activity and the oil markets. In response to lower commodity prices, partially mitigated the impact of production declines.
Company materially reduced its upstream capital investment budget and drilling activity during 2020. Daily production decreased 13 percent from an average of 445 Mboe/d in the third quarter of 2017 averaged 448 thousand barrels2020 to an average of oil equivalent per day (Mboe/d), a decrease of 14 percent from the comparative prior-year quarter driven by the sale of the Company’s Canadian operations. Excluding production from Canada, Apache’s worldwide equivalent daily production decreased 8 percent due to natural decline. The production decline was driven by strategic decisions to curtail capital investments389 Mboe/d in the two preceding years in order to allow costs to re-align with the lower commodity price environment and to allocate a significant portionthird quarter of this year’s capital investments to the development2021.
The Company generated $2.4 billion of the Alpine High field and infrastructure.
Duringcash from operating activities during the first nine months of 2017, the Company generated $1.8 billion in cash from operating activities, an 82021, a 172 percent increase from the comparative prior-year period,first nine months of 2020, driven by higher commodity prices and $1.4 billion of cash proceeds from non-core asset divestments. Apache exited the quarter with $1.9 billion of cash, cash equivalents, and restricted cash, an increase of $565 million fromassociated revenues. Since year-end 2016. In addition, the Company reduced its outstanding debt from year-end levelsby $1.1 billion, and has $3.5 billionit had $348 million of available committed borrowing capacity. In response to continued commoditycash at the end of the third quarter of 2021.
Following this progress and considering the ongoing constructive price volatility,environment, the Company entered commodity derivatives to secure deployment of high priority investments without compromisinghas adjusted its financial strength or flexibility. We continuously monitor changes in our operating environment and have the ability, due to our dynamic capitalcash allocation process, to adjust ourapproach. The capital investment program will be increased to levels that maximize value for our shareholdersa level intended to sustain or slightly grow global production volumes. This will be primarily accomplished through a gradual ramp in activity over the long-term.next few quarters, primarily in Egypt, but also in the U.S. Onshore.
Operating
30

Operational Highlights
Significant operating activitiesKey operational highlights for the quarter include the following:include:
North AmericaUnited States
North America equivalent production decreased 17 percent for the quarter relative to the 2016 period, reflecting Apache’s exit from Canada. Excluding Canada, Apache’s North America equivalent production decreased 6 percent, in line with the Company’s expectations given the significant reduction in capital investments over the preceding two years and the allocation of a significant portion of our 2017 capital investments to infrastructure at Alpine High.
Third-quarter equivalent•Equivalent production from the Company’s U.S. assets accounted for 61 percent of its total production during the third quarter of 2021. After halting all drilling and completion activity for most of 2020, in early 2021 the Company re-activated one rig in the Permian Basin region,and one rig in the Austin Chalk. A second rig was added in the Permian Basin in late June 2021. The Company was also active in completing its backlog of Permian wells previously drilled but not completed. During the third quarter, the Company placed nine wells online in the Permian Basin. One additional well was drilled in the Austin Chalk, where the results are continuing to be evaluated, and a drilling rig was recently added to advance the characterization of the Company’s acreage position in the play.
•On October 11, 2021, APA announced that it has ended routine flaring in its U.S. onshore operations, achieving one of its announced 2021 environmental, social and governance (ESG) goals, three months ahead of schedule.
•On October 21, 2021, ALTM announced that it will combine with privately-owned BCP Raptor Holdco LP (BCP) in an all-stock transaction. As consideration for the transaction, ALTM will issue 50 million Class C common shares (and its subsidiary, Altus Midstream LP, will issue corresponding common units) to BCP’s unitholders, which accountsare principally funds affiliated with Blackstone and I Squared Capital. Upon closing of the transaction, APA will own approximately 20 percent of the issued and outstanding common stock of the combined entity. The transaction is expected to close during the first quarter of 2022 following completion of customary closing conditions, including ALTM shareholder approval and regulatory reviews.
International
•In May 2021, the Company reached an agreement in principle with the Egyptian Ministry of Petroleum and the Egyptian General Petroleum Corporation (EGPC) to modernize the terms of the majority of the production-sharing contracts. The changes simplify the contractual relationship with EGPC and include provisions to create a single cost recovery pool, adjust cost oil and gas and profit oil and gas participation, facilitate recovery of prior investment, update day-to-day operational governance, and refresh the term length of both exploration and development leases. The Apache entity that will become the sole contractor is owned two-thirds by Apache and one-third by Sinopec. The final draft of this agreement has been completed and is scheduled to move to the Egyptian Parliament and President in the fall for more than halfapprovals to complete the process.
•In Egypt, the Company averaged 8 drilling rigs and completed 12 wells during the third quarter of Apache’s total North American2021. Third-quarter gross equivalent production increased 1in the Company’s Egypt assets decreased 15 percent from the third quarter of 2016, which was driven by our Alpine High discovery2020, given reduced drilling activity over the preceding year. The Company continues to build and strong performanceenhance its drilling inventory in Egypt, supplemented with recent seismic acquisitions and new play concept evaluations on both new and existing acreage. Upon ratification of the new agreement referenced above, the Company expects to further increase drilling and workover activity.
•The Company averaged two rigs in the Midland Basin. Third-quarter production increased 11 percent from the prior sequential quarter, a reflection of increased activity and the startup of Alpine High production.


Drilling and infrastructure development activities continue at Alpine High; specifically:
◦First production from the Alpine High play was achieved in early May 2017. Net production averaged approximately 13.3 Mboe/dNorth Sea during the third quarter, and we anticipate production of 25 Mboe/d by the end of the year.
◦During the first nine months of 2017, Apache invested $389 million in midstream facilities at Alpine High, with development ongoing.
◦Three processing facilities are currently operating with a combined gross inlet capacity of 200 million cubic feet of natural gas per day (MMcf/d). Infrastructure buildout for two additional central processing facilities has been slightly delayed by a quarter as a result of Hurricane Harvey-related damage to Houston-area manufacturing facilities that are providing key infrastructure equipment.
In 2017, Apache announced three separate transactions to sell its subsidiary Apache Canada Ltd. (ACL) and exit its Canadian operations. The sale of assets at Midale and House Mountain, located in Saskatchewan and Alberta, closed on June 30, 2017 for approximately $228 million of cash proceeds. The two remaining transactions to sell ACL and Provost assets in Alberta closed in August 2017 for approximately $478 million of cash proceeds. The sale of Apache’s Canadian operations further streamlines its portfolio, enabling the Company to allocate a higher percentage of capital to the Permian Basin.
International
The Egypt region net equivalent production decreased 12 percent from the third quarter of 2016 despite a decline of only 3 percent in gross production, a function2021. Production was significantly impacted by compressor downtime, extended platform turnaround work, and third-party pipeline outages during the first nine months of the Company’s production-sharing contracts. In August 2017, the Company received final award of two new concessions totaling 1.6 million net acres. At the end of September 2017, the Company began acquiring high resolution 3D seismic in the West Kalabsha concession and plans to expand this seismic activity to cover the majority of its acreage.year.
The North Sea region average daily production decreased 5 percent from the third quarter of 2016, primarily the result of extended turnaround activities in the third quarter of 2017 and natural well decline. The Callater discovery, which came online in late May 2017, has two wells producing with a third offset well expected to commence production later in the fourth quarter of 2017.



31

Results of Operations
Oil and Gas Production Revenues
Revenue
The table below presentsCompany’s oil and gas production revenues and respective contribution to total revenues by geographic region and each region’s percent contributioncountry were as follows:
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
 2021202020212020
$ Value%
Contribution		$ Value%
Contribution		$
Value		%
Contribution		$
Value		%
Contribution
 ($ in millions)
Oil Revenues:
United States$484 41 %$303 39 %$1,325 40 %$929 40 %
Egypt(1)
465 39 %303 38 %1,299 39 %823 35 %
North Sea233 20 %179 23 %690 21 %578 25 %
Total(1)
$1,182 100 %$785 100 %$3,314 100 %$2,330 100 %
Natural Gas Revenues:
United States$188 64 %$77 47 %$533 64 %$169 41 %
Egypt(1)
63 22 %74 45 %198 24 %209 50 %
North Sea42 14 %13 8 %100 12 %39 9 %
Total(1)
$293 100 %$164 100 %$831 100 %$417 100 %
NGL Revenues:
United States$202 96 %$90 93 %$463 95 %$211 91 %
Egypt(1)
2 1 %2 2 %6 1 %6 3 %
North Sea6 3 %5 5 %16 4 %15 6 %
Total(1)
$210 100 %$97 100 %$485 100 %$232 100 %
Oil and Gas Revenues:
United States$874 52 %$470 45 %$2,321 50 %$1,309 44 %
Egypt(1)
530 31 %379 36 %1,503 33 %1,038 35 %
North Sea281 17 %197 19 %806 17 %632 21 %
Total(1)
$1,685 100 %$1,046 100 %$4,630 100 %$2,979 100 %
(1)    Includes revenues attributable to revenues for 2017 and 2016.a noncontrolling interest in Egypt.

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


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





Production
The Company’s production volumes by country were as follows:
 
For the Quarter Ended
September 30,
For the Nine Months Ended,
September 30,
2021Increase
(Decrease)		20202021Increase
(Decrease)		2020
Oil Volume (b/d)
United States75,526 (9)%83,178 75,384 (19)%93,051 
Egypt(1)(2)
69,830 (12)%79,194 71,052 (8)%77,410 
North Sea33,783 (31)%48,755 36,398 (28)%50,339 
Total179,139 (15)%211,127 182,834 (17)%220,800 
Natural Gas Volume (Mcf/d)
United States546,058 (9)%597,686 531,695 (7)%571,325 
Egypt(1)(2)
243,294 (15)%286,744 259,108 (5)%273,676 
North Sea33,752 (36)%53,137 40,061 (31)%57,659 
Total823,104 (12)%937,567 830,864 (8)%902,660 
NGL Volume (b/d)
United States70,962 (6)%75,266 65,805 (13)%75,468 
Egypt(1)(2)
496 (19)%611 544 (33)%812 
North Sea1,200 (39)%1,976 1,220 (37)%1,948 
Total72,658 (7)%77,853 67,569 (14)%78,228 
BOE per day(3)
United States237,498 (8)%258,058 229,805 (13)%263,740 
Egypt(1)(2)
110,875 (13)%127,595 114,780 (7)%123,834 
North Sea(4)
40,608 (32)%59,588 44,295 (28)%61,897 
Total388,981 (13)%445,241 388,880 (13)%449,471 
(1)    Gross oil, natural gas, and NGL production in Egypt were as follows:
For the Quarter Ended September 30,For the Nine Months Ended September 30,
 2021202020212020
Oil (b/d)134,128 159,941 134,976 171,778 
Natural Gas (Mcf/d)564,354 649,566 581,859 648,995 
NGL (b/d)776 1,175 846 1,534 
(2)    Includes net production volumes per day attributable to a noncontrolling interest in Egypt of:
For the Quarter Ended September 30,For the Nine Months Ended September 30,
 2021202020212020
Oil (b/d)23,309 26,459 23,716 25,891 
Natural Gas (Mcf/d)81,309 95,776 86,564 91,374 
NGL (b/d)165 204 181 271 
(3)    The table below presentsshows production on a boe basis 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 third-quarter and year-to-date 2017 and 2016 production andprice ratio between the relative increase or decreasetwo products.
(4)    Average sales volumes from the prior period.North Sea for the third quarter of 2021 and 2020 were 40,581 boe/d and 57,099 boe/d, respectively, and 45,637 boe/d and 61,771 boe/d for the first nine months of 2021 and 2020, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

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

  For the Quarter Ended September 30, For the Nine Months Ended September 30,
  2017 2016 2017 2016
Oil (b/d) 201,151
 210,755
 196,781
 210,939
Natural Gas (Mcf/d) 818,350
 826,548
 813,880
 828,950
NGL (b/d) 1,526
 1,853
 1,514
 1,918
(2)Includes production volumes per day attributable to a noncontrolling interest in Egypt for the third quarter and nine-month period of 2017 and 2016 of:
  For the Quarter Ended September 30, For the Nine Months Ended September 30,
  2017 2016 2017 2016
Oil (b/d) 31,275
 36,839
 32,573
 34,964
Natural Gas (Mcf/d) 126,459
 135,233
 130,263
 134,591
NGL (b/d) 305
 374
 306
 373
(3)The table shows production on a barrel of oil equivalent basis (boe) in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the price ratio between the two products.

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


Pricing

The Company’s average selling prices by country were as follows:
The table below presents third-quarter and year-to-date 2017 and 2016 pricing and the relative increase or decrease from the prior period.
 
For the Quarter Ended
September 30,
For the Nine Months Ended,
September 30,
2021Increase
(Decrease)		20202021Increase
(Decrease)		2020
Average Oil Price - Per barrel
United States$69.69 76%$39.60 $64.38 77%$36.45 
Egypt72.37 74%41.51 66.97 73%38.79 
North Sea74.94 78%42.10 66.93 59%41.99 
Total71.72 75%40.88 65.90 71%38.53 
Average Natural Gas Price - Per Mcf
United States$3.75 168%$1.40 $3.67 240%$1.08 
Egypt2.82 —%2.82 2.80 —%2.79 
North Sea13.40 419%2.58 9.13 271%2.46 
Total3.87 104%1.90 3.66 117%1.69 
Average NGL Price - Per barrel
United States$30.85 136%$13.06 $25.75 152%$10.20 
Egypt52.02 101%25.88 44.73 70%26.24 
North Sea56.64 109%27.08 48.32 69%28.54 
Total31.42 133%13.51 26.32 143%10.83 
  For the Quarter Ended September 30, For the Nine Months Ended September 30,
  2017 Increase
(Decrease)		 2016 2017 Increase
(Decrease)		 2016
Average Oil Price - Per barrel            
United States $45.68
 9 % $41.83
 $46.54
 24% $37.53
Canada 42.23
 5 % 40.17
 45.25
 26% 36.04
North America 45.56
 9 % 41.65
 46.42
 24% 37.36
Egypt 51.23
 10 % 46.54
 50.78
 21% 41.97
North Sea 53.11
 17 % 45.47
 51.35
 24% 41.28
International 51.87
 12 % 46.20
 50.97
 22% 41.74
Total 49.34
 11 % 44.35
 49.15
 23% 39.86
Average Natural Gas Price - Per Mcf            
United States $2.62
 (2)% $2.66
 $2.58
 29% $2.00
Canada 1.90
 11 % 1.71
 2.17
 48% 1.47
North America 2.47
 7 % 2.31
 2.45
 36% 1.80
Egypt 2.81
 2 % 2.75
 2.77
 3% 2.69
North Sea 5.27
 27 % 4.14
 5.27
 28% 4.12
International 3.10
 5 % 2.96
 3.02
 4% 2.89
Total 2.75
 6 % 2.59
 2.70
 19% 2.26
Average NGL Price - Per barrel            
United States $15.77
 64 % $9.59
 $14.75
 71% $8.65
Canada 15.80
 159 % 6.10
 16.39
 148% 6.61
North America 15.77
 70 % 9.25
 14.87
 76% 8.46
Egypt 36.47
 30 % 28.12
 35.98
 31% 27.54
North Sea 26.92
 10 % 24.45
 30.51
 40% 21.82
International 31.02
 20 % 25.91
 33.07
 37% 24.21
Total 16.38
 64 % 9.97
 15.53
 70% 9.11

Third-Quarter 20172021 compared to Third-Quarter 20162020
Crude Oil Revenues Crude oil revenues for the third quarter of 20172021 totaled $1.1$1.2 billion, a $47$397 million decreaseincrease from the comparative 20162020 quarter. A 1275 percent decreaseincrease in average daily production reducedrealized prices increased third-quarter 20172021 oil revenues by $172$592 million compared to the prior-year quarter, while 1115 percent higherlower average realized prices increaseddaily production decreased revenues by $125$195 million. Crude oil revenues accounted for 7770 percent of Apache’stotal oil and gas production revenues and 5346 percent of its equivalentworldwide production in the third quarter of 2017. Crude2021. The Company’s worldwide oil prices realized inproduction decreased 32.0 Mb/d to 179.1 Mb/d during the third quarter of 2017 averaged $49.34 per barrel, compared with $44.35 per barrel in the comparative prior-year quarter.
Worldwide oil production decreased 32.9 Mb/d to 238.0 Mb/d in the third quarter of 20172021 from the comparative prior-year period, primarily thea result of the Canada divestituresnatural production decline across all countries and natural decline. Decreases were slightly offset by a 2 percent increaseextended operational downtime and platform turnaround work in the North Sea region, a result of the Callater field coming online in late May 2017.Sea.
Natural Gas Revenues Gas revenues for the third quarter of 20172021 totaled $238$293 million, a $25$129 million decreaseincrease from the comparative 20162020 quarter. A 15104 percent decreaseincrease in average daily production reducedrealized prices increased third-quarter 2021 natural gas revenues by $42$170 million compared to the prior-year quarter, while 612 percent higherlower average realized prices increaseddaily production decreased revenues by $17$41 million. Natural gas revenues accounted for 17 percent of Apache’stotal oil and gas production revenues and 35 percent of its equivalentworldwide production during the third quarter of 2017.


Worldwide2021. The Company’s worldwide natural gas production decreased 164114.5 MMcf/d to 940823 MMcf/d induring the third quarter of 20172021 from the comparative prior-year period, primarily thea result of production decline across all countries and extended operational downtime in the Canada divestitures and maintenanceNorth Sea, offset by increased completion activity in the North Sea. Decreases were slightly offset by a 2 percent increase in the U.S., primarily on drilling activity at Alpine High.
NGL Revenues NGL revenues for the third quarter of 20172021 totaled $81$210 million, a $22$113 million increase from the comparative 20162020 quarter. An 18A 133 percent decreaseincrease in average daily production reduced third-quarter 2017 revenues by approximately $17 million, while 64 percent higher average realized prices increased third-quarter 2021 NGL revenues by $39$128 million compared to the prior-year quarter, while 7 percent lower average daily production decreased revenues by $15 million. NGLsNGL revenues accounted for 613 percent of Apache’stotal oil and gas production revenues and 1219 percent of its equivalentworldwide production during the third quarter of 2017.
Worldwide2021. The Company’s worldwide NGL production of NGLs decreased 11.75.2 Mb/d to 53.572.7 Mb/d induring the third quarter of 20172021 from the comparative prior-year period, primarily thea result of the Canada divestitures and naturalproduction decline inacross all regions.countries.
34

Year-to-Date 20172021 compared to Year-to-Date 20162020
Crude Oil Revenues Crude oil revenues for the first nine months of 20172021 totaled $3.3 billion, a $235 million$1.0 billion increase from the comparative 20162020 period. A 1371 percent decreaseincrease in average daily production reduced 2017realized prices increased oil revenues for the 2021 period by $478 million$1.7 billion compared to the prior-year period, while 2317 percent higherlower average realized prices increaseddaily production decreased revenues by $713 million.$671 million compared to the prior-year period. Crude oil revenues accounted for 7872 percent of Apache’stotal oil and gas production revenues and 5347 percent of its equivalentworldwide production for the first nine months of 2017.2021. Crude oil prices realized induring the first nine months of 20172021 averaged $49.15$65.90 per barrel, compared with $39.86to $38.53 per barrel in the comparative prior-year period.
Worldwide The Company’s worldwide oil production decreased 35.638.0 Mb/d to 244.8182.8 Mb/d in the first nine months of 2017 from2021 compared to the comparative prior-year period, primarily thea result of production decline across all countries, and extended operational downtime and platform turnaround work in the Canada divestitures and natural decline in all regions.North Sea.
Natural Gas Revenues Gas revenues for the first nine months of 20172021 totaled $726$831 million, a $31$414 million increase from the comparative 20162020 period. A 12117 percent decreaseincrease in average daily production reduced 2017realized prices increased natural gas revenues for the 2021 period by $104$489 million compared to the prior-year period, while 198 percent higherlower average realized prices increaseddaily production decreased revenues by $135 million.$75 million compared to the prior-year period. Natural gas revenues accounted for 1718 percent of Apache’stotal oil and gas production revenues and 36 percent of its equivalentworldwide production for the first nine months of 2021. Natural gas prices realized during the first nine months of 2017.
Worldwide2021 averaged $3.66 per Mcf, compared to $1.69 per Mcf in the comparative prior-year period. Gas prices for the U.S. during the first nine months of 2021 also reflect the extreme price volatility during the month of February due to the Texas freeze event. The Company’s worldwide natural gas production decreased 13772 MMcf/d to 987831 MMcf/d in the first nine months of 2017 from2021 compared to the comparative prior-year period, primarily thea result of production decline across all countries, impacts of winter storms in the Canada divestitures, maintenance activitiesU.S., and extended operational downtime and platform turnaround work in the North Sea, and natural decline in all regions.Sea.
NGL Revenues NGL revenues for the first nine months of 20172021 totaled $229$485 million, a $69$253 million increase from the comparative 20162020 period. A 17143 percent decreaseincrease in average production reduced 2017realized prices increased NGL revenues for the 2021 period by $45$332 million compared to the prior-year period, while 7014 percent higherlower average realized prices increaseddaily production decreased revenues by $114 million. NGLs$79 million compared to the prior-year period. NGL revenues accounted for 510 percent of Apache’stotal oil and gas production revenues and 1117 percent of its equivalentworldwide production for the first nine months of 2017.
Worldwide2021. NGL prices realized during the first nine months of 2021 averaged $26.32 per barrel, compared to $10.83 per barrel in the comparative prior-year period. The Company’s worldwide NGL production of NGLs decreased 10.610.7 Mb/d to 53.867.6 Mb/d in the first nine months of 2017 from2021 compared to the comparative prior-year period, primarily thea result of production decline across all countries and the Canada divestituresimpacts of winter storms in the U.S.
Altus Midstream Revenues
Altus Midstream services revenues generated through its fee-based contractual arrangements with the Company totaled $35 million and $39 million during the third quarters of 2021 and 2020, respectively, and $99 million and $111 million during the first nine months of 2021 and 2020, respectively. These affiliated revenues are eliminated upon consolidation. Changes in revenue compared to the prior periods were primarily driven by lower natural declinegas throughput volumes processed by Altus for the Company’s Alpine High production.
Purchased Oil and Gas Sales
Purchased oil and gas sales represent volumes primarily attributable to transport, fuel, and physical in-basin gas purchases that were sold by the Company to fulfill natural gas takeaway obligations. Sales related to these purchased volumes totaled $374 million and $74 million during the third quarters of 2021 and 2020, respectively, and $1.1 billion and $237 million during the first nine months of 2021 and 2020, respectively. Purchased oil and gas sales were offset by associated purchase costs of $396 million and $75 million during the third quarters of 2021 and 2020, respectively, and $1.2 billion and $207 million during the first nine months of 2021 and 2020, respectively. When compared to the prior-year periods, gross purchased oil and gas sales values and the associated net losses in all regions.

the third quarter and first nine months of 2021 increased as a result of production shortfalls following reduced capital investment and drilling activity in 2020. The year-to-date net loss was exacerbated by extreme price volatility during the month of February due to Winter Storm Uri in Texas.

35

Operating Expenses
The table below presentsCompany’s operating expenses were as follows:
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
 2021202020212020
 (In millions)
Lease operating expenses$316 $259 $891 $858 
Gathering, processing, and transmission68 63 187 206 
Purchased oil and gas costs396 75 1,152 207 
Taxes other than income54 34 149 90 
Exploration21 58 86 187 
General and administrative64 52 226 214 
Transaction, reorganization, and separation4 7 8 44 
Depreciation, depletion, and amortization:
Oil and gas property and equipment306 366 940 1,284 
Gathering, processing, and transmission assets18 19 56 58 
Other assets11 13 32 40 
Asset retirement obligation accretion29 27 85 81 
Impairments18 — 18 4,492 
Financing costs, net192 99 393 168 
Total Operating Expenses$1,497 $1,072 $4,223 $7,929 
Lease Operating Expenses (LOE)
LOE increased $57 million and $33 million in the third quarter and the first nine months of 2021, respectively, from the comparative prior-year periods. On a comparisonper-unit basis, LOE increased 39 percent and 20 percent in the third quarter and the first nine months of Apache’s expenses on an absolute dollar basis2021, respectively, from the comparative prior-year periods. The increase was driven by higher turnaround 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 includemaintenance costs attributable to a noncontrolling interest in Egypt.
  For the Quarter Ended September 30, For the Nine Months Ended September 30,
  2017 2016 2017 2016 2017 2016 2017 2016
  (In millions) (Per boe) (In millions) (Per boe)
Lease operating expenses(1)
 $358
 $382
 $8.74
 $7.94
 $1,066
 $1,119
 $8.42
 $7.68
Gathering and transportation(1)
 39
 51
 0.91
 1.08
 144
 155
 1.13
 1.06
Taxes other than income 46
 9
 1.12
 0.19
 117
 85
 0.93
 0.58
Exploration 231
 161
 5.60
 3.36
 431
 347
 3.41
 2.38
General and administrative 98
 102
 2.39
 2.13
 307
 298
 2.43
 2.04
Transaction, reorganization, and separation 20
 12
 0.48
 0.25
 14
 36
 0.11
 0.24
Depreciation, depletion, and amortization:                
Oil and gas property and equipment(1)
 524
 610
 12.76
 12.67
 1,598
 1,875
 12.63
 12.87
Other assets 35
 38
 0.83
 0.79
 109
 120
 0.86
 0.82
Asset retirement obligation accretion 30
 40
 0.75
 0.83
 103
 116
 0.82
 0.79
Impairments —
 836
 —
 17.47
 8
 1,009
 0.06
 6.92
Financing costs, net 101
 102
 2.45
 2.13
 300
 311
 2.38
 2.13
(1) For expenses impacted by the timing of 2017 liftings in the North Sea, per-boe calculations are based on sales volumes rather than production volumes.strengthening foreign exchange rates against the U.S. dollar, increased workover activity in the U.S. in the third quarter of 2021, and per-unit operating costs trending with higher oil and gas prices.
Lease Operating Expenses (LOE) LOEGathering, Processing, and Transmission (GPT)
The Company’s GPT expenses were as follows:
For the Quarter Ended
September 30,
For the Nine Months Ended,
September 30,
2021202020212020
(In millions)
Third-party processing and transmission costs$59 $54 $163 $177 
Midstream service affiliate costs35 38 98 110 
Upstream processing and transmission costs94 92 261 287 
Midstream operating expenses9 9 24 29 
Intersegment eliminations(35)(38)(98)(110)
Total Gathering, processing, and transmission$68 $63 $187 $206 
GPT costs increased $5 million and decreased $24$19 million or 6 percent,in the third quarter and the first nine months 2021, respectively, from the comparative prior-year periods. Third-party processing and transmission costs increased $5 million and decreased $14 million in the third quarter and the first nine months of 2021, respectively, from the comparative prior-year periods. The increase in third-party costs for the third quarter of 2017, and decreased $53 million, or 5 percent2021 was primarily driven by an increase in average transportation rates during the quarter. The overall decrease in third-party costs for the first nine months of 2017, on an absolute dollar basis relative to the comparable periods of 2016. On2021 was primarily driven by a per-unit basis, LOE increased 10 percent to $8.74 per boe fordecrease in contracted pricing and lower processed volumes. Midstream service affiliate costs decreased $3 million and $12 million in the third quarter of 2017, and 10 percent to $8.42 per boe for the first nine months of 2017,2021, respectively, from the comparative prior-year periods. The overall decrease in the first nine months of 2021 was primarily driven by lower throughput of rich natural gas volumes at Alpine High. Midstream operating expenses, primarily incurred by Altus Midstream, remained flat in the third quarter of 2021 and decreased $5 million in the first nine months of 2021, compared to the respective prior-year periods, driven by increased operational efficiency and continued cost cutting efforts.
36

Purchased Oil and Gas Costs
Purchased oil and gas costs totaled $396 million and $1.2 billion during the third quarter and the first nine months of 2021, respectively, compared to $75 million and $207 million during the third quarter and the first nine months of 2020, respectively. Purchased oil and gas costs were offset by associated purchase sales of $374 million and $1.1 billion during the third quarter and the first nine months of 2021, respectively, compared to $74 million and $237 million during the third quarter and the first nine months of 2020, respectively, as further discussed above.
Taxes Other Than Income
Taxes other than income increased $20 million and $59 million from the third quarter and the first nine months of 2020, respectively, primarily from higher severance taxes driven by higher commodity prices as compared to the same prior-year periods.
Exploration Expenses
The per-barrel increase for both comparative periods isCompany’s exploration expenses were as follows:
For the Quarter Ended
September 30,
For the Nine Months Ended,
September 30,
2021202020212020
(In millions)
Unproved leasehold impairments$5 $36 $26 $86 
Dry hole expense6 5 31 52 
Geological and geophysical expense4 7 6 14 
Exploration overhead and other6 10 23 35 
Total Exploration$21 $58 $86 $187 
Exploration expenses decreased $37 million and $101 million from the third quarter and the first nine months of 2020, respectively, primarily the result of a declinehigher unproved leasehold impairments during the prior-year periods, due to lower oil and gas prices in productionthe comparative periods. For the first nine months of 2021, the Company also had lower overhead and dry hole expenses resulting from decreased exploration activities compared to the prior year.
General and Administrative (G&A) Expenses
G&A expenses increased $12 million from the third quarter and the first nine months of 2020, primarily driven by higher cash-based stock compensation expense resulting from an increase in all regionsAPA’s stock price, partially offset by lower overhead driven by organizational redesign efforts during 2019 and generally rising2020.
Transaction, Reorganization, and Separation (TRS) Costs
TRS costs commensurate with higher commodity prices.
Gathering and Transportation Gathering and transportation costs totaled $39decreased $3 million and $144$36 million from the third quarter and the first nine months of 2020, respectively, driven by costs associated with the Company’s reorganization efforts incurred primarily in the prior year.
In recent years, the Company has streamlined its portfolio through strategic divestitures and centralized certain operational activities in an effort to capture greater efficiencies and cost savings through shared services. During the second half of 2019, management initiated a comprehensive redesign of the Company’s organizational structure and operations that it believes will better position the Company to be competitive for the long-term and further reduce recurring costs. Reorganization efforts were substantially completed during 2020.
Depreciation, Depletion, and Amortization (DD&A)
DD&A expenses on the Company’s oil and gas properties decreased $60 million and $344 million from the third quarter and the first nine months of 2020, respectively. The Company’s DD&A rate on its oil and gas properties decreased $0.45 per boe and $1.61 per boe from the third quarter and the first nine months of 2020, respectively. The decrease on an absolute basis was driven by lower production volumes and lower asset property balances associated with proved property impairments recorded during the first quarter of 2020. DD&A expense on the Company’s GPT assets remained essentially flat compared to the third quarter and the first nine months of 2020.
37

Impairments
During the third quarter and first nine months of 2017, respectively, a decrease2021, the Company recorded $18 million of $12 million from the third quarter of 2016asset impairments in connection with inventory valuations and a decrease of $11 million from the first nine months of 2016. The decrease was directly related to the Canadian divestitures.
Taxes other than Income Taxes other than income totaled $46 million and $117 million for the third quarter and first nine months of 2017, respectively, an increase of $37 million and $32 million from the third quarter and first nine months of 2016, respectively. Third-quarter 2017 expense consists primarily of severance and ad valorem taxes, which combined increased $4 million on higher commodity prices during the third quarter compared to the prior year quarter. For the first nine months of 2017, severance tax expense and ad valorem tax expense increased $12 million and $5 million, respectively, compared to the first nine months of 2016. In addition,expected equipment dispositions in the third quarter and first nine months of 2016, Apache recognized a $33 million benefit related to the U.K. Petroleum Revenue Tax (PRT). The U.K. PRT rate, historically assessed on qualifying fields in the U.K. North Sea, was reduced to zero during 2016.


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 2017 increased $70 million and $84 million, respectively, compared to the prior-year periods.Sea.
The following table presents a summary of exploration expense:
  For the Quarter Ended September 30, For the Nine Months Ended September 30,
  2017 2016 2017 2016
  (In millions)
Unproved leasehold impairments $160
 $114
 $214
 $222
Dry hole expense 38
 7
 136
 38
Geological and geophysical expense 12
 21
 24
 30
Exploration overhead and other 21
 19
 57
 57
  $231
 $161
 $431
 $347
Unproved leasehold impairmentsCompany recognized $4.5 billion in the third quarter of 2017 increased $46 million compared to the third quarter of 2016, primarily relate to legacy acreage and a reallocation of capital budgets in the U.S. For the first nine months of 2017, unproved leasehold impairments decreased $8 million compared to the prior-year period, primarily a result of stabilizing commodity and leasehold prices. Dry hole expense increased $31 million and $98 million for the third quarter and first nine months of 2017, respectively, from the comparative prior-year periods primarily related to unsuccessful international offshore exploration.
General and Administrative (G&A) Expenses G&A expense for the third quarter of 2017 was $4 million lower than the third quarter of 2016. For the first nine months of 2017, G&A expense increased $9 million compared to the prior-year period, primarily related to non-cash stock-based compensation expense and other corporate costs.
Transaction, Reorganization, and Separation (TRS) Costs The Company recorded TRS expense of $20 million and $14 million for the third quarter and first nine months of 2017, respectively, related to asset divestitures in the U.S. and Canada and employee separation. The Company recorded TRS expense of $12 million and $36 million in the third quarter and first nine months of 2016, respectively, related to various asset divestitures, company reorganization, and employee separation.
Depreciation, Depletion, and Amortization (DD&A) Oil and gas property DD&A expense of $524 million in the third quarter of 2017 decreased $86 million compared to the third quarter of 2016. For the first nine months of 2017, oil and gas property DD&A expense decreased $277 million compared to the prior-year period. The Company’s oil and gas property DD&A rate increased $0.09 per boe and decreased $0.24 per boe in the third quarter and first nine months of 2017, respectively, compared to the comparable prior-year periods. The primary factor driving lower absolute dollar expense was a decrease in production volumes from the comparative prior-year periods.
Impairments The Company did not record any asset impairments in connection with fair value assessments during the first nine months of 2020. During the first half of 2020, the Company recognized impairments totaling $4.3 billion related to proved oil and gas properties in the U.S., Egypt, and the North Sea, $68 million related to GPT facilities in Egypt, $87 million related to goodwill valuations in Egypt, and $18 million related to inventory and other miscellaneous assets, including charges for the early termination of drilling rig leases.
Financing Costs, Net
The Company’s Financing costs were as follows:
 
For the Quarter Ended
September 30,
For the Nine Months Ended,
September 30,
 2021202020212020
 (In millions)
Interest expense$102 $113 $324 $327 
Amortization of debt issuance costs1 2 6 6 
Capitalized interest— (3)— (9)
Loss (gain) on extinguishment of debt105 (12)104 (152)
Interest income(1)(1)(6)(4)
Interest income from APA Corporation, net(15)— (35)— 
Total Financing costs, net$192 $99 $393 $168 
Net financing costs increased $93 million and $225 million from the third quarter and the first nine months of 2020, respectively, primarily driven by a $105 million loss on extinguishment of debt recognized in the third quarter of 2017. During2021, and a $152 million gain on extinguishment of debt during the first quarter of 2017, the Company recorded asset impairments in connection with fair value assessments totaling $8 million for a U.K. PRT decommissioning asset that is no longer expected to be realizable from future abandonment activities in the North Sea. The Company recorded $836 million and $1.0 billion of impairments in connection with fair value assessments in the third quarter and first nine months of 2016, respectively. For more information regarding asset impairments, please refer2020. This increase was partially offset by interest income from APA Corporation as a result of the note receivable from APA related to “Fair Value Measurements” within the Holding Company Reorganization. Refer to Note 1—Summary of Significant Accounting Policies2—Transactions with Parent Affiliate in the Notes to Consolidated Financial Statements in Part 1,I, Item 1 of this Quarterly Report on Form 10-Q.10-Q for further information.



Financing Costs, Net Financing costs incurred during the period comprised the following:
  For the Quarter Ended September 30, For the Nine Months Ended September 30,
  2017 2016 2017 2016
  (In millions)
Interest expense $113
 $116
 $344
 $348
Amortization of deferred loan costs 3
 2
 7
 5
Capitalized interest (12) (13) (39) (36)
Loss on extinguishment of debt —
 —
 1
 —
Interest income (3) (3) (13) (6)
Financing costs, net $101
 $102
 $300
 $311
Net financing costs decreased $1 million and $11 million in the third quarter and first nine months of 2017, respectively. The $11 million decrease in the first nine months of 2017 was primarily the result of higher capitalized interest and interest income.
Provision for Income Taxes
The Company estimates its annual effective income tax rate for continuing operations in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments ofon the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur.
In August 2017, Apache completedDuring the sale of ACL. For more information regarding this transaction, please refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q. As a result of this transaction, Apache recorded a deferred tax asset associated with its realizable capital loss on the sale of ACL, and a decrease in the Company’s deferred tax liability associated with its investment in foreign subsidiaries. In the third and second quarters of 2017, the Company recorded a $2 million deferred income tax expense and a $674 million deferred income tax benefit, respectively, in connection with these transactions.
Apache’s third quarter of 20172021, the Company’s effective income tax rate was primarily impacted by gainsa loss on offshore decommissioning contingency and an increase in the saleamount of oil and gas properties and a $30 million currentvaluation allowance against its U.S. deferred tax benefit associated with U.S. federal income tax credits. On September 15, 2016, U.K. Finance Act 2016 received Royal Assent. Under the enacted legislation, the corporate income tax rate on North Sea oil and gas profits was reduced from 50 percent to 40 percent effective January 1, 2016. As a result of the enacted legislation, inassets. During the third quarter of 20162020, the Company recorded a deferred tax benefit of $235 million related to the remeasurement of the Company’s December 31, 2015 U.K. deferred income tax liability.
Apache’s 2017 year-to-date effective income tax rate iswas primarily impacted by an increase in the decrease inamount of valuation allowance against its U.S. deferred taxes associated with its investments in foreign subsidiaries, gains on the sale of oil and gas properties, non-cash impairments of thetax assets. The Company’s PRT decommissioning asset, and the current tax benefit associated with U.S. federal income tax credits. Apache’s 20162021 year-to-date effective income tax rate was primarily impacted by non-cash impairmentsa loss contingency in connection with decommissioning of previously sold Gulf of Mexico properties and a decrease in the carrying valueamount of thevaluation allowance against its U.S. deferred tax assets. The Company’s 2020 year-to-date effective income tax rate was primarily impacted by oil and gas properties, non-cashasset impairments, of the Company’s PRT decommissioning asset, the impact of the change in U.K. statutory income tax rate,a goodwill impairment, and an increase in the amount of valuation allowances onallowance against its U.S. and Canadian deferred tax assets.
Apache andThe Company recorded a full valuation allowance against its subsidiaries areU.S. net deferred tax assets. The Company 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.
The Company is subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. In April 2017,The Company is currently under audit by the Internal Revenue Service (IRS) began their audit offor the Company’s 2014 income2014-2017 tax year. The Companyyears and is also under audit in various states and in most of the Company’s foreign jurisdictions as part of its normal course of business.



38




Critical Accounting Estimates
Capital ResourcesThe Company prepares its financial statements and Liquidity
Operating cash flowsaccompanying notes in conformity with accounting principles generally accepted in the United States of America, which require management to make estimates and assumptions about future events that affect reported amounts. Estimations are considered critical accounting estimates based on, among other things, its impact on the portrayal of the Company’s primary sourcefinancial condition, results of liquidity. The Company may also elect to use available cash on hand, available committed borrowing capacity, access to both debt and equity capital markets,operations, 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 coststhe degree of difficulty, subjectivity, and sales volumes. Significant changescomplexity in commodity prices impact Apache’s revenues, earnings,its deployment. Critical accounting estimates address accounting matters that are inherently uncertain due to unknown future resolution of such matters. Management routinely discusses the development, selection, and cash flows. These changes potentially impact Apache’s liquidity if costs do not trend with changes in commodity prices. Historically, costs have trended with commodity prices, albeit with a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term.
Apache’s long-term operating cash flows are dependent on reserve replacement and the leveldisclosure of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of Apache’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves. In the first nine months of 2017, Apache recognized positive reserve revisions of approximately 2 percent of its year-end 2016 estimated proved reserves as a result of higher prices.
Apache believes the liquidity and capital resource alternatives available to the Company, combined with proactive measures to adjust its capital budget to reflect volatile commodity prices and anticipated operating cash flows, will be adequate to fund short-term and long-term operations, including Apache’s capital spending program, repayment of debt maturities, payment of dividends, and any amount that may ultimately be paid in connection with commitments and contingencies.
For additional information, please see Part I, Items 1 and 2, “Business and Properties,” and Item 1A, “Risk Factors,” in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.
Sources and Uses of Cash
The following table presents the sources and uses of the Company’s cash, cash equivalents, and restricted cash for the periods presented.
  For the Nine Months Ended September 30,
  2017 2016
  (In millions)
Sources of Cash, Cash Equivalents, and Restricted Cash:    
Net cash provided by operating activities $1,760
 $1,634
Proceeds from sale of oil and gas properties 1,404
 74
Other —
 38
  3,164
 1,746
Uses of Cash and Cash Equivalents:    
Capital expenditures(1)
 $1,855
 $1,314
Leasehold and property acquisitions 142
 169
Payments on fixed-rate debt 70
 1
Dividends paid 285
 284
Distributions to noncontrolling interest 212
 215
Other 35
 —
  2,599
 1,983
Increase (decrease) in cash, cash equivalents, and restricted cash $565
 $(237)

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


Net Cash Provided by Operating Activities Operating cash flows are Apache’s primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile oil and natural gas prices. The factors that determine operating cash flow are largely the same as those that affect net earnings, witheach critical accounting estimates. With the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation (ARO) accretion,the critical accounting estimate listed below, there have been no significant changes to the Company’s estimates and deferred income tax expense, which affect earnings but do not affect cash flows.
Net cash provided by operating activities forassumptions during the first nine months ended September 30, 2021 and 2020.
Offshore Decommissioning Contingency
The Company has potential exposure to future obligations related to divested properties. For information regarding a potential obligation to decommission sold properties estimated and recorded in the third quarter of 2017 totaled $1.8 billion, an increase of $126 million from the first nine months of 2016. The increase primarily reflects higher commodity prices compared to the prior-year period.
For a detailed discussion of commodity prices, production, and expenses,2021, please refer to the “Results of Operations” of this Item 2. For additional detail on the changes in operating assets“Potential Obligation to Decommission Sold Properties” within Note 12—Commitments and liabilities and the non-cash expenses that do not impact net cash provided by operating activities, please see the statement of consolidated cash flows in Item 1, Financial Statements of this Quarterly Report on Form 10-Q.
Asset Divestitures The Company recorded proceeds from asset divestitures totaling $1.4 billion and $74 million in the first nine months of 2017 and 2016, respectively. For more information regarding the Company’s acquisitions and divestitures, please see Note 2—Acquisitions and DivestituresContingencies in the Notes to Consolidated Financial Statements in Part 1,I, Item 1 of this Quarterly Report on Form 10-Q.
Capital Expenditures Worldwide exploration Changes in significant assumptions impacting the Company’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and development (E&D) cash expenditures for the first nine months of 2017 totaled $1.5 billion, compared to $1.3 billion for the first nine months of 2016. Apache operated an average of 36 drilling rigs during the third quarter of 2017.
Apache also completed leasehold and property acquisitions totaling $142 million and $169 million during the first nine months of 2017 and 2016, respectively.
Apache’s investmentplanned abandonment logistics could result in gas gathering, transmission, and processing (GTP) facilities totaled $384 million and $33 million during the first nine months of 2017 and 2016, respectively. Expendituresa liability in 2017 primarily comprise investments in infrastructure for the Alpine High play.
Dividends For the nine-month periods ended September 30, 2017 and 2016, the Company paid $285 million and $284 million, respectively, in dividends on its common stock.


Liquidity
The following table presents a summaryexcess of the Company’s key financial indicators at the dates presented:
  September 30, 2017 December 31, 2016
  (In millions)
Cash and cash equivalents $1,846
 $1,377
Total debt 8,483
 8,544
Equity 8,377
 7,679
Available committed borrowing capacity 3,500
 3,500
Cash and cash equivalents The Company had $1.8 billion in cash and cash equivalents as of September 30, 2017, compared to $1.4 billion at December 31, 2016. At September 30, 2017, approximately $1.3 billion of the cash was held by foreign subsidiaries. The cash held by foreign subsidiaries should not be subject to additional U.S. income taxes if repatriated. The majority of the cash is invested in highly liquid, investment grade securities with maturities of three months or less at the time of purchase. The Company also had $96 million of restricted cash at September 30, 2017, expected to be releasedamount accrued. In addition, significant changes in the fourth quartermarket price of 2017.
Debt As of September 30, 2017, outstanding debt, which consisted of notesoil, gas, and debentures, totaled $8.5 billion. Current debt as of September 30, 2017, included $150 million of 7.0% senior notes due February 1, 2018 and $400 million of 6.9% senior notes due September 15, 2018.
In November 2016, the Company initiated a program to purchase in the open market up to $250 million in aggregate principal amount of senior notes issued under its indentures. In the fourth quarter of 2016, the Company purchased and canceled $181 million aggregate principal amountnatural gas liquids could further impact Apache’s estimate of its senior notes through open market repurchases for $182 million in cash, including accrued interest and $0.5 million of premium.contingent liability to decommission GOM Legacy Assets.

In January 2017, the Company purchased and canceled an additional $69 million aggregate principal amount of senior notes for $71 million in cash, including accrued interest and $1 million of premium, which completed the open market repurchase program. These repurchases resulted in a $1 million net loss on extinguishment of debt, which is included in “Financing costs, net” in the Company’s consolidated statement of operations. The net loss includes an acceleration of related discount and deferred financing costs.

In August 2017, the Company assumed the obligations of Apache Finance Canada Corporation (AFCC) in respect of $300 million 7.75% notes due in 2029 which AFCC issued and the Company guaranteed pursuant to the governing indenture. The assumption was permitted by the indenture and effected pursuant to a supplemental indenture thereto. As a result of the assumption, the Company is the obligor under the notes and indenture, and AFCC is released from its obligations thereunder. The $300 million 7.75% notes historically have been included in the Company’s long-term debt; accordingly, the assumption did not change the Company’s long-term debt or total debt.
Available committed borrowing capacity In June 2015, the Company entered into a five-year revolving credit facility which matures in June 2020, subject to Apache’s two, one-year extension options. The facility provides for aggregate commitments of $3.5 billion (including a $750 million letter of credit subfacility) and rights to increase commitments to $4.5 billion. Proceeds from borrowings may be used for general corporate purposes. Apache’s available borrowing capacity under this facility supports its commercial paper program, currently $3.5 billion. The commercial paper program, which is subject to market availability, facilitates Apache borrowing funds for up to 270 days at competitive interest rates. As of September 30, 2017, the Company had no commercial paper or borrowings under committed bank facilities or uncommitted bank lines outstanding.
In February 2016, the Company entered into a letter of credit facility providing £900 million in commitments and rights to increase commitments to £1.075 billion. This facility matures in February 2020 and is available for the Company’s letter of credit needs, particularly those which may arise in respect of abandonment obligations assumed in various North Sea acquisitions. The facility also is available for loans to cash collateralize letters of credit or obligations to provide letters of credit, in each case, to the extent letters of credit are unavailable under the facility. As of September 30, 2017, three letters of credit aggregating approximately £147.5 million and no borrowings were outstanding under this facility.
The Company was in compliance with the terms of these credit facilities as of September 30, 2017.



ITEM 3 –3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity RiskOmitted.
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 11 percent to $49.34 per barrel in the third quarter of 2017 from $44.35 per barrel in the comparable period of 2016. The Company’s average natural gas price realizations have increased 6 percent to $2.75 per Mcf in the third quarter of 2017 from $2.59 per Mcf in the comparable period of 2016. Based on average daily production for the third quarter of 2017, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the quarter by approximately $22 million, and a $0.10 per Mcf change in the weighted average realized price of natural gas would have increased or decreased revenues for the quarter by approximately $9 million.
Apache periodically enters into derivative positions on a portion of its projected oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Apache does not hold or issue derivative instruments for trading purposes. As of September 30, 2017, the Company had open natural gas derivatives not designated as cash flow hedges in an asset position with a fair value of $6 million. A 10 percent increase in gas prices would move the derivatives to a liability position of $17 million, while a 10 percent decrease in prices would increase the asset by approximately $17 million. As of September 30, 2017, the Company had open oil derivatives not designated as cash flow hedges in an asset position with a fair value of $11 million. A 10 percent increase in oil prices would move the derivatives to a liability position of $50 million, while a 10 percent decrease in prices would increase the asset by approximately $84 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2017. See Note 3—Derivative Instruments and Hedging Activities of the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q for notional volumes and terms associated with the Company’s derivative contracts.
Foreign Currency Risk
The Company’s cash flow stream relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. The Company’s North Sea production is sold under U.S. dollar contracts, and the majority of costs incurred are paid in British pounds. In Egypt, all oil and gas production is sold under U.S. dollar contracts, and the majority of the costs incurred are denominated in U.S. dollars. Revenue and disbursement transactions denominated in British pounds are converted to U.S. dollar equivalents based on average exchange rates during the period.
Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Currency gains and losses are included as either a component of “Other” under “Revenues and Other” or, as is the case when the Company re-measures its foreign tax liabilities, as a component of the Company’s provision for income tax expense on the statement of consolidated operations. A foreign currency net gain or loss of $6 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of September 30, 2017.


ITEM 4 –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 ourthe Company’s disclosure controls and procedures as of September 30, 2017,2021, 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 the information we arethe Company is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the SEC’sCommission’s rules and forms and accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
WeThe Company periodically reviewreviews the design and effectiveness of ourits disclosure controls, including compliance with various laws and regulations that apply to ourits operations, both inside and outside the United States. We makeThe Company makes modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if ourthe Company’s reviews identify deficiencies or weaknesses in ourits controls.
Changes in Internal Control Over Financial Reporting
There were no changes in ourthe Company’s internal controlcontrols over financial reporting that occurred during the quarter ended September 30, 20172021 that have materially affected, or are reasonably likely to materially affect, ourthe Company’s internal controlcontrols over financial reporting.

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PART II - OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS
ITEM 1.LEGAL PROCEEDINGS
Please referRefer to Part I, Item 33—Legal Proceedings of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016 (filed with the SEC on February 24, 2017)2020 and Note 9—12—Commitments and Contingencies in the notesNotes to the consolidated financial statementsConsolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q (which is hereby incorporated by reference herein), for a description of material legal proceedings.

ITEM 1A.    RISK FACTORS
ITEM 1A.RISK FACTORS
Please referRefer to Part I, Item 1A—Risk Factors of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016,2020 and Part I,II, Item 3—Quantitative and Qualitative Disclosures About Market 1A—Risk Factors of thisthe Company’s Quarterly Report on Form 10-Q. There have been no material changes10-Q for the quarterly period ended March 31, 2021.
Given the nature of their respective businesses, APA Corporation and Altus Midstream Company may be subject to our risk factors since our annual reportdifferent or additional risks than those applicable to the Company. For a description of these risks, refer to the applicable disclosures in APA Corporation’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2021, June 30, 2021, and September 30, 2021 and Altus Midstream Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Apache’s Board of Directors has authorized2020 and Quarterly Reports on Form 10-Q for 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 onquarterly periods ended March 31, 2021, June 10, 2013,30, 2021, and through September 30, 2017, had repurchased a total of 32.2 million shares at an average price of $88.96 per share. The Company is not obligated to acquire any specific number of shares and has not purchased any additional shares during 2017.2021.

ITEM 3.DEFAULTS UPON SENIOR SECURITIES
None

ITEM 4.MINE SAFETY DISCLOSURES
None

ITEM 5.OTHER INFORMATION
None



ITEM 6.EXHIBITS
40
3.1–
Restated Certificate of Incorporation of Registrant, dated September 19, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed September 20, 2013, SEC File No. 001-4300).
3.2–
Certificate of Amendment of Restated Certificate of Incorporation of Registrant, dated May 14, 2015, as filed with the Secretary of State of Delaware on May 14, 2015 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed May 20, 2015, SEC File No. 001-4300).
3.3–
Bylaws of Registrant, as amended May 11, 2017 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed May 16, 2017, SEC File No. 001-4300).
*4.1–
Supplemental Indenture, dated as of August 14, 2017, among Apache Finance Canada Corporation, Apache Corporation, and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A., formerly The Chase Manhattan Bank), as trustee.
*31.1–
Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2–
Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
*32.1–
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
*101.INS–XBRL Instance Document.
*101.SCH–XBRL Taxonomy Schema Document.
*101.CAL–XBRL Calculation Linkbase Document.
*101.DEF–XBRL Definition Linkbase Document.
*101.LAB–XBRL Label Linkbase Document.
*101.PRE–XBRL Presentation Linkbase Document.

ITEM 6.    EXHIBITS
2.1–
Agreement and Plan of Merger, dated as of March 1, 2021, by and among Registrant, APA Corporation, and APA Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed March 1, 2021, SEC File No. 001-4300).
3.1–
Amended and Restated Certificate of Incorporation of Registrant, dated March 1, 2021, as attached as Annex A to the Certificate of Merger of APA Merger Sub, Inc. with and into Registrant, filed with the Secretary of State of the State of Delaware on March 1, 2021 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed March 1, 2021, SEC File No. 001-4300).
3.2–
Certificate of Amendment of Amended and Restated Certificate of Incorporation of Registrant, dated June 7, 2021, filed with the Secretary of State of the State of Delaware on June 10, 2021 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed June 14, 2021, SEC File No. 001-4300).
3.3–
Amended and Restated Bylaws of Registrant, dated March 1, 2021 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed March 1, 2021, SEC File No. 001-4300).
*31.1–
Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2–
Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
*32.1–
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
*101–The following financial statements from the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2021, formatted in Inline XBRL: (i) Statement of Consolidated Operations, (ii) Statement of Consolidated Comprehensive Income (Loss), (iii) Statement of Consolidated Cash Flows, (iv) Consolidated Balance Sheet, (v) Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interest and (vi) Notes to Consolidated Financial Statements, tagged as blocks of text and including detailed tags.
*101.SCH–Inline XBRL Taxonomy Schema Document.
*101.CAL–Inline XBRL Calculation Linkbase Document.
*101.DEF–Inline XBRL Definition Linkbase Document.
*101.LAB–Inline XBRL Label Linkbase Document.
*101.PRE–Inline XBRL Presentation Linkbase Document.
*104–Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
*    Filed herewith
41
*Filed herewith



SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
APACHE CORPORATION
Dated:November 2, 20174, 2021/s/ STEPHEN J. RINEY
Stephen J. Riney
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
Dated:November 2, 20174, 2021/s/ REBECCA A. HOYT
Rebecca A. Hoyt
Senior Vice President, Chief Accounting Officer, and Controller
(Principal Accounting Officer)



40
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