Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C.D.C. 20549
FORM 10-Q
(Mark One)
[ X ]  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 20172018
or
[    ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from        to        
Commission File No. 1-8968
ANADARKO PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 76-0146568
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code (832) 636-1000
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  þ    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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  þ    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer  þ    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨Emerging growth company  ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  þ
The number of shares outstanding of the Company’s common stock at October 20, 2017,18, 2018, is shown below:
Title of Class Number of Shares Outstanding
Common Stock, par value $0.10 per share 547,157,557504,280,902

TABLE OF CONTENTS
PART I
 Page
Item 1.
Financial Statements
 
 
Consolidated Statements of Income for the Three and Nine Months Ended September 30, 20172018 and 20162017
34
 
Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 20172018 and 20162017
45
 
Consolidated Balance Sheets at September 30, 2017,2018, and December 31, 20162017
56
 
Consolidated Statement of Equity for the Nine Months Ended September 30, 20172018
67
 
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 20172018 and 20162017
78
 
Notes to Consolidated Financial Statements
89
 
Note 1 - 1—Summary of Significant Accounting Policies
89
 
Note 2 - Inventories
10
Note 3 - Acquisitions, Divestitures, and Assets Held for Sale
11
Note 4 - Impairments2—Revenue from Contracts with Customers
12
 
Note 5 - Exploratory Well Costs3—Commodity Inventories
1316
 
Note 6 - Current Liabilities4—Divestitures
1416
 
Note 7 - Derivative Instruments5—Impairments
1417
 
Note 8 - Debt6—Suspended Exploratory Well Costs
2017
 
Note 9 - Income Taxes7—Current Liabilities
2218
 
Note 10 - Contingencies8—Derivative Instruments
2318
 
Note 11 - Restructuring Charges
23
Note 12 - Pension Plans and Other Postretirement Benefits9—Tangible Equity Units
24
 
Note 13 - Stockholders’ Equity10—Debt
2524
 
Note 14 - Noncontrolling Interests
26
Note 15 - Variable Interest Entities11—Income Taxes
27
 
Note 16 - Supplemental Cash Flow Information12—Contingencies
28
 
Note 17 - 13—Pension Plans and Other Postretirement Benefits
29
Note 14—Stockholders’ Equity
30
Note 15—Noncontrolling Interests
32
Note 16—Variable Interest Entities
33
Note 17—Supplemental Cash Flow Information
35
Note 18—Segment Information
2836
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
3239
 
Cautionary Statement About Forward-Looking Statements
3239
 
Management Overview
3441
 
Financial Results
3543
 
Liquidity and Capital Resources
4654
 
Recent Accounting Developments
4957
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
5058
Item 4.
Controls and Procedures
5159
PART II
  
Item 1.
Legal Proceedings
5260
Item 1A.
Risk Factors
5261
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
5362
Item 6.
Exhibits
5463

COMMONLY USED TERMS AND DEFINITIONS
Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. In addition, the following company or industry-specific terms and abbreviations are used throughout this report:

364-Day Facility - Anadarko’s $2.0 billion 364-day senior unsecured RCF maturing in January 2018
APC RCF - Anadarko’s $3.0 billion senior unsecured RCF maturing in January 2021
ASR Agreement - Anadarko’sAn accelerated share-repurchase agreement with an investment bank to repurchase the Company’s common stock
ASU - Accounting Standards Update
Bcf - Billion cubic feet
BOE - Barrels of oil equivalent
CBM - Coalbed methane
DBJV - Delaware Basin JV Gathering LLC
DBJV systemSystem - A gathering system and related facilities located in the Delaware basin in Loving, Ward, Winkler, and Reeves Counties in West Texas
DBM complexComplex - The processing plants, gas gathering system, and related facilities and equipment in West Texas that serve production from Reeves, Loving, and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico
DD&A - Depreciation, depletion, and amortization
EPADJ Basin Complex - The Platte Valley system, Wattenberg system, and Lancaster plant, which were combined into a single complex in Colorado in the first quarter of 2014 to serve production in the DJ basin
FID - U.S. Environmental Protection AgencyFinal investment decision
Fitch - Fitch Ratings
FPSO - Floating production, storage, and offloading unit
G&A - General and administrative expenses
GAAPIRS - U.S. Generally Accepted Accounting Principles
GOM Acquisition - The acquisition of oil and natural-gas assets in the Gulf of Mexico that closed on December 15, 2016Internal Revenue Service
IPO - Initial public offering
LIBOR - London Interbank Offered Rate
LNG - Liquefied natural gas
MBbls/d - Thousand barrels per day
MBOE/d - Thousand barrels of oil equivalent per day
Mcf - Thousand cubic feet
MMBbls - Million barrels
MMBOE - Million barrels of oil equivalent
MMBtu - Million British thermal units
MMBtu/d - Million British thermal units per day
MMcf/d - Million cubic feet per day
Moody’s - Moody’s Investors Service
N/A - Not applicable
NGLs - Natural gas liquids
NM - Not meaningful
NTSB - National Transportation Safety Board
NYMEX - New York Mercantile Exchange
NYSE - New York Stock Exchange
Oil - Includes crude oil and condensate
OPEC - Organization of the Petroleum Exporting Countries
RCF - Revolving credit facility
ROTF - Regional oil treating facility

S&P - Standard and Poor’s
Share-Repurchase Program - A program authorizing the repurchase of Anadarko’s common stock
Tax Reform Legislation - The U.S. Tax Cuts and Jobs Act signed into law on December 22, 2017
TEN - Tweneboa/Enyenra/Ntomme
TEU or TEUs - Tangible equity units
VIE or VIEs - Variable interest entity
WES - Western Gas Partners, LP, a publicly traded limited partnership, which is a consolidated subsidiary of Anadarko
WES RCF - WES’s $1.2$1.5 billion senior unsecured RCF maturing in February 2020
WGP - Western Gas Equity Partners, LP, a publicly traded limited partnership, which is a consolidated subsidiary of Anadarko
WGP RCF - WGP’s $250$35 million three-year senior secured RCF maturing in March 2019
WTI - West Texas Intermediate
Zero Coupons - Anadarko’s Zero-Coupon Senior Notes due 2036

PART I. FINANCIAL INFORMATION
Item 1.  Financial Statements
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
  Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
millions except per-share amounts 2017 2016 2017 2016
Revenues and Other        
Oil sales $1,567
 $1,239
 $4,652
 $3,214
Natural-gas sales 269
 435
 1,090
 1,121
Natural-gas liquids sales 265
 227
 768
 640
Gathering, processing, and marketing sales 509
 350
 1,417
 895
Gains (losses) on divestitures and other, net (114) (358) 1,052
 (388)
Total 2,496
 1,893
 8,979
 5,482
Costs and Expenses        
Oil and gas operating 257
 198
 748
 608
Oil and gas transportation 220
 256
 698
 744
Exploration 751
 304
 2,371
 506
Gathering, processing, and marketing 398
 291
 1,108
 758
General and administrative 280
 362
 840
 1,116
Depreciation, depletion, and amortization 1,083
 1,069
 3,235
 3,202
Production, property, and other taxes 159
 148
 449
 422
Impairments —
 27
 383
 61
Other operating expense 123
 31
 157
 54
Total 3,271
 2,686
 9,989
 7,471
Operating Income (Loss) (775) (793) (1,010) (1,989)
Other (Income) Expense        
Interest expense 230
 220
 680
 657
Loss on early extinguishment of debt —
 —
 2
 124
(Gains) losses on derivatives, net 82
 25
 (33) 629
Other (income) expense, net (21) (31) (43) (86)
Total 291
 214
 606
 1,324
Income (Loss) Before Income Taxes (1,066) (1,007) (1,616) (3,313)
Income tax expense (benefit) (425) (260) (366) (957)
Net Income (Loss) (641) (747) (1,250) (2,356)
Net income (loss) attributable to noncontrolling interests 58
 83
 182
 200
Net Income (Loss) Attributable to Common Stockholders $(699) $(830) $(1,432) $(2,556)
         
Per Common Share        
Net income (loss) attributable to common stockholders—basic $(1.27) $(1.61) $(2.60) $(5.00)
Net income (loss) attributable to common stockholders—diluted $(1.27) $(1.61) $(2.61) $(5.00)
Average Number of Common Shares Outstanding—Basic 553
 517
 552
 512
Average Number of Common Shares Outstanding—Diluted 553
 517
 552
 512
Dividends (per common share) $0.05
 $0.05
 $0.15
 $0.15

See accompanying Notes to Consolidated Financial Statements.

3

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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
  Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
millions 2017 2016 2017 2016
Net Income (Loss) $(641) $(747) $(1,250) $(2,356)
Other Comprehensive Income (Loss)        
Adjustments for derivative instruments        
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net 1
 2
 3
 7
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net —
 (1) (1) (3)
Total adjustments for derivative instruments, net of taxes 1
 1
 2
 4
Adjustments for pension and other postretirement plans        
Net gain (loss) incurred during period (14) (157) 1
 (347)
Income taxes on net gain (loss) incurred during period 5
 58
 —
 128
Prior service credit (cost) incurred during period —
 —
 —
 (1)
Income taxes on prior service credit (cost) incurred during period —
 —
 —
 1
Amortization of net actuarial (gain) loss to general and administrative expense 29
 114
 100
 156
Income taxes on amortization of net actuarial (gain) loss to general and administrative expense (11) (43) (37) (59)
Amortization of net prior service (credit) cost to general and administrative expense (7) (6) (19) (27)
Income taxes on amortization of net prior service (credit) cost to general and administrative expense 3
 2
 7
 10
Total adjustments for pension and other postretirement plans, net of taxes 5
 (32) 52
 (139)
Total 6
 (31) 54
 (135)
Comprehensive Income (Loss) (635) (778) (1,196) (2,491)
Comprehensive income (loss) attributable to noncontrolling interests 58
 83
 182
 200
Comprehensive Income (Loss) Attributable to Common Stockholders $(693) $(861) $(1,378) $(2,691)

  Three Months Ended Nine Months Ended
  September 30, September 30,
millions except per-share amounts 2018 2017 2018 2017
Revenues and Other        
Oil sales $2,572
 $1,567
 $6,964
 $4,652
Natural-gas sales 232
 269
 682
 1,090
Natural-gas liquids sales 382
 265
 992
 768
Gathering, processing, and marketing sales 421
 509
 1,163
 1,417
Gains (losses) on divestitures and other, net 90
 (114) 232
 1,052
Total 3,697
 2,496
 10,033
 8,979
Costs and Expenses        
Oil and gas operating 294
 253
 845
 738
Oil and gas transportation 228
 220
 633
 698
Exploration 118
 750
 380
 2,366
Gathering, processing, and marketing 256
 396
 745
 1,101
General and administrative 248
 261
 814
 768
Depreciation, depletion, and amortization 1,130
 1,083
 3,123
 3,235
Production, property, and other taxes 246
 159
 637
 449
Impairments 172
 —
 319
 383
Other operating expense 26
 123
 188
 157
Total 2,718
 3,245
 7,684
 9,895
Operating Income (Loss) 979
 (749) 2,349
 (916)
Other (Income) Expense        
Interest expense 240
 230
 705
 682
(Gains) losses on derivatives, net 32
 82
 503
 (33)
Other (income) expense, net 24
 5
 16
 51
Total 296
 317
 1,224
 700
Income (Loss) Before Income Taxes 683
 (1,066) 1,125
 (1,616)
Income tax expense (benefit) 256
 (425) 507
 (366)
Net Income (Loss) 427
 (641) 618
 (1,250)
Net income (loss) attributable to noncontrolling interests 64
 58
 105
 182
Net Income (Loss) Attributable to Common Stockholders $363
 $(699) $513
 $(1,432)
         
Per Common Share        
Net income (loss) attributable to common stockholders—basic $0.72
 $(1.27) $0.99
 $(2.60)
Net income (loss) attributable to common stockholders—diluted $0.72
 $(1.27) $0.99
 $(2.61)
Average Number of Common Shares Outstanding—Basic 499
 553
 507
 552
Average Number of Common Shares Outstanding—Diluted 500
 553
 508
 552
Dividends (per common share) $0.25
 $0.05
 $0.75
 $0.15

See accompanying Notes to Consolidated Financial Statements.

4

Table of Contents

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
  Three Months Ended Nine Months Ended
  September 30, September 30,
millions 2018 2017 2018 2017
Net Income (Loss) $427
 $(641) $618
 $(1,250)
Other Comprehensive Income (Loss)        
Adjustments for derivative instruments        
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net 1
 1
 2
 3
Income taxes on reclassification of previously deferred derivative losses —
 —
 —
 (1)
Total adjustments for derivative instruments, net of taxes 1
 1
 2
 2
Adjustments for pension and other postretirement plans        
Net gain (loss) incurred during period 25
 (14) 25
 1
Income taxes on net gain (loss) incurred during period (6) 5
 (6) —
Amortization of net actuarial (gain) loss to other (income) expense, net 15
 29
 28
 100
Income taxes on amortization of net actuarial (gain) loss (4) (11) (7) (37)
Amortization of net prior service (credit) cost to other (income) expense, net (6) (7) (18) (19)
Income taxes on amortization of net prior service (credit) cost 2
 3
 4
 7
Total adjustments for pension and other postretirement plans, net of taxes 26
 5
 26
 52
Total 27
 6
 28
 54
Comprehensive Income (Loss) 454
 (635) 646
 (1,196)
Comprehensive income (loss) attributable to noncontrolling interests 64
 58
 105
 182
Comprehensive Income (Loss) Attributable to Common Stockholders $390
 $(693) $541
 $(1,378)


See accompanying Notes to Consolidated Financial Statements.

5

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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)
millions September 30, 
 2017		 December 31, 
 2016
 September 30, December 31,
millions except per-share amounts
2018 2017
ASSETS        
Current Assets        
Cash and cash equivalents ($153 and $359 related to VIEs) $5,251
 $3,184
Accounts receivable (net of allowance of $16 and $14)    
Customers ($104 and $70 related to VIEs) 1,009
 1,007
Others ($12 and $80 related to VIEs) 873
 721
Cash and cash equivalents ($133 and $80 related to VIEs) $1,883
 $4,553
Accounts receivable (net of allowance of $11 and $14)    
Customers ($159 and $106 related to VIEs) 1,644
 1,222
Others ($15 and $19 related to VIEs) 547
 607
Other current assets 340
 354
 397
 380
Total 7,473
 5,266
 4,471
 6,762
Properties and Equipment    
Cost 64,855
 69,013
Less accumulated depreciation, depletion, and amortization 37,023
 36,845
Net properties and equipment ($5,508 and $5,050 related to VIEs) 27,832
 32,168
Other Assets ($589 and $609 related to VIEs)
 2,152
 2,226
Goodwill and Other Intangible Assets ($1,200 and $1,221 related to VIEs)
 5,671
 5,904
Net Properties and Equipment (net of accumulated depreciation, depletion, and amortization of $36,375 and $34,107) ($6,419 and $5,731 related to VIEs)
 28,744
 27,451
Other Assets ($801 and $579 related to VIEs)
 2,292
 2,211
Goodwill and Other Intangible Assets ($1,170 and $1,191 related to VIEs)
 5,638
 5,662
Total Assets $43,128
 $45,564
 $41,145
 $42,086
        
LIABILITIES AND EQUITY        
Current Liabilities        
Accounts payable        
Trade ($280 and $234 related to VIEs) $1,770
 $1,617
Other 225
 303
Trade ($337 and $305 related to VIEs) $2,144
 $1,894
Other ($16 and $1 related to VIEs) 201
 266
Short-term debt - Anadarko (1)
 149
 42
 910
 142
Short-term debt - WGP/WES 28
 —
Current asset retirement obligations 336
 129
 332
 294
Other current liabilities 1,203
 1,237
 1,502
 1,310
Total 3,683
 3,328
 5,117
 3,906
Long-term Debt        
Long-term debt - Anadarko (1)
 12,052
 12,162
 11,189
 12,054
Long-term debt - WES and WGP 3,372
 3,119
Long-term debt - WGP/WES 4,566
 3,493
Total 15,424
 15,281
 15,755
 15,547
Other Long-term Liabilities        
Deferred income taxes 3,378
 4,324
 2,455
 2,234
Asset retirement obligations ($144 and $140 related to VIEs) 2,747
 2,802
Asset retirement obligations ($158 and $143 related to VIEs) 2,538
 2,500
Other 3,974
 4,332
 4,043
 4,109
Total 10,099
 11,458
 9,036
 8,843
        
Equity        
Stockholders’ equity        
Common stock, par value $0.10 per share
(1.0 billion shares authorized, 574.0 million and 572.0 million shares issued)		 57
 57
Common stock, par value $0.10 per share (1.0 billion shares authorized, 576.2 million and 574.2 million shares issued) 57
 57
Paid-in capital 11,972
 11,875
 12,344
 12,000
Retained earnings 160
 1,704
 1,291
 1,109
Treasury stock (21.4 million and 20.8 million shares) (1,070) (1,033)
Treasury stock (82.3 million and 43.4 million shares) (4,608) (2,132)
Accumulated other comprehensive income (loss) (337) (391) (383) (338)
Total Stockholders’ Equity 10,782
 12,212
 8,701
 10,696
Noncontrolling interests 3,140
 3,285
 2,536
 3,094
Total Equity 13,922
 15,497
 11,237
 13,790
Total Liabilities and Equity $43,128
 $45,564
 $41,145
 $42,086

Parenthetical references reflect amounts as of September 30, 2017,2018, and December 31, 2016.2017.
VIE amounts relate to WGP and WES. See Note 15—16—Variable Interest Entities.
(1) 
Excludes WES and WGP.

See accompanying Notes to Consolidated Financial Statements.

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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF EQUITY
(Unaudited)
 Total Stockholders’ Equity     Total Stockholders’ Equity    
millions 
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Treasury
Stock
 
Accumulated Other
Comprehensive
Income (Loss)
 
Non-
controlling
Interests
 
Total
Equity
 
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Treasury
Stock
 
Accumulated Other
Comprehensive
Income (Loss)
 
Non-
controlling
Interests
 
Total
Equity
Balance at December 31, 2016 $57
 $11,875
 $1,704
 $(1,033) $(391) $3,285
 $15,497
Balance at December 31, 2017 $57
 $12,000
 $1,109
 $(2,132) $(338) $3,094
 $13,790
Net income (loss) —
 —
 (1,432) —
 —
 182
 (1,250) —
 —
 513
 —
 —
 105
 618
Common stock issued (1)
 —
 123
 —
 —
 —
 —
 123
 —
 6
 —
 —
 —
 —
 6
Share-based compensation expense —
 125
 —
 —
 —
 —
 125
Dividends—common stock —
 —
 (84) —
 —
 —
 (84) —
 —
 (380) —
 —
 —
 (380)
Repurchase of common stock —
 —
 —
 (37) —
 —
 (37)
Repurchases of common stock —
 —
 —
 (2,476) —
 —
 (2,476)
Subsidiary equity transactions —
 (23) —
 —
 —
 —
 (23) —
 (17) —
 —
 —
 25
 8
Settlement of tangible equity units —
 230
 —
 —
 —
 (300) (70)
Distributions to noncontrolling interest owners —
 —
 —
 —
 —
 (327) (327) —
 —
 —
 —
 —
 (365) (365)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net —
 —
 —
 —
 2
 —
 2
 —
 —
 —
 —
 2
 —
 2
Adjustments for pension and other postretirement plans —
 —
 —
 —
 52
 —
 52
 —
 —
 —
 —
 26
 —
 26
Cumulative effect of accounting change —
 (3) (28) —
 —
 —
 (31)
Balance at September 30, 2017 $57
 $11,972
 $160
 $(1,070) $(337) $3,140
 $13,922
Cumulative effect of accounting change (1)
 —
 —
 49
 —
 (73) (23) (47)
Balance at September 30, 2018 $57
 $12,344
 $1,291
 $(4,608) $(383) $2,536
 $11,237

 __________________________________________________________________
(1) 
Represents share-based compensation expense.
Beginning January 1, 2018, the Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements for further information.



See accompanying Notes to Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 Nine Months Ended
 Nine Months Ended 
 September 30,		 September 30,
millions 2017 2016 2018 2017
Cash Flows from Operating Activities        
Net income (loss) $(1,250) $(2,356) $618
 $(1,250)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities        
Depreciation, depletion, and amortization 3,235
 3,202
 3,123
 3,235
Deferred income taxes (1,026) (1,121) 141
 (1,026)
Dry hole expense and impairments of unproved properties 2,144
 300
 212
 2,144
Impairments 383
 61
 319
 383
(Gains) losses on divestitures, net (815) 516
 (31) (815)
Loss on early extinguishment of debt 2
 124
Total (gains) losses on derivatives, net (33) 634
 506
 (33)
Operating portion of net cash received (paid) in settlement of derivative instruments 21
 229
 (433) 21
Other 225
 256
 224
 227
Changes in assets and liabilities        
(Increase) decrease in accounts receivable (32) 810
 (344) (32)
Increase (decrease) in accounts payable and other current liabilities (95) (637) 230
 (95)
Other items, net (140) (141) (263) (140)
Net cash provided by (used in) operating activities 2,619
 1,877
 4,302
 2,619
Cash Flows from Investing Activities        
Additions to properties and equipment (3,538) (2,618) (4,891) (3,538)
Divestitures of properties and equipment and other assets 3,480
 1,281
 393
 3,480
Other, net 32
 81
 (161) 30
Net cash provided by (used in) investing activities (26) (1,256) (4,659) (28)
Cash Flows from Financing Activities        
Borrowings, net of issuance costs 249
 5,840
 2,131
 249
Repayments of debt (42) (6,023) (1,176) (42)
Financing portion of net cash received (paid) for derivative instruments (160) (639) 19
 (160)
Increase (decrease) in outstanding checks (58) (126) (13) (58)
Dividends paid (84) (78) (380) (84)
Repurchase of common stock (37) (32)
Issuance of common stock —
 2,188
Sale of subsidiary units —
 1,163
Repurchases of common stock (2,476) (37)
Issuances of common stock 6
 —
Distributions to noncontrolling interest owners (327) (260) (365) (327)
Proceeds from conveyance of future hard minerals royalty revenues, net of transaction costs —
 413
Payments of future hard minerals royalty revenues conveyed (50) (25)
Payments of future hard-minerals royalty revenues conveyed (50) (50)
Other financing activities (18) —
 (2) (18)
Net cash provided by (used in) financing activities (527) 2,421
 (2,306) (527)
Effect of Exchange Rate Changes on Cash 1
 (1)
Net Increase (Decrease) in Cash and Cash Equivalents 2,067
 3,041
Cash and Cash Equivalents at Beginning of Period 3,184
 939
Cash and Cash Equivalents at End of Period $5,251
 $3,980
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and restricted cash equivalents (18) 4
Net Increase (Decrease) in Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents (2,681) 2,068
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at Beginning of Period 4,674
 3,308
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at End of Period $1,993
 $5,376

See accompanying Notes to Consolidated Financial Statements.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)



1. Summary of Significant Accounting Policies

General  Anadarko Petroleum Corporation is engaged in the exploration, development, production, and sale of oil, natural gas, and NGLs and in advancing its Mozambique LNG project toward a final investment decision.FID. In addition, the Company engages in the gathering, compressing, treating, processing, treating,and transporting of natural gas; gathering, stabilizing, and transporting of oil natural gas, and NGLs as well asNGLs; and gathering and disposaldisposing of produced water. The Company also participates in the hard-minerals business through royalty arrangements.

Basis of Presentation  The accompanying unaudited consolidated financial statements have been prepared in accordance with GAAPU.S. Generally Accepted Accounting Principles for interim financial information and the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain notes and other information have been condensed or omitted. The accompanying interim financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the Company’s consolidated financial statements. Certain prior-period amounts have been reclassified to conform to the current-period presentation. These interim financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.
During the second quarter of 2017, the Company revised its reporting segments to reflect a change in how management reviews financial information and makes operating decisions. The Company has reclassified prior-period amounts to conform to the current period’s presentation. See Note 17—Segment Information for additional information on the change in reporting segments.2017.
The consolidated financial statements include the accounts of Anadarko and subsidiaries in which Anadarko holds, directly or indirectly, more than 50% of the voting rights and VIEs for which Anadarko is the primary beneficiary. The Company has determined that WGP and WES are VIEs. Anadarko is considered the primary beneficiary and consolidates WGP and WES. WGP and WES function with capital structures that are separate from Anadarko, consisting of their own debt instruments and publicly traded common units. All intercompany transactions have been eliminated. Undivided interests in oil and natural-gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in noncontrolled entities that Anadarko has the ability to exercise significant influence over operating and financial policies and VIEs for which Anadarko is not the primary beneficiary are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for the Company’s proportionate share of earnings, losses, and distributions. Other investments are carried at original cost. Investments accounted for using the equity method and cost method are included in other assets.

Recently Adopted Accounting StandardsASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, assists in determining whether a transaction should be accounted for as an acquisition or disposal of assets or as a business. This ASU provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the assets will not be considered a business. If the screen is not met, the assets must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. The Company’s adoption of this ASU on January 1, 2017, using a prospective approach, could have a material impact on consolidated financial statements as goodwill will not be allocated to divestitures or recorded on acquisitions that are not considered businesses. See Note 3—Acquisitions, Divestitures, and Assets Held for Sale.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory, requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs and eliminates the exception for an intra-entity transfer of an asset other than inventory. The Company adopted this ASU on January 1, 2017, using a modified retrospective approach, and recognized a cumulative adjustment to retained earnings of $31 million during the first quarter of 2017.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


1. Summary of Significant Accounting Policies (Continued)

ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, simplifies the accounting for share-based payment transactions, including the income tax consequences, classification on the statement of cash flows, accounting for forfeitures, and classification of awards as either equity or liabilities. As a result of adopting this ASU on January 1, 2017, excess tax benefits and tax deficiencies related to share-based compensation are reflected on a prospective basis in the income statement as a component of the provision for income taxes rather than additional paid-in capital as previously recognized. For the nine months ended September 30, 2017, the Company recognized a $13 million tax deficiency as an increase to the provision for income taxes. Cash flows related to excess tax benefits are classified on a prospective basis as operating activities in the statement of cash flows rather than cash inflows from financing activities and cash outflows from operating activities as previously recognized. Prior periods of the statement of cash flows were not adjusted as there was no material impact. In addition, the Company elected to begin accounting for share-based compensation award forfeitures when they occur instead of estimating the number of forfeitures expected. This change in accounting policy for share-based compensation award forfeitures did not have a material impact on the Company’s consolidated financial statements.

New Accounting Standards Issued But Not Yet Adopted  ASU 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period and presentation of the remaining components of net benefit cost in a separate line item outside operating items. Additionally, only the service cost component of net benefit cost will be eligible for capitalization. The Company will adoptadopted this ASU on January 1, 2018, with retrospective presentation of the service cost component and the other components of net benefit cost in the income statement and prospective presentation for the capitalization of the service cost component of net benefit cost in assets. Upon adoption, non-service cost components of net periodic benefit costs of $225$107 million for the year ended 2016 and2017, including $94 million for the nine months ended September 30, 2017, will bewere reclassified to other (income) expense, net, from G&A; oil and gas operating; gathering, processing, and marketing; and exploration expense. The Company does not expect any other material changes upon adoption of this ASU.
ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. ThisThe Company adopted this ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach with early adoption permitted. The Company will adopt this ASU on January 1, 2018, and does2018. Adoption did not expect the adoption to have a material impact on itsthe Company’s consolidated financial statements.
ASU 2016-15, Statement See Consolidated Statements of Cash Flows (Topic 230): Classification of Certainand Note 17—Supplemental Cash Receipts and Cash Payments,Flow Information provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach if practicable, with early adoption permitted. The Company will adopt this ASU on January 1, 2018, and does not expect the adoption to have a material impact on its Consolidated Statement of Cash Flows.additional information.


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


1. Summary of Significant Accounting Policies (Continued)

ASU 2014-09, Revenue from Contracts with Customers (Topic 606), supersedes currentthe revenue recognition requirements and industry-specific guidance under Revenue Recognition (Topic 605). Topic 606 requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing, and uncertainty of revenue and cash flows from contracts with customers. The Company has completed an initial review of contracts in each of its revenue streams and is developing accounting policies to address the provisions of the ASU. While the Company does not currently expect net earnings to be materially impacted, the Company has concluded that it is acting as an agent in the sale of certain volumes on behalf of its midstream service customers based on the requirements of the new ASU. This conclusion will result in the reduction of gathering and processing revenues and a corresponding reduction to gathering and processing expense related to its contracts with these customers. In addition, the Company expects to recognize revenue for commodities received as noncash consideration in exchange for services provided by our midstream business and revenue and associated cost of product for the subsequent sale of those same commodities. This recognition will result in an increase to revenues and expenses for gathering and processing activities with no impact on net earnings. The Company also expects changes in the timing of recognizing revenue for certain fees earned from its midstream business and hard minerals royalties due to the fee structure of certain contracts. Anadarko continues to evaluate the impact of these and other provisions of the ASU on its accounting policies, internal controls, and consolidated financial statements. Although the Company has not finalized the quantitative impact of the new standard, based on the assessment completed to date, the Company does not expect the adoption of this standard will have a material impact on its net earnings. The Company will complete its evaluation during the fourth quarter of 2017 and will adopt this new standardadopted Topic 606 on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. Under the modified retrospective method, prior-period financial positions and results will not be adjusted. The cumulative effect adjustment recognized in the opening balances included a reduction to total equity of $47 million. While the Company does not expect 2018 net earnings to be materially impacted by revenue recognition timing changes, Topic 606 requires certain changes to the presentation of revenues and related expenses beginning January 1, 2018. See Note 2—Revenue from Contracts with Customers for additional information. The Company’s revenue recognition accounting policy effective January 1, 2018, is detailed below.
Exploration and Production—The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.
Contracts with customers have varying terms, including spot sales or month-to-month contracts, contracts with a cumulative adjustmentfinite term, and life-of-field contracts where all production from a well or group of wells is sold to one or more customers. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs. For natural gas and NGLs sold on our behalf by a processor, revenue is typically measured based on the price the processor receives for the sale, less certain costs withheld by the processor.
Revenues are recognized for the sale of Anadarko’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues.
The Company enters into buy/sell arrangements related to the transportation of a portion of its oil production. Under these arrangements, barrels are sold to a third party at a location-based contract price and subsequently repurchased by the Company at a downstream location. The difference in value between the sale and purchase price represents the transportation fee to move oil from the lease or certain gathering locations to more liquid markets. These arrangements are often required by private transporters. These buy/sell transactions are recorded net in oil and gas transportation expense in the Company’s Consolidated Statements of Income.



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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. Summary of Significant Accounting Policies (Continued)

WES Midstream and Other Midstream—Anadarko provides gathering, compressing, treating, processing, stabilizing, transporting, and disposal services pursuant to a variety of contracts. Under these arrangements, the Company receives fees and/or retains a percentage of products or a percentage of the proceeds from the sale of the customer’s products. These revenues are included in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income. Payment is generally received from the customer in the month of service or the month following the service. Contracts with customers generally have initial terms ranging from 5 to 10 years.
Revenue is recognized for fee-based gathering and processing services in the month of service based on the volumes delivered by the customer. Revenues are valued based on the rate in effect for the month of service when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. The Company may charge additional service fees to customers for a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold) due to the significant upfront capital investment. These fees are recognized as revenue over the expected period of customer benefit, generally the life of the related properties. Deficiency fees, which are charged to the customer if they do not meet minimum delivery requirements, are recognized over the performance period based on an estimate of the deficiency fees that will be billed upon completion of the performance period.
The Company’s midstream business also purchases natural-gas volumes from producers at the wellhead or production facility, typically at an index price, and charges the producer fees associated with the downstream gathering and processing services. These fees are treated as a reduction of the purchase cost when the fees relate to services performed after control of the product has transferred to Anadarko. Revenue is recognized, along with cost of product expense related to the sale, when the purchased product is sold to a third party.
Revenue from percentage of proceeds gathering and processing contracts is recognized net of the cost of product for purchases from service customers when the Company is acting as their agent in the product sale, and any fees charged on these percentage of proceeds contracts are recognized in service revenues.
ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, provides entities the option to reclassify stranded tax effects resulting from the Tax Reform Legislation from accumulated other comprehensive income (AOCI) to retained earnings. In accordance with its accounting policy, the Company releases stranded income tax effects from AOCI in the period the underlying portfolio is liquidated. This ASU allows for the reclassification of stranded tax effects as a result of the change in tax rates from Tax Reform Legislation to be recorded upon adoption of the ASU, rather than at the actual portfolio liquidation date. The Company adopted this ASU on January 1, 2018, electing to reclassify $73 million from AOCI to retained earnings, including a $2 million federal benefit of state tax impact related to the Tax Reform Legislation.

New Accounting Standards Issued But Not Yet Adopted  ASU 2016-02, Leases (Topic 842), requires lessees to recognize a lease liability and a right-of-use (ROU) asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. The provisions ofThis ASU 2016-02 also modifymodifies the definition of a lease and outlineoutlines the requirements for recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. AnadarkoThe Company plans to electmake certain practical expedients when implementing the new lease standard, which meanselections allowing the Company will not have to reassess the accounting for contracts that commenced prior to adoption.adoption, to continue applying its current accounting policy for existing or expired land easements, and not to recognize ROU assets or lease liabilities for short-term leases. Anadarko has preliminarily determinedcontinues to review contracts in its portfolio of leased assets and is reviewing all related contracts to determineassess the impact thatof adopting this ASU. The Company expects the adoption will haveof this ASU to primarily impact other assets and other long-term liabilities and does not expect a material impact on its consolidated financial statements. The Company is also evaluating the impactresults of operations. To facilitate compliance with this ASU, onAnadarko expects to implement new accounting software and complete the evaluation of its systems, processes, and internal controls. The Companycontrols by the end of 2018. Anadarko will complete its evaluation in 2018 and adopt this new standardASU on January 1, 2019, using a modified retrospective approach for all comparative periods presented.approach. As permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements, the Company does not expect to adjust comparative-period financial statements and will recognize a cumulative effect adjustment in the opening balance of retained earnings in the period of adoption.

2. Inventories

The following summarizes the major classes of inventories included in other current assets:
millionsSeptember 30, 
 2017		 December 31, 
 2016
Oil$127
 $169
Natural gas29
 38
NGLs108
 106
Total inventories$264
 $313


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

2. Revenue from Contracts with Customers

Change in Accounting Policy  The Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. See Note 1—Summary of Significant Accounting Policies for additional information.

Impacts on Financial Statements

Exploration and Production There were no significant changes to the timing or valuation of revenue recognized for sales of production by the Exploration and Production segment.

WES Midstream and Other Midstream Gathering and processing revenues decreased for contracts where the Company is acting as an agent for its processing customer in the sale of processed volumes and increased for contracts with noncash consideration, with an offset to gathering and processing expense upon product sale. The magnitude of these presentation changes in subsequent periods is dependent on future customer volumes subject to the impacted contracts and commodity prices for those volumes. These presentation changes do not impact net earnings.

The following tables summarize the impacts of adopting Topic 606 on the Company’s consolidated financial statements:
CONSOLIDATED BALANCE SHEETImpact of Change in Accounting Policy
millionsAs Reported Without Adoption of Topic 606 
Effect of Change
Increase/(Decrease)
September 30, 2018     
Assets     
Other current assets$397
 $395
 $2
Net properties and equipment28,744
 28,697
 47
Other assets2,292
 2,282
 10
Liabilities     
Other current liabilities1,502
 1,494
 8
Deferred income taxes2,455
 2,461
 (6)
Other4,043
 3,932
 111
Equity     
Total equity11,237
 11,291
 (54)








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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

2. Revenue from Contracts with Customers (Continued)

CONSOLIDATED STATEMENT OF INCOMEImpact of Change in Accounting Policy
millionsAs Reported Without Adoption of Topic 606 
Effect of Change
Increase/(Decrease)
Three Months Ended September 30, 2018     
Revenues     
Gathering, processing, and marketing sales$421
 $717
 $(296)
Gains (losses) on divestitures and other, net90
 89
 1
Expenses     
Gathering, processing, and marketing256
 551
 (295)
Income tax expense (benefit)256
 254
 2
Net income (loss) attributable to noncontrolling interests64
 71
 (7)
Net Income (Loss) Attributable to Common Stockholders$363
 $358
 $5
      
Nine Months Ended September 30, 2018     
Revenues     
Gathering, processing, and marketing sales$1,163
 $1,944
 $(781)
Gains (losses) on divestitures and other, net232
 233
 (1)
Expenses     
Gathering, processing, and marketing745
 1,520
 (775)
Income tax expense (benefit)507
 507
 —
Net income (loss) attributable to noncontrolling interests105
 111
 (6)
Net Income (Loss) Attributable to Common Stockholders$513
 $514
 $(1)


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

2. Revenue from Contracts with Customers(Continued)

Disaggregation of Revenue from Contracts with CustomersThe following table disaggregates revenue by significant product type and segment:
millionsExploration
& Production		 WES Midstream Other Midstream Other and
Intersegment
Eliminations		 Total
Three Months Ended September 30, 2018         
Oil sales$2,572
 $—
 $—
 $—
 $2,572
Natural-gas sales232
 —
 —
 —
 232
Natural-gas liquids sales382
 —
 —
 —
 382
Gathering, processing, and marketing sales (1)
—
 511
 113
 1
 625
Other, net9
 —
 —
 31
 40
Total Revenue from Customers$3,195
 $511
 $113
 $32
 $3,851
Gathering, processing, and marketing sales (2)
—
 (3) 3
 (204) (204)
Gains (losses) on divestitures, net5
 —
 1
 (3) 3
Other, net(8) 52
 12
 (9) 47
Total Revenue from Other than Customers$(3) $49
 $16
 $(216) $(154)
Total Revenue and Other$3,192
 $560
 $129
 $(184) $3,697
          
Nine Months Ended September 30, 2018         
Oil sales$6,964
 $—
 $—
 $—
 $6,964
Natural-gas sales682
 —
 —
 —
 682
Natural-gas liquids sales992
 —
 —
 —
 992
Gathering, processing, and marketing sales (1)
—
 1,438
 255
 83
 1,776
Other, net16
 —
 —
 71
 87
Total Revenue from Customers$8,654
 $1,438
 $255
 $154
 $10,501
Gathering, processing, and marketing sales (2)
—
 (6) 6
 (613) (613)
Gains (losses) on divestitures, net24
 —
 10
 (3) 31
Other, net(21) 113
 30
 (8) 114
Total Revenue from Other than Customers$3
 $107
 $46
 $(624) $(468)
Total Revenue and Other$8,657
 $1,545
 $301
 $(470) $10,033
 __________________________________________________________________
(1)
The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $328 million and intercompany eliminations of $(312) million for the three months ended September 30, 2018, and sales of third-party natural gas and NGLs of $813 million and intercompany eliminations of $(715) million for the nine months ended September 30, 2018.
(2)
The amount in Other and Intersegment Eliminations represents purchases of third-party natural gas and NGLs. Although these purchases are reported net in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income, they are shown separately on this table, as the purchases are not considered revenue from customers.


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

2. Revenue from Contracts with Customers(Continued)

Contract Liabilities Contract liabilities primarily relate to midstream fees and capital reimbursements that are charged to customers for only a portion of the contract term and must be recognized as revenues over the expected period of benefit, fixed and variable fees that are received from customers but revenue recognition is deferred under midstream cost of service contracts, and hard-minerals bonus payments received from customers that must be recognized as revenue over the expected period of benefit. The following table summarizes the current period activity related to contract liabilities from contracts with customers:
millions 
Balance at December 31, 2017$37
Increase due to cumulative effect of adopting Topic 60698
Increase due to cash received, excluding revenues recognized in the period (1)
46
Decrease due to revenue recognized (2)
(30)
Balance at September 30, 2018$151
  
Contract liabilities at September 30, 2018 
Other current liabilities$23
Other long-term liabilities - other128
Total contract liabilities from contracts with customers$151
 __________________________________________________________________
(1)
Includes $(6) million for the three months ended September 30, 2018.
(2)
Includes $(9) million for the three months ended September 30, 2018.

Transaction Price Allocated to Remaining Performance Obligations Revenue expected to be recognized from certain performance obligations that are unsatisfied as of September 30, 2018, is reflected in the table below. The Company applies the optional exemptions in Topic 606 and does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied performance obligations. Therefore, the following table represents only a small portion of Anadarko’s expected future consolidated revenues as future revenue from the sale of most products and services is dependent on future production or variable customer volumes and variable commodity prices for those volumes.
millionsExploration
& Production		 WES Midstream Other Midstream Other and
Intersegment
Eliminations		 Total
Remainder of 2018$27
 $124
 $31
 $(96) $86
2019104
 480
 204
 (441) 347
2020103
 545
 293
 (606) 335
2021103
 525
 361
 (672) 317
20227
 529
 417
 (739) 214
Thereafter65
 2,192
 3,107
 (4,662) 702
Total$409
 $4,395
 $4,413
 $(7,216) $2,001


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

3. Acquisitions,Commodity Inventories

The following summarizes the major classes of commodity inventories included in other current assets:
 September 30, December 31,
millions2018 2017
Oil$168
 $165
Natural gas19
 29
NGLs131
 122
Total commodity inventories$318
 $316

4. Divestitures and Assets Held for Sale

AcquisitionDivestitures   On December 15, 2016,The following summarizes the proceeds received and gains (losses) recognized on divestitures:
 Nine Months Ended
 September 30,
millions2018 2017
Proceeds received, net of closing adjustments$393
 $3,480
Gains (losses) on divestitures, net (1)
31
 815

(1)
Includes the $126 million gain related to the 2017 property exchange discussed below.

2018 During the nine months ended September 30, 2018, the Company closed the GOM Acquisition for $1.8 billion using a portiondivested of the following U.S. onshore and Gulf of Mexico assets:
Alaska nonoperated assets, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds fromof $370 million and net losses of $33 million in 2018 and $154 million in the fourth quarter of 2017.
Ram Powell nonoperated assets in the Gulf of Mexico, included in the Exploration and Production reporting segment, resulting in a net gain of $67 million.

2017 During the nine months ended September 2016 issuance of 40.5 million shares of its common stock. The GOM Acquisition constituted a business combination and was accounted for using30, 2017, the acquisition method of accounting. Fair-value measurementsCompany divested of the following U.S. onshore assets:
Eagleford assets acquiredin South Texas, included in the Exploration and liabilities assumed atProduction reporting segment, for net proceeds of $2.1 billion and a net gain of $730 million
Marcellus assets in Pennsylvania, included in the acquisition date were finalized duringExploration and Production and Other Midstream reporting segments, for net proceeds of $758 million and net losses of $56 million in 2017 and $129 million in the fourth quarter ended June 30, 2017. There were no material changes toof 2016
Eaglebine assets in Southeast Texas, included in the fair valueExploration and Production reporting segment, for net proceeds of $533 million and a net gain of $282 million
Utah CBM assets, included in the assets acquiredExploration and liabilities assumed from the amounts included on the Company’s Consolidated Balance Sheet at December 31, 2016.Production and WES Midstream reporting segments, for net proceeds of $69 million and a net loss of $52 million

Property Exchange On March 17, 2017, WES acquired a third party’s 50% nonoperated interest in the DBJV systemSystem in exchange for WES’s 33.75% interest in nonoperated Marcellus midstream assets and $155 million in cash. WES recognized a gain of $126 million as a result of this transaction. AfterFollowing the acquisition, the DBJV systemSystem is 100% owned by WES and consolidated by Anadarko.

Divestitures and Assets Held for Sale  The following summarizes the proceeds received and gains (losses) recognized on divestitures and assets held for sale for the nine months ended September 30:
millions2017 2016
Proceeds received, net of closing adjustments$3,480
 $1,281
Gains (losses) on divestitures, net (1)
815
 (516)

(1)
Includes the $126 million gain related to the property exchange discussed above.

2017 During the nine months ended September 30, 2017, the Company divested of the following assets:
Eagleford assets in South Texas, included in the Exploration and Production reporting segment, for net proceeds of $2.1 billion and a net gain of $730 million
Eaglebine assets in Southeast Texas, included in the Exploration and Production reporting segment, for net proceeds of $533 million and a net gain of $282 million
Utah CBM assets, included in the Exploration and Production and Midstream reporting segments, for net proceeds of $69 million and a net loss of $52 million
Marcellus assets in Pennsylvania, included in the Exploration and Production and Midstream reporting segments, for net proceeds of $758 million and net losses of $129 million in the fourth quarter of 2016 and $56 million for the nine months ended September 30, 2017
Certain Marcellus assets in Pennsylvania, included in the Exploration and Production and Midstream reporting segments, satisfied criteria to be considered held for sale during the fourth quarter of 2016, at which time the Company remeasured these assets to their current fair value using a market approach and Level 2 fair-value inputs and recognized the losses discussed above. Proceeds of $196 million associated with these assets were held in escrow by the purchaser and reflected as Accounts Receivable, Others on the Company’s Consolidated Balance Sheet as of September 30, 2017. In October 2017, proceeds of $193 million were released from escrow. The remaining $3 million is expected to be released by early 2018.
Certain Moxa Arch assets in Wyoming, included in the Exploration and Production reporting segment, satisfied criteria to be considered held for sale during the third quarter of 2017, at which time the Company remeasured these assets to their current fair value using a market approach and Level 2 fair-value inputs and recognized a loss of $197 million. At September 30, 2017, the Company’s Consolidated Balance Sheet included long-term assets of $557 million and long-term liabilities of $37 million associated with the Moxa Arch assets held for sale. Losses on assets held for sale are included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income.

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3. Acquisitions, Divestitures, and Assets Held for Sale (Continued)

2016 During the nine months ended September 30, 2016, the Company divested of the following assets:
Wamsutter assets in Wyoming, included in the Exploration and Production reporting segment, for net proceeds of $588 million and a net loss of $59 million
Ozona and Steward assets in West Texas, included in the Exploration and Production and Midstream reporting segments, for net proceeds of $223 million and a net loss of $50 million
East Chalk assets in East Texas/Louisiana, included in the Exploration and Production reporting segment, for net proceeds of $99 million and a net gain of $13 million
Elm Grove assets in East Texas/Louisiana, included in the Exploration and Production reporting segment, for net proceeds of $100 million and a net loss of $54 million
The Carthage assets in East Texas, included in the Exploration and Production and Midstream reporting segments, satisfied criteria to be considered held for sale during the third quarter of 2016, at which time the Company remeasured these assets to their current fair value using a market approach and Level 2 fair-value measurement and recognized a loss of $355 million. The sale of these assets closed in the fourth quarter of 2016.

4.5. Impairments

Impairments of Long-Lived Assets

Impairments2018 During the nine months ended September 30, 2018, the Company expensed $319 million primarily related to the following:
$145 million in the third quarter of long-lived2018 related to hard-minerals properties due to the Company’s primary consumer of coal stating its intent to retire its existing coal-fired power generation plant earlier than expected, coupled with the outlook for limited new markets for the Company’s coal in the Rockies region. These coal assets arehad a post-impairment fair value of $15 million.
$126 million related to a gathering system in the DJ basin, included in impairment expensethe WES Midstream reporting segment that was permanently taken out of service in the Company’s Consolidated Statementssecond quarter of Income. The following summarizes impairments of long-lived assets and the related post-impairment fair values by segment:2018.
  Nine Months Ended
millionsImpairment 
Fair Value (1)
September 30, 2017   
Exploration and Production   
U.S. onshore properties$2
 $3
Gulf of Mexico properties211
 231
Midstream169
 58
Other1
 —
Total$383
 $292

(1)
Measured as of the impairment date using the income approach and Level 3 inputs. The primary assumptions used to estimate undiscounted future net cash flows include anticipated future production, commodity prices, and capital and operating costs.

Impairments during2017 During the nine months ended September 30, 2017, werethe Company expensed $383 million primarily related to the following:
$211 million related to oil and gas properties in the Gulf of Mexico, included in the Exploration and Production reporting segment, due to lower forecasted commodity prices andat that time. The assets had a post-impairment fair value of $231 million.
$168 million related to U.S. onshore midstream propertyproperties, included in the WES Midstream reporting segment, primarily due to a reduced throughput fee as a result of a producer’s bankruptcy. The assets had a post-impairment fair value of $58 million.
Fair values were measured as of the impairment date using the income approach and Level 3 inputs. The primary assumptions used to estimate undiscounted future net cash flows include anticipated future production, commodity prices, and capital and operating costs.

Impairments of Unproved PropertiesImpairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. During the nine months ended September 30, 2018, the Company recognized $158 million of impairments of unproved Gulf of Mexico properties primarily related to blocks where the Company determined it would no longer pursue activities. The Company recognized $586 million of impairments of unproved Gulf of Mexico properties during the nine months ended September 30, 2017, primarily due to an impairment of which $463 million related to the Shenandoah project. The unproved property balance related to the Shenandoah project originated from the purchase price allocated to the Gulf of Mexico exploration projects from the acquisition of Kerr-McGee Corporation in 2006. For additional details on the Shenandoah project, see Note 5—Exploratory Well Costs.

It is reasonably possible that significant declines in commodity prices, further changes to the Company’s drilling plans in response to lower prices, reduction of proved and probable reserve estimates, or increases in drilling or operating costs could result in other additional impairments.


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5.6. Suspended Exploratory Well Costs

During the nine months ended September 30, 2017, exploratory well costs were expensed for certain exploratory wells that did not encounter commercial quantities of hydrocarbons or that the Company determined were no longer making sufficient progress for continued capitalization of the exploratory well costs.

Gulf of Mexico The Company expensed exploratory well costs of $801 million during the nine months ended September 30, 2017, primarily related to the following projects:
Shenandoah The Company expensed $438 million related to the Shenandoah-6 appraisal well and subsequent sidetrack, which completed appraisal activities in April 2017 and did not encounter the oil-water contact in the eastern portion of the field. Given the results of this well and the commodity-price environment at that time, the Company suspended further appraisal activities.
Phobos The Company expensed $221 million in the third quarter of 2017 related to wells at the Phobos project. These wells found insufficient quantities of oil pay to justify development in the current price environment.
Warrior The Company expensed $110 million in the third quarter of 2017 related to the northern appraisal well and sidetrack at the Warrior project. These wells found insufficient quantities of oil pay to justify development of the northern portion of the field in the current price environment. Evaluation of the remaining appraisal well in the southern portion of the field is ongoing.

ColombiaDuring the nine months ended September 30, 2017, the Company expensed exploratory well costs of $243 million related to wells in the Grand Fuerte area in Colombia due to insufficient progress on contractual and fiscal reforms needed for deepwater gas development. All leases remain contractually in good standing.

Côte d’Ivoire During the second quarter of 2017, the Company expensed exploratory well costs of $119 million in Côte d’Ivoire due to unsuccessful drilling activities in the south channel of the Paon prospect and in Block CI-527. During the third quarter of 2017, after further evaluation of recent well results, Anadarko initiated relinquishment of the Company’s interests in its Côte d’Ivoire blocks and expensed the remaining $206 million of exploratory well and appraisal costs related to the Paon project.

Suspended Exploratory Well CostsThe Company’s suspended exploratory well costs were $530$510 million at September 30, 2017,2018, and $1.2 billion$525 million at December 31, 2016.2017. For exploratory wells, drilling costs are capitalized, or “suspended,” on the balance sheet when the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time. During the nine months ended September 30, 2017, $488 million of2018, there was no exploration expense recorded for suspended exploratory well costs previously capitalized for greater than one year at December 31, 2016, were charged to exploration expense.2017.


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6.7. Current Liabilities

Accounts Payable Accounts payable, trade included liabilities of $204$205 million at September 30, 2017,2018, and $262$219 million atDecember 31, 2016,2017, representing the amount by which checks issued but not presented to the Company’s banks for collection exceeded balances in applicable bank accounts. Changes in these liabilities are classified as cash flows from financing activities.

Other Current Liabilities The following summarizes the Company’s other current liabilities:
September 30, December 31,
millionsSeptember 30, 
 2017		 December 31, 
 2016		2018 2017
Accrued income taxes$211
 $6
$79
 $71
Interest payable161
 244
169
 246
Production, property, and other taxes payable249
 239
344
 216
Accrued employee benefits207
 355
270
 210
Derivatives233
 175
491
 384
Other142
 218
149
 183
Total other current liabilities$1,203
 $1,237
$1,502
 $1,310

7.8. Derivative Instruments

Objective and Strategy  The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Futures, swaps, and options are used to manage exposure to commodity-price risk inherent in the Company’s oil and natural-gas production and natural-gas processing operations (Oil and Natural-Gas Production/Processing Derivative Activities). Futures contracts and commodity-price swap agreements are used to fix the price of expected future oil and natural-gas sales at major industry trading locations, such as Cushing, Oklahoma or Sullom Voe, Scotland for oil and Henry Hub, Louisiana for natural gas. Basis swaps are periodically used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities (Marketing and Trading Derivative Activities).facilities.
Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to interest-rate changes. The fair value of the Company’s current interest-rate swap portfolio is subject to changes in interest rates.
The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized currently in earnings. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings.


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7.8. Derivative Instruments (Continued)

Oil and Natural-Gas Production/Processing Derivative Activities  The oil prices listed below are a combination of NYMEX West Texas IntermediateWTI and Intercontinental Exchange, Inc. (ICE) Brent Blend prices. The natural-gas prices listed below are NYMEX Henry Hub prices. The NGLs prices listed below are Oil Price Information Services prices. The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at September 30, 2017:2018:
2017 Settlement 2018 Settlement2018 Settlement 2019 Settlement
Oil      
Two-Way Collars (MBbls/d)108
 —
Average price per barrel (WTI)
 
Ceiling sold price (call)$60.48
 $—
Floor purchased price (put)$50.00
 $—
Three-Way Collars (MBbls/d)91
 —
—
 87
Average price per barrel
  
Average price per barrel (WTI and Brent)
 

Ceiling sold price (call)$59.80
 $—
$—
 $72.98
Floor purchased price (put)$50.00
 $—
$—
 $56.72
Floor sold price (put)$40.00
 $—
$—
 $46.72
Fixed-Price Contracts (MBbls/d)84
 —
Average price per barrel (Brent)$61.45
 $—
Natural Gas   
 
Three-Way Collars (thousand MMBtu/d)857
 250
250
 —
Average price per MMBtu   
Average price per MMBtu (Henry Hub)
 
Ceiling sold price (call)$3.64
 $3.54
$3.54
 $—
Floor purchased price (put)$2.85
 $2.75
$2.75
 $—
Floor sold price (put)$2.10
 $2.00
$2.00
 $—
Fixed-Price Contracts (thousand MMBtu/d)280
 —
Average price per MMBtu (Henry Hub)$3.02
 $—

A two-way collar is a combination of two options: a sold call and a purchased put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes.
A three-way collar is a combination of three options: a sold call, a purchased put, and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (e.g., NYMEX) plus the excess of the purchased put strike price over the sold put strike price.

Marketing and Trading Derivative Activities  The Company had financial derivative transactions with notional volumes of natural gas totaling 15 Bcf at September 30, 2017, and 2 Bcf at December 31, 2016, that were entered into to mitigate commodity-price risk related to fixed-price purchase and sales contracts and storage activity.


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7.8. Derivative Instruments (Continued)

Interest-Rate Derivatives  Anadarko has outstanding interest-rate swap contracts to manage interest-rate risk associated with anticipated debt issuances. The Company has locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month LIBOR.
In June 2017, the Company amended certain interest-rate swaps with an aggregate notional principal amount of $625 million, extending the mandatory termination dates fromAugust 2018, to 2020, 2022, and 2023 in exchange for cash payments of approximately $57 million. In July 2017, the Company amended an interest-rate swap with a notional principal amount of $125$200 million, extending the mandatory termination date from 2018 to 20222023 in exchange for a cash payment of approximately $15$10 million.
At September 30, 2017,2018, the Company had outstanding interest-rate swaps with a notional amount of $1.6 billion due prior to or in September 2023 that manage interest-rate risk associated with the potential refinancing of the Company’s future debt maturities.issuances. Depending on market conditions, liability-management actions, or other factors, the Company may enter into offsetting interest-rate swap positions or settle or amend certain or all of the currently outstanding interest-rate swaps. The Company had the following outstanding interest-rate swaps at September 30, 2017:2018: 
millions except percentagesmillions except percentages  Mandatory Weighted-Averagemillions except percentages  Mandatory Weighted-Average
Notional Principal AmountNotional Principal Amount Reference Period Termination Date Interest RateNotional Principal Amount Reference Period Termination Date Interest Rate
$550
 September 2016 - 2046
September 2020 6.418%550
 September 2016 - 2046
September 2020 6.418%
$250
 September 2016 - 2046 September 2022 6.809%250
 September 2016 - 2046 September 2022 6.809%
$200
 September 2017 - 2047 September 2018 6.049%100
 September 2017 - 2047 September 2020 6.891%
$100
 September 2017 - 2047 September 2020 6.891%250
 September 2017 - 2047 September 2021 6.570%
$250
 September 2017 - 2047 September 2021 6.570%450
 September 2017 - 2047 September 2023 6.445%
$250
 September 2017 - 2047 September 2023 6.761%

Derivative settlements and collateralization are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements and collateralization are classified as cash flows from financing activities. As a result of prior extensions of reference-period start dates without settlement of the related interest-rate derivative obligations, the interest-rate derivatives in the Company’s portfolio contain an other-than-insignificant financing element, and therefore, any settlements, collateralization, or cash payments for amendments related to these extended interest-rate derivatives are classified as cash flows from financing activities. Net cash payments related to settlements and amendments of interest-rate swap agreements were $101 million during the nine months ended September 30, 2018, and $118 million during the nine months ended September 30, 2017, and $275 million during the nine months ended September 30, 2016.2017.


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7.8. Derivative Instruments (Continued)

Effect of Derivative Instruments—Balance Sheet  The following summarizes the fair value of the Company’s derivative instruments:
 Gross Derivative Assets Gross Derivative Liabilities Gross Derivative Assets Gross Derivative Liabilities
millions September 30, December 31, September 30, December 31, September 30, December 31, September 30, December 31,
Balance Sheet Classification 2017 2016 2017 2016 2018 2017 2018 2017
Commodity derivatives                
Other current assets $58
 $10
 $(40) $(3) $2
 $7
 $—
 $(1)
Other assets 33
 9
 (29) —
 —
 2
 —
 —
Other current liabilities 38
 66
 (44) (201) 20
 45
 (440) (206)
Other liabilities 163
 —
 (166) (12) 15
 —
 (56) (2)
 292
 85
 (279) (216) 37
 54
 (496) (209)
Interest-rate derivatives 
       
      
Other current assets 12
 8
 —
 —
 21
 14
 —
 —
Other assets 42
 23
 —
 —
 54
 40
 —
 —
Other current liabilities —
 —
 (237) (48) —
 —
 (80) (236)
Other liabilities —
 —
 (1,176) (1,328) —
 —
 (1,028) (1,183)
 54
 31
 (1,413) (1,376) 75
 54
 (1,108) (1,419)
Total derivatives $346
 $116
 $(1,692) $(1,592) $112
 $108
 $(1,604) $(1,628)

Effect of Derivative Instruments—Statement of Income  The following summarizes gains and losses related to derivative instruments:
 Three Months Ended Nine Months Ended
millions Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		 September 30, September 30,
Classification of (Gain) Loss Recognized 2017 2016 2017 2016 2018 2017 2018 2017
Commodity derivatives                
Gathering, processing, and marketing sales (1)
 $—
 $(1) $—
 $5
Gathering, processing, and marketing sales $1
 $—
 $3
 $—
(Gains) losses on derivatives, net 43
 (59) (164) 7
 104
 43
 734
 (164)
Interest-rate derivatives 
 
   
 
 
   
(Gains) losses on derivatives, net 39
 84
 131
 622
 (72) 39
 (231) 131
Total (gains) losses on derivatives, net $82
 $24
 $(33) $634
 $33
 $82
 $506
 $(33)

(1)
Represents the effect of Marketing and Trading Derivative Activities.


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7.8. Derivative Instruments (Continued)

Credit-Risk Considerations  The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or ICE through systems of financial safeguards and transaction guarantees. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact on the fair value of its counterparties’ creditworthiness. The Company has the ability to require cash collateral or letters of credit to mitigate its credit-risk exposure.
The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities and routinely exercises its contractual right to offset gains and losses when settling with derivative counterparties. In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and provide for contract termination and net settlement across derivative types.
The Company’s derivative instruments are subject to individually negotiated credit provisions that may require collateral of cash or letters of credit depending on the derivative’s portfolio valuation versus negotiated credit thresholds. These credit thresholds may alsogenerally require full or partial collateralization or immediate settlement of the Company’s obligations ifdepending on certain credit-risk-related provisions, are triggered, such as if the Company’s credit rating from S&P and Moody’s declines to a level that is below investment grade.Moody’s. As of September 30, 2017,2018, the Company’s long-term debt was rated investment grade (BBB) by both S&P and Fitch Ratings and below investment grade (Ba1) by Moody’s. Although certain counterpartiesThe Company may be required to post additional collateral with respect to its derivative instruments if its credit ratings decline below current levels or if the liability associated with any such derivative instrument increases substantially. For example, based on the derivative positions as of September 30, 2018, if Anadarko’s credit rating were to be downgraded one level by either S&P or Moody’s, the Company could be required to post additional collateral dueof up to the Moody’s rating, no counterparties have requested termination or full settlement of derivative positions.approximately $124 million. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.2$1.4 billion (net of $159$49 million of collateral) at September 30, 2017,2018, and $1.4 billion (net of $117$170 million of collateral) at December 31, 2016.2017.


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7.8. Derivative Instruments (Continued)

Fair Value  Fair value of futures contracts is based on unadjusted quoted prices in active markets for identical assets or liabilities, which represent Level 1 inputs. Valuations of physical-delivery purchase and sale agreements, over-the-counter financial swaps, and commodity option collars are based on similar transactions observable in active markets and industry-standard models that primarily rely on market-observable inputs. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. Inputs used to estimate the fair value of swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and, for Black-Scholes option valuations, discount factors and implied market volatility.
The following summarizes the fair value of the Company’s derivative assets and liabilities by input level within the fair-value hierarchy:
millionsLevel 1 Level 2 Level 3 
Netting (1)
 Collateral TotalLevel 1 Level 2 Level 3 
Netting (1)
 Collateral Total
September 30, 2017           
September 30, 2018           
Assets                      
Commodity derivatives$—
 $292
 $—
 $(271) $—
 $21
$—
 $37
 $—
 $(35) $—
 $2
Interest-rate derivatives—
 54
 —
 —
 —
 54
—
 75
 —
 —
 —
 75
Total derivative assets$—
 $346
 $—
 $(271) $—
 $75
$—
 $112
 $—
 $(35) $—
 $77
Liabilities                      
Commodity derivatives$—
 $(279) $—
 $271
 $—
 $(8)$—
 $(496) $—
 $35
 $6
 $(455)
Interest-rate derivatives—
 (1,413) —
 —
 159
 (1,254)—
 (1,108) —
 —
 49
 (1,059)
Total derivative liabilities$—
 $(1,692) $—
 $271
 $159
 $(1,262)$—
 $(1,604) $—
 $35
 $55
 $(1,514)
                      
December 31, 2016           
December 31, 2017           
Assets                      
Commodity derivatives$2
 $83
 $—
 $(69) $—
 $16
$1
 $53
 $—
 $(46) $(1) $7
Interest-rate derivatives—
 31
 —
 —
 —
 31
—
 54
 —
 —
 —
 54
Total derivative assets$2
 $114
 $—
 $(69) $—
 $47
$1
 $107
 $—
 $(46) $(1) $61
Liabilities                      
Commodity derivatives$(3) $(213) $—
 $69
 $6
 $(141)$(1) $(208) $—
 $46
 $3
 $(160)
Interest-rate derivatives—
 (1,376) —
 —
 117
 (1,259)—
 (1,419) —
 —
 170
 (1,249)
Total derivative liabilities$(3) $(1,589) $—
 $69
 $123
 $(1,400)$(1) $(1,627) $—
 $46
 $173
 $(1,409)
 __________________________________________________________________
(1) 
Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

9. Tangible Equity Units

In June 2015, the Company issued 9.2 million 7.50% TEUs at a stated amount of $50.00 per TEU and raised net proceeds of $445 million. Each TEU was comprised of a prepaid equity purchase contract for common units of WGP and a senior amortizing note. The prepaid equity purchase contract was considered a freestanding financial instrument, indexed to WGP common units, and met the conditions for equity classification.

Equity ComponentOn June 7, 2018, the mandatory settlement date, Anadarko settled 9.2 million outstanding TEUs in exchange for approximately 8.2 million WGP common units based on the determined final settlement rate of 0.8921 WGP common units per outstanding TEU. See settlement of tangible equity units in the Company’s Consolidated Statement of Equity.

Debt Component Each senior amortizing note had an initial principal amount of $10.95 and bore interest at 1.50% per year. The final installment payment of $9 million was made on June 7, 2018. For activity related to the senior amortizing notes, see Note 10—Debt.

10. Debt

Debt Activity  The following summarizes the Company’s borrowing activity, after eliminating the effect of intercompany transactions, during the nine months ended September 30, 2018:
 Carrying Value  
millionsWES 
WGP (1)
 
Anadarko (2)
 Anadarko Consolidated Description
Balance at December 31, 2017$3,465
 $28
 $11,965
 $15,458
  
Issuances

 
 

 

  
 394
 —
 —
 394
 WES 4.500% Senior Notes due 2028
 687
 —
 —
 687
 WES 5.300% Senior Notes due 2048
 396
 —
 —
 396
 WES 4.750% Senior Notes due 2028
 342
 —
 —
 342
 WES 5.500% Senior Notes due 2048
Borrowings

 

 
 

  
 320
 —
 —
 320
 WES RCF
Repayments

 
 
 

  
 (690) —
 —
 (690) WES RCF
 —
 —
 (114) (114) 7.050% Debentures due 2018
 (350) —
 —
 (350) WES 2.600% Senior Notes due 2018
 —
 —
 (17) (17) TEUs - senior amortizing notes
Other, net2
 —
 39
 41
 Amortization of discounts, premiums, and debt issuance costs
Balance at September 30, 2018$4,566
 $28
 $11,873
 $16,467
  

(1)
Excludes WES.
(2)
Excludes WES and WGP.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

8.10. Debt (Continued)

Debt  The following summarizes the Company’s outstanding debt, including capital lease obligations, after eliminating the effect of intercompany transactions:
millionsWES 
WGP (1)
 
Anadarko (2)
 ConsolidatedWES 
WGP (1)
 
Anadarko (2)
 Consolidated
September 30, 2017       
September 30, 2018       
Total borrowings at face value$3,370
 $28
 $13,523
 $16,921
$4,620
 $28
 $13,383
 $18,031
Net unamortized discounts, premiums, and debt issuance costs (3)
(26) —
 (1,563) (1,589)(54) —
 (1,510) (1,564)
Total borrowings (4)
3,344
 28
 11,960
 15,332
4,566
 28
 11,873
 16,467
Capital lease obligations—
 —
 241
 241
—
 —
 226
 226
Less short-term debt—
 —
 149
 149
—
 28
 910
 938
Total long-term debt$3,344
 $28
 $12,052
 $15,424
$4,566
 $—
 $11,189
 $15,755
              
December 31, 2016       
December 31, 2017       
Total borrowings at face value$3,120
 $28
 $13,558
 $16,706
$3,490
 $28
 $13,514
 $17,032
Net unamortized discounts, premiums, and debt issuance costs (3)
(29) —
 (1,599) (1,628)(25) —
 (1,549) (1,574)
Total borrowings (4)
3,091
 28
 11,959
 15,078
3,465
 28
 11,965
 15,458
Capital lease obligations—
 —
 245
 245
—
 —
 231
 231
Less short-term debt—
 —
 42
 42
—
 —
 142
 142
Total long-term debt$3,091
 $28
 $12,162
 $15,281
$3,465
 $28
 $12,054
 $15,547

(1) 
Excludes WES.
(2) 
Excludes WES and WGP.
(3) 
Unamortized discounts, premiums, and debt issuance costs are amortized over the term of the related debt. Debt issuance costs related to RCFs are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.
(4) 
The Company’s outstanding borrowings, except for borrowings under the WGP RCF, are senior unsecured.

Fair Value  The Company uses a market approach to determine the fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was $17.4$17.8 billion at September 30, 2017,2018, and $17.1$17.7 billion at December 31, 2016.2017.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


8.10. Debt (Continued)

Anadarko Borrowings  Anadarko has aIn January 2018, the Company amended its $3.0 billion senior unsecured RCF maturing into extend the maturity date to January 20212022 (APC RCF) and aamended its $2.0 billion 364-day senior unsecured RCF maturing into extend the maturity date to January 20182019 (364-Day Facility). At September 30, 2017, the Company2018, Anadarko had no outstanding borrowings under the APC RCF or the 364-Day Facility and was in compliance with all covenants.
At September 30, 2018, Anadarko had outstanding borrowings of $600 million of 8.700% Senior Notes due March 2019 and $300 million of 6.950% Senior Notes due June 2019 classified as short-term debt on the Company’s Consolidated Balance Sheet. Short-term debt also included the current portion of the Company’s capital lease obligations.
Anadarko’s Zero Coupons can be put to the Company in October of each year, in whole or in part, for the then-accreted value of the outstanding Zero Coupons. None of the Zero Coupons were put to the Company in October 2017.2018. The Zero Coupons can next be put to the Company in October 2018,2019, which, if put in whole, or in part, for the then-accreted value of $930would be $980 million.
The Company also has notes payable related to its ownership of certain noncontrolling mandatorily redeemable interests that are not included in the Company’s reported debt balance and do not affect consolidated interest expense. See Note 8—Equity MethodEquity-Method Investments in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.2017.

WES and WGP Borrowings  At September 30, 2017,In February 2018, WES was in compliance with all covenants contained inamended its $1.2 billion senior unsecured RCF maturing into extend the maturity date from February 2020 to February 2023 and expanded the borrowing capacity to $1.5 billion (WES RCF), which. As part of the amendment, the WES RCF is expandable to $1.5a maximum of $2.0 billion. During the nine months ended September 30, 2017,2018, WES borrowed $250$320 million under its RCF, which was used for general partnership purposes.purposes, and made repayments of $690 million. At September 30, 2017,2018, WES had no outstanding borrowings under its RCF, of $250 million at an interest rate of 2.54%, had outstanding letters of credit of $5 million, and had available borrowing capacity of $945 million. WES’s$1.495 billion, and was in compliance with all covenants.
In August 2018, WES completed a public offering of $400 million aggregate principal amount of 4.750% Senior Notes due August 2028 and a public offering of $350 million 2.60%aggregate principal amount of 5.500% Senior Notes due August 2048. The net proceeds from the public offerings were used to repay the maturing WES $350 million of 2.600% Senior Notes due August 2018, and amounts outstanding under the WES RCF. The remaining net proceeds were classified as long-term debt onused for general partnership purposes, including to fund capital expenditures.
In March 2018, WES completed a public offering of $400 million aggregate principal amount of 4.500% Senior Notes due March 2028 and a public offering of $700 million aggregate principal amount of 5.300% Senior Notes due March 2048. Net proceeds from the Company’s Consolidated Balance Sheet at September 30, 2017, aspublic offerings were used to repay amounts outstanding under the WES hasRCF and for general partnership purposes, including to fund capital expenditures.
In February 2018, WGP voluntarily reduced the ability and intent to refinance these obligations using long-term debt.
At September 30, 2017, WGP was in compliance with all covenants contained inaggregate commitments of the lenders under its $250 million three-year senior secured RCF maturing in March 2019 from $250 million to $35 million (WGP RCF), which is expandable to $500 million subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions.. Obligations under the WGP RCF are secured by a first priority lien on all of WGP’s assets (not including the consolidated assets of WES) as well as all equity interests owned by WGP. At September 30, 2017,2018, WGP had outstanding borrowings under its RCF of $28 million at an interest rate of 3.24%4.25%, classified as short-term debt on the Company’s Consolidated Balance Sheet, and had available borrowing capacity of $222$7 million. At September 30, 2018, WGP was in compliance with all covenants.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

11. Income Taxes

9. Upon enactment of the Tax Reform Legislation on December 22, 2017, the Company remeasured its U.S. deferred tax assets and liabilities based on the reduction of the U.S. corporate tax rate from 35% to 21%. During the third quarter of 2018, the Company recognized an additional net tax benefit of $5 million related to the adoption of the Tax Reform Legislation under Staff Accounting Bulletin 118. The Company expects to complete the accounting for the income tax effects related to the adoption of the Tax Reform Legislation, including its accounting policy related to Global Intangible Low Taxed Income, and record any remaining adjustments to provisional tax amounts, which could be material to income tax expense, before the end of the measurement period on December 21, 2018. See Note 13—Income Taxes

in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.
The following summarizes income tax expense (benefit) and effective tax rates:
Three Months Ended Nine Months Ended
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		September 30, September 30,
millions except percentages2017 2016 2017 20162018 2017 2018 2017
Current income tax expense (benefit)$430
 $64
 $670
 $212
$146
 $430
 $383
 $670
Deferred income tax expense (benefit)(855) (324) (1,036) (1,169)110
 (855) 124
 (1,036)
Total income tax expense (benefit)$(425) $(260) $(366) $(957)$256
 $(425) $507
 $(366)
Income (loss) before income taxes(1,066) (1,007) (1,616) (3,313)683
 (1,066) 1,125
 (1,616)
Effective tax rate40% 26% 23% 29%37% 40% 45% 23%

The Company’s tax provision for interim periods is determined using an estimate of its annual current and deferred effective tax rates, adjusted for discrete items. Each quarter, the Company updates these rates and records a cumulative adjustment to current and deferred tax expense by applying the rates to the year-to-date pre-tax income excluding discrete items. The Company’s quarterly estimate of its annual current and deferred effective tax rates can vary significantly based on various forecasted items, including future commodity prices, capital expenditures, expenses for which tax benefits are not recognized, and the geographic mix of pre-tax income and losses.
The variance from the U.S. federal statutory rate of 21% for the three and nine months ended September 30, 2018, was primarily attributable to the following items:
tax impact from foreign operations
non-deductible Algerian exceptional profits tax for Algerian income tax purposes
The Company reported a loss before income taxes for the three and nine months ended September 30, 2017 and 2016.2017. As a result, items that ordinarily increase or decrease the Company’s tax rate will have the opposite effect. The increasevariance from the 35% U.S. federal statutory rate of 35% for the three months ended September 30, 2017, was primarily attributable to the following:
tax impact from foreign operations
income attributable to noncontrolling interests
federal manufacturing deduction
These increases from the 35% U.S. federal statutory rate were partially offset by the following:
•non-deductible Algerian exceptional profits tax for Algerian income tax purposes
net changes in uncertain tax positions
The decrease from the 35% U.S. federal statutory rate for theand nine months ended September 30, 2017 was primarily attributable to the following:following items:
tax impact from foreign operations
non-deductible Algerian exceptional profits tax for Algerian income tax purposes
tax impact from foreign operations
net changes in uncertain tax positions
These decreases from the 35% U.S. federal statutory rate were partially offset by the following:
•income attributable to noncontrolling interests
•federal manufacturing deduction
The decrease from the 35% U.S. federal statutory rate for the three and nine months ended September 30, 2016, was primarily attributable to non-deductible Algerian exceptional profits tax for Algerian income tax purposes, the tax impact from foreign operations, non-deductible goodwill related to divestitures, and net changes in uncertain tax positions. These decreases were partially offset by increases to state taxes, net of federal benefit, and income attributable to noncontrolling interests. See Note 14—Noncontrolling Interests.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


11. Income Taxes (Continued)

The Company recognized a net tax benefit of $346 million as of September 30, 2018 and December 31, 2017, related to the deduction of its 2015 settlement payment for the Tronox Adversary Proceeding. This benefit is net of uncertain tax positions of $1.2 billion as of September 30, 2018 and December 31, 2017, due to uncertainty related to the deductibility of the settlement payment. Due to the deduction of the settlement payment, the Company had a net operating loss carryback for 2015, which resulted in a tentative tax refund of $881 million in 2016. The IRS has audited this position and, in April 2018, issued a final notice of proposed adjustment denying the deductibility of the settlement payment. In September 2018, the Company received a statutory notice of deficiency from the IRS disallowing the net operating loss carryback and rejecting the Company’s refund claim. As a result, the Company intends to file a petition with the U.S. Tax Court to dispute the disallowances, and pursuant to standard U.S. Tax Court procedures, the Company is not required to repay the $881 million refund to dispute the IRS’s position. Accordingly, the Company has not revised its estimate of the benefit that will ultimately be realized. After the case is tried and briefed in the Tax Court, the court will issue an opinion and then enter a decision. If the Company does not prevail on the issue, the earliest potential date the Company might be required to repay the refund received, plus interest, would be 91 days after entry of the decision. At such time, the Company would reverse the portion of the $346 million net benefit previously recognized in its consolidated financial statements to the extent necessary to reflect the result of the Tax Court decision. It is reasonably possible the amount of uncertain tax position and/or tax benefit could materially change as the Company asserts its position in the Tax Court proceedings. Although management cannot predict the timing of a final resolution of the Tax Court proceedings, the Company does not anticipate a decision to be entered within the next three years. 

10.12. Contingencies

Litigation  There are no material developments in previously reported contingencies nor are there any other material matters that have arisen since the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.2017.

11. Restructuring Charges

In the first quarter of 2016, the Company initiated a workforce reduction program to align the size and composition of its workforce with its expected future operating and capital plans. Employee notifications related to the workforce reduction program were completed by June 30, 2016. The Company recognized restructuring charges included in G&A in the Company’s Consolidated Statements of Income of $112 million during the three months ended September 30, 2016, and $363 million during the nine months ended September 30, 2016. All material restructuring charges were recognized in 2016, with the exception of settlement expense expected to be recognized during 2017 for lump-sum payments to terminated participants. During the nine months ended September 30, 2017, the Company recognized restructuring charges of $20 million, primarily related to settlement expense. Settlement expenses for the remainder of 2017 are not expected to be material.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


12.13. Pension Plans and Other Postretirement Benefits

The Company has contributory and non-contributory defined-benefit pension plans, which include both qualified and supplemental plans. The Company also provides certain health care and life insurance benefits for certain retired employees. Retiree health care benefits are funded by contributions from the retiree and, in certain circumstances, contributions from the Company. The Company’s retiree life insurance plan is noncontributory. The following summarizes the Company’s pension and other postretirement benefit cost:
Pension Benefits Other BenefitsPension Benefits Other Benefits
millions2017 2016 2017 20162018 2017 2018 2017
Three Months Ended September 30              
Service cost$22
 $24
 $—
 $1
$23
 $22
 $—
 $—
Interest cost21
 24
 3
 3
19
 21
 3
 3
Expected (return) loss on plan assets(21) (24) —
 —
(20) (21) —
 —
Amortization of net actuarial loss (gain)7
 12
 —
 —
6
 7
 —
 —
Amortization of net prior service cost (credit)(1) —
 (6) (6)—
 (1) (6) (6)
Settlement expense (1)
22
 102
 —
 —
Net periodic benefit cost$50
 $138
 $(3) $(2)
Settlement expense9
 22
 —
 —
Termination benefits expense7
 —
 —
 —
Net periodic benefit cost (1)
$44
 $50
 $(3) $(3)
              
Nine Months Ended September 30              
Service cost$64
 $73
 $1
 $2
$68
 $64
 $1
 $1
Interest cost63
 73
 9
 9
57
 63
 8
 9
Expected (return) loss on plan assets(63) (75) —
 —
(61) (63) —
 —
Amortization of net actuarial loss (gain)20
 30
 —
 —
19
 20
 —
 —
Amortization of net prior service cost (credit)(1) —
 (18) (18)—
 (1) (18) (18)
Settlement expense (1)
80
 126
 —
 —
Termination benefits expense (1)
4
 44
 —
 —
Curtailment expense (1)
—
 8
 —
 —
Net periodic benefit cost$167
 $279
 $(8) $(7)
Settlement expense9
 80
 —
 —
Termination benefits expense7
 4
 —
 —
Net periodic benefit cost (1)
$99
 $167
 $(9) $(8)

(1) 
Settlement expense, termination benefitsThe service cost component of net periodic benefit cost is included in G&A; oil and gas operating expense; gathering, processing, and marketing expense; and exploration expense, and curtailmentall other components of net periodic benefit cost are included in other (income) expense for 2016 relate toon the workforce reduction program. See Note 11—Restructuring Charges.
Company’s Consolidated Statements of Income.

The Company contributed $167$161 million to funded pension plans and $84$36 million to unfunded pension plans during the nine months ended September 30, 2017, and2018. The Company expects to contribute an additional $3$1 million to funded pension plans and $26 million to unfunded pension plans during 2017.2018.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


13.14. Stockholders’ Equity

Earnings Per Share  The Company’s basic earnings per share (EPS) is computed based on the average number of shares of common stock outstanding for the period and includes the effect of any participating securities and TEUs as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units, TEUs, and WES Series A Preferred units,TEUs, if the inclusion of these items is dilutive. All outstanding TEUs were settled in June 2018. See Note 9—Tangible Equity Units for additional information.
The following provides a reconciliation between basic and diluted EPS attributable to common stockholders:
Three Months Ended Nine Months Ended
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		September 30, September 30,
millions except per-share amounts2017 2016 2017 20162018 2017 2018 2017
Net income (loss)              
Net income (loss) attributable to common stockholders$(699) $(830) $(1,432) $(2,556)$363
 $(699) $513
 $(1,432)
Income (loss) effect of TEUs(2) (2) (6) (5)—
 (2) (4) (6)
Less distributions on participating securities—
 1
 —
 1
2
 —
 4
 —
Less undistributed income allocated to participating securities2
 —
 1
 —
Basic$(701) $(833) $(1,438) $(2,562)$359
 $(701) $504
 $(1,438)
Income (loss) effect of TEUs—
 —
 (1) (1)—
 —
 —
 (1)
Diluted$(701) $(833) $(1,439) $(2,563)$359
 $(701) $504
 $(1,439)
Shares              
Average number of common shares outstanding—basic553
 517
 552
 512
499
 553
 507
 552
Dilutive effect of stock options1
 —
 1
 —
Average number of common shares outstanding—diluted553
 517
 552
 512
500
 553
 508
 552
Excluded due to anti-dilutive effect11
 11
 11
 11
8
 11
 9
 11
Net income (loss) per common share              
Basic$(1.27) $(1.61) $(2.60) $(5.00)$0.72
 $(1.27) $0.99
 $(2.60)
Diluted$(1.27) $(1.61) $(2.61) $(5.00)$0.72
 $(1.27) $0.99
 $(2.61)




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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

14. Stockholders’ Equity (Continued)

Common Stock  Repurchase Program In September 2017, theThe Company announced a $2.5 billion share-repurchaseShare-Repurchase Program in September 2017, which was expanded to $3.0 billion in February 2018. In July 2018, the program under which shareswas further expanded to $4.0 billion and extended through June 30, 2019. The Share-Repurchase Program authorizes the repurchase of the Company’s common stock may be repurchased either in the open market or through private transactions. The program is authorized to extend throughAs of the end of 2018. In October 2017, Anadarko entered into an accelerated share-repurchase agreement (ASR Agreement) with an investment bank (Bank) to repurchase $1.0the third quarter of 2018, the Company had completed $3.5 billion of the Company’sShare-Repurchase Program through ASR Agreements and open-market repurchases. These transactions were accounted for as equity transactions, with all of the repurchased shares classified as treasury stock. Additionally, the receipt of these shares reduced the average number of shares of common stock outstanding used to compute both basic and diluted EPS.
During the nine months ended September 30, 2018, the Company entered into and completed two ASR Agreements and open-market repurchases as part of the share-repurchase program. presented below:
millions except per-share amounts        
Agreement Date Settlement Date Amount Average Price per Share Initial Shares Delivered Additional Shares Delivered Total Shares Delivered
ASR Agreements            
January 2018 February 2018 $500
 $58.82
 7.0
 1.5
 8.5
March 2018 June 2018 1,441
 65.28
 19.1
 3.0
 22.1
Total ASR Agreements   1,941
   26.1
 4.5
 30.6
Open-market repurchases 
 
 

 

 

 

August 2018 August 2018 250
 66.14
 N/A
 N/A
 3.8
September 2018 September 2018 250
 63.11
 N/A
 N/A
 3.9
Total open-market repurchases   500
       7.7
Total   $2,441
       38.3

Under the terms of theeach ASR Agreement, the Company paid $1.0 billiona specific amount in cash and received an initial delivery of shares of the Company’s common stock. AtThe initial delivery of shares represented the conclusionminimum number of shares to be repurchased under the termagreement. The final number of theshares delivered upon settlement of each ASR Agreement the Company and the Bank will enter into a final share settlementwas determined with the settlement price determined by applying a percentage discountreference to the volume-weighted average price of the shares during the term. The ASR Agreement is subject to customary adjustment and termination provisions, and final settlement is expected to occur prior to year end. Allterm of the shares acquired by Anadarko under the ASR Agreement will be classified as treasury stock.agreement less a negotiated settlement price adjustment.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


14.15. Noncontrolling Interests

WES is a limited partnership formed by Anadarko to acquire, own, develop, and operate midstream assets. During 2016, WES issued 22 million Series A Preferred units to private investors for net proceeds of $687 million and issued 1.3 million common units to the Company. Proceeds from these issuances were primarily used to acquire interests in Springfield Pipeline LLC from the Company.investors. Pursuant to an agreement between WES and the holders of the Series A Preferred units, 50% of the Series A Preferred units converted into WES common units on a one-for-one basis on March 1, 2017, and theall remaining Series A Preferred units were converted on May 2, 2017.
WES Class C units issued to Anadarko will convert into WES common units on a one-for-one basis on the conversion date, which was extended in February 2017 from December 31, 2017, to March 1, 2020. The Class C units receive quarterly distributions in the form of additional Class C units until the March 1, 2020 conversion date, unless WES elects to convert the units to common units earlier or Anadarko elects to extend the conversion date. WES distributed 620802 thousand Class C units to Anadarko during the nine months ended September 30, 2017,2018, and 946886 thousand Class C units to Anadarko during 2016.2017.
WGP is a limited partnership formed by Anadarko to own interests in WES. During 2016,In June 2018, Anadarko sold 12.5settled 9.2 million outstanding TEUs, originally issued in 2015, in exchange for approximately 8.2 million WGP common units to the public units. See Note 9—Tangible Equity Unitsfor net proceeds of $476 million.additional information. At September 30, 2017,2018, Anadarko’s ownership interest in WGP consisted of an 81.6%a 77.8% limited partner interest and the entire non-economic general partner interest. The remaining 18.4%22.2% limited partner interest in WGP was owned by the public.
At September 30, 2017,2018, WGP’s ownership interest in WES consisted of a 29.8%29.6% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At September 30, 2017,2018, Anadarko also owned a 9.0%9.5% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 59.7%59.4% limited partner interest in WES was owned by the public.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


15.16. Variable Interest Entities

Consolidated VIEs The Company determined that the partners in WGP and WES with equity at risk lack the power, through voting rights or similar rights, to direct the activities that most significantly impact WGP’s and WES’s economic performance; therefore, WGP and WES are considered VIEs. Anadarko, through its ownership of the general partner interest in WGP, has the power to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to WGP and WES; therefore, Anadarko is considered the primary beneficiary and consolidates WGP, WES, and all of their consolidated subsidiaries. See Note 14—Noncontrolling InterestsforFor additional information on WGP and WES.WES, see Note 15—Noncontrolling Interests.
The following tables present selected financial data from the consolidated financial statements of WGP:

Three Months Ended Nine Months Ended
 September 30, September 30,
millions2018 2017 2018
2017
Statement of Operations Data       
Total revenues and other$508
 $575
 $1,432
 $1,616
Operating income (loss)200
 179
 461
 523
Net income (loss)155
 147
 340
 424

 Nine Months Ended
 September 30,
millions2018 2017
Statement of Cash Flows Data   
Net cash provided by (used in) operating activities$749
 $642
Net cash provided by (used in) investing activities(1,161) (515)
Net cash provided by (used in) financing activities465
 (334)

 September 30, December 31,
millions2018 2017
Balance Sheet Data   
Cash and cash equivalents$133
 $80
Net property, plant, and equipment6,419
 5,731
Total assets9,034
 8,016
Long-term debt4,566
 3,493
Total liabilities5,417
 4,071
Total equity and partners’ capital3,617
 3,945

Assets and Liabilities of VIEs The assets of WGP, WES, and their subsidiaries cannot be used by Anadarko for general corporate purposes and are included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets. The carrying amounts of liabilities related to WGP, WES, and their subsidiaries for which the creditors do not have recourse to other assets of the Company are included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets.
All outstanding debt for WES at September 30, 2017,2018, and December 31, 2016,2017, including any borrowings under the WES RCF, is recourse to WES’s general partner, which in turn has been indemnified in certain circumstances by certain wholly owned subsidiaries of the Company for such liabilities. All outstanding debt for WGP at September 30, 2017,2018, and December 31, 2016,2017, including any borrowings under the WGP RCF, is recourse to WGP’s general partner, which is a wholly owned subsidiary of the Company. See Note 8—10—Debt for additional information on WGP and WES short-term and long-term debt balances.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

16. Variable Interest Entities (Continued)

VIE Financing WGP’s sources of liquidity include borrowings under its RCF and distributions from WES. WES’s sources of liquidity include cash and cash equivalents, cash flows generated from operations, interest income from a note receivable from Anadarko as discussed below, borrowings under its RCF, the issuance of additional partnership units, orand debt offerings. See Note 8—10—Debt and Note 14—15—Noncontrolling Interests for additional information on WGP and WES financing activity.

Financial Support Provided to VIEs Concurrent with the closing of its May 2008 IPO, WES loaned the Company $260 million in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The related interest income for WES was $5 million for each of the three months ended September 30, 2017 and 2016, and $13 million for each of the nine months ended September 30, 20172018 and 2016.2017. The note receivable and related interest income are eliminated in consolidation.
In March 2015, WES acquired the Company’s interest in DBJV. The acquisition was financed using a deferred purchase price obligation that required a cash payment from WES to the Company due on March 31, 2020. In May 2017, WES reached an agreement with the Company to settle this obligation whereby WES made a cash payment to the Company of $37 million, equal to the estimated net present value of the obligation at March 31, 2017.
In order toTo reduce WES’s exposure to a majority of the commodity-price risk inherent in certain of its contracts, Anadarko has commodity price swap agreements in place with WES expiring on December 31, 2017.2018. WES has recorded a capital contribution from Anadarko in its Consolidated Statement of Equity and Partners’ Capital for an amount equal to (i) the amount by which the swap price for product sales exceeds the applicable market price, minus (ii) the amount by which the swap price for product purchases exceeds the market price. WES recorded a capital contribution from Anadarko of $41 million for the nine months ended September 30, 2018, and $47 million for the nine months ended September 30, 2017, and $35 million for the nine months ended September 30, 2016.2017.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


16.17. Supplemental Cash Flow Information

Additions to properties and equipment as presented within Anadarko’s cash flows from investing activities include cash payments for cost of properties, equipment, and facilities. The cost of properties includes the initial capitalization of drilling costs associated with all exploratory wells whether or not they were deemed to have a commercially sufficient quantity of proved reserves.
The following summarizes cash paid (received) for interest and income taxes as well as non-cash investing and financing activities:
Nine Months Ended
Nine Months Ended 
 September 30,		September 30,
millions2017 20162018 2017
Cash paid (received)      
Interest, net of amounts capitalized$764
 $735
$813
 $764
Income taxes, net of refunds (1)
169
 (878)
Income taxes, net of refunds48
 169
Non-cash investing activities      
Fair value of properties and equipment from non-cash transactions$619
 $2
Fair value of properties and equipment acquired$8
 $619
Asset retirement cost additions228
 85
261
 228
Accruals of property, plant, and equipment786
 454
886
 786
Net liabilities assumed (divested) in acquisitions and divestitures(115) (39)(97) (115)
Non-cash investing and financing activities      
Capital lease obligation (2)
$—
 $10
FPSO construction period obligation (2)
—
 11
Deferred drilling lease liability14
 3
$—
 $14
Non-cash financing activities   
Settlement of tangible equity units$300
 $—

(1)
Includes $881 million from a tax refund in 2016 related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback.
(2)
Upon completion of the FPSO in the third quarter of 2016, the Company reported the construction period obligation as a capital lease obligation based on the fair value of the FPSO.
 
The following table provides a reconciliation of Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents as reported in the Consolidated Statement of Cash Flows to the line items within the Consolidated Balance Sheets:
17. Segment Information
 September 30, December 31,
millions2018 2017
Cash and cash equivalents$1,883
 $4,553
Restricted cash and restricted cash equivalents included in Other Assets110
 121
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents$1,993
 $4,674

Anadarko’s business segmentsIncluded in cash and cash equivalents is restricted cash and restricted cash equivalents of $134 million at September 30, 2018, and $255 million at December 31, 2017. Total restricted cash and restricted cash equivalents are separately managed dueprimarily associated with certain international joint venture operations, payments of future hard-minerals royalty revenues conveyed, like-kind exchanges of property, and a judicially-controlled account related to distinct operational differences. Anadarko has previously presented three reporting segments in its quarterly and annual filings: Oil and Gas Exploration and Production, Midstream, and Marketing. In the first half of 2017, Anadarko substantially completed a repositioning of its asset portfolio to focus on higher margin liquids production. This shift resulted in a substantial decreaseBrazilian tax dispute. See Note 17—Contingencies in the number of U.S. operating areas. Following the portfolio repositioning, the chief operating decision maker reviews operating results for Exploration and Production and Midstream when making operating and capital allocation decisions. Accordingly, Anadarko no longer identifies marketing activities as a separate reporting segment and has two reporting segments, Exploration and Production and Midstream, which include their respective marketing results. The Company has reclassified prior period amounts to conform to the current period’s presentation.
The Exploration and Production reporting segment explores for, produces, and sells oil, natural gas, and NGLs and plansCompany’s Annual Report on Form 10-K for the development and operation of the Company’s LNG project in Mozambique. The Midstream reporting segment engages in gathering, processing, treating, and transporting Anadarko and third-party oil, natural-gas, and NGLs production as well as gathering and disposal of produced water. The Midstream reporting segment consists of two operating segments, WES and Other Midstream, which are aggregated into one reporting segment due to similar financial and operating characteristics.year ended December 31, 2017.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


17.18. Segment Information (Continued)

Anadarko’s business segments are separately managed due to distinct operational differences. Anadarko has three reporting segments: Exploration and Production, WES Midstream, and Other Midstream, which include their respective marketing results. The Company has reclassified prior-period amounts to conform to the current-period presentation.
The Exploration and Production reporting segment is engaged in the exploration, development, production, and sale of oil, natural gas, and NGLs and in advancing its Mozambique LNG project toward FID. The WES Midstream and Other Midstream reporting segments engage in gathering, compressing, treating, processing, and transporting of natural gas; gathering, stabilizing, and transporting of oil and NGLs; and gathering and disposing of produced water. The WES Midstream segment consists of WES midstream assets, and the Other Midstream segment consists of the Company’s other midstream assets.
To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes; interest expense; DD&A; exploration expense; gains (losses) on divestitures, net; impairments; total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives; restructuring charges; and certain items not related to the Company’s normal operations, less net income (loss) attributable to noncontrolling interests. During the periods presented, items not related to the Company’s normal operations included restructuring charges related to the workforce reduction program included in G&A, loss on early extinguishment of debt, and certain other nonoperating items included in other (income) expense, net.
The Company’s definition of Adjusted EBITDAX excludes gains (losses) on divestitures, net and exploration expense as they are not indicators of operating efficiency for a given reporting period. DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Finally, net income (loss) attributable to noncontrolling interests is excluded from the Company’s measure of Adjusted EBITDAX because it represents earnings that are not attributable to the Company’s common stockholders.
Management believes Adjusted EBITDAX provides information useful in assessing the Company’s operating and financial performance across periods. Adjusted EBITDAX as defined by Anadarko may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures, such as operating income. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes:
Three Months Ended Nine Months Ended
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		September 30, September 30,
millions2017 2016 2017 20162018 2017 2018 2017
Income (loss) before income taxes$(1,066) $(1,007) $(1,616) $(3,313)$683
 $(1,066) $1,125
 $(1,616)
Interest expense230
 220
 680
 657
240
 230
 705
 682
DD&A1,083
 1,069
 3,235
 3,202
1,130
 1,083
 3,123
 3,235
Exploration expense751
 304
 2,371
 506
Exploration expense (1)
118
 750
 380
 2,366
(Gains) losses on divestitures, net194
 414
 (815) 516
(3) 194
 (31) (815)
Impairments—
 27
 383
 61
172
 —
 319
 383
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives98
 88
 (12) 863
(167) 98
 73
 (12)
Restructuring charges3
 112
 20
 363
13
 3
 13
 20
Other operating expense—
 —
 —
 1
Loss on early extinguishment of debt—
 —
 2
 124
Certain other nonoperating items—
 —
 —
 (56)
Less net income (loss) attributable to noncontrolling interests58
 83
 182
 200
64
 58
 105
 182
Consolidated Adjusted EBITDAX$1,235
 $1,144
 $4,066
 $2,724
$2,122
 $1,234
 $5,602
 $4,061
 __________________________________________________________________
(1)
Includes restructuring charges of $20 million for the three and nine months ended September 30, 2018.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


17.18. Segment Information (Continued)

Information presented below as “Other and Intersegment Eliminations” includes corporate costs, margin on sales of third-party commodity purchases, deficiency fees,fee expenses, results from hard-minerals royalties, net cash from settlement of commodity derivatives, and net income (loss) attributable to noncontrolling interests. The following summarizes selected financial information for Anadarko’s reporting segments:
millions
Exploration
& Production
 Midstream 
Other and
Intersegment
Eliminations
 Total
Exploration
& Production
 WES Midstream Other Midstream 
Other and
Intersegment
Eliminations
 Total
Three Months Ended September 30, 2017       
Three Months Ended September 30, 2018         
Sales revenues$2,101
 $496
 $13
 $2,610
$3,161
 $394
 $39
 $13
 $3,607
Intersegment revenues—
 158
 (158) —
25
 114
 78
 (217) —
Other (1)
6
 39
 35
 80
1
 52
 11
 23
 87
Total revenues and other (2)(1)
2,107
 693
 (110) 2,690
3,187
 560
 128
 (181) 3,694
Operating costs and expenses (3)(2)
959
 391
 84
 1,434
1,059
 245
 55
 (67) 1,292
Net cash from settlement of commodity derivatives—
 —
 (16) (16)—
 —
 —
 199
 199
Other (income) expense, net(3)—
 —
 (21) (21)—
 —
 —
 17
 17
Net income (loss) attributable to noncontrolling interests(1)
—
 —
 58
 58
—
 —
 —
 64
 64
Total expenses and other959
 391
 105
 1,455
1,059
 245
 55
 213
 1,572
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement—
 —
 —
 —
 —
Adjusted EBITDAX$1,148
 $302
 $(215) $1,235
$2,128
 $315
 $73
 $(394) $2,122
                
Three Months Ended September 30, 2016       
Three Months Ended September 30, 2017         
Sales revenues$1,901
 $329
 $21
 $2,251
$2,097
 $445
 $53
 $15
 $2,610
Intersegment revenues—
 227
 (227) —
4
 119
 43
 (166) —
Other (1)
(2) 35
 23
 56
Total revenues and other (2)
1,899
 591
 (183) 2,307
Operating costs and expenses (3)
877
 284
 13
 1,174
Other6
 39
 7
 28
 80
Total revenues and other (1)
2,107
 603
 103
 (123) 2,690
Operating costs and expenses (2)
956
 345
 62
 49
 1,412
Net cash from settlement of commodity derivatives—
 —
 (63) (63)—
 —
 —
 (16) (16)
Other (income) expense, net—
 —
 (31) (31)—
 —
 —
 2
 2
Net income (loss) attributable to noncontrolling interests(1)
—
 —
 83
 83
Net income (loss) attributable to noncontrolling interests—
 —
 —
 58
 58
Total expenses and other877
 284
 2
 1,163
956
 345
 62
 93
 1,456
Adjusted EBITDAX$1,022
 $307
 $(185) $1,144
$1,151
 $258
 $41
 $(216) $1,234
 __________________________________________________________________
(1)
Presentation has been adjusted to align with the current analysis of segment performance. Net income (loss) attributable to noncontrolling interests, previously reported within the Midstream segment, is now presented within Other and Intersegment Eliminations. Other revenues, previously reported within Other and Intersegment Eliminations, is now presented within the applicable segments.
(2) 
Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.
(3)(2) 
Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX.
(3)
Other (income) expense, net excludes restructuring charges since these expenses are excluded from Adjusted EBITDAX.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


17.18. Segment Information (Continued)

millions
Exploration
& Production
 Midstream 
Other and
Intersegment
Eliminations
 Total
Exploration
& Production
 WES Midstream Other Midstream 
Other and
Intersegment
Eliminations
 Total
Nine Months Ended September 30, 2017       
Nine Months Ended September 30, 2018         
Sales revenues$6,510
 $1,346
 $71
 $7,927
$8,589
 $1,063
 $73
 $76
 $9,801
Intersegment revenues—
 507
 (507) —
49
 369
 188
 (606) —
Other (1)
16
 126
 95
 237
Total revenues and other (2)
6,526
 1,979
 (341) 8,164
Operating costs and expenses (3)
2,687
 1,063
 230
 3,980
Other(5) 113
 30
 63
 201
Total revenues and other (1)
8,633
 1,545
 291
 (467) 10,002
Operating costs and expenses (2)
2,840
 687
 134
 195
 3,856
Net cash from settlement of commodity derivatives—
 —
 (23) (23)—
 —
 —
 437
 437
Other (income) expense, net—
 —
 (43) (43)
Net income (loss) attributable to noncontrolling interests(1)
—
 —
 182
 182
Other (income) expense, net (3)
—
 —
 —
 9
 9
Net income (loss) attributable to noncontrolling interests—
 —
 —
 105
 105
Total expenses and other2,687
 1,063
 346
 4,096
2,840
 687
 134
 746
 4,407
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement—
 —
 (2) (2)—
 —
 —
 7
 7
Adjusted EBITDAX$3,839
 $916
 $(689) $4,066
$5,793
 $858
 $157
 $(1,206) $5,602
                
Nine Months Ended September 30, 2016       
Nine Months Ended September 30, 2017         
Sales revenues$4,975

$823

$72

$5,870
$6,500

$1,213
 $134
 $80

$7,927
Intersegment revenues—

671

(671)
—
10

387
 125
 (522)
—
Other (1)
(17)
76

69

128
Total revenues and other (2)
4,958

1,570

(530)
5,998
Operating costs and expenses (3)
2,586

714

38

3,338
Other16

124
 20
 77

237
Total revenues and other (1)
6,526

1,724
 279
 (365)
8,164
Operating costs and expenses (2)
2,679

936
 168
 135

3,918
Net cash from settlement of commodity derivatives—

—

(226)
(226)—

—
 —
 (23)
(23)
Other (income) expense, net—

—

(30)
(30)—

—
 —
 24

24
Net income (loss) attributable to noncontrolling interests (1)
—

—

200

200
Net income (loss) attributable to noncontrolling interests—

—
 —
 182

182
Total expenses and other2,586

714

(18)
3,282
2,679

936
 168
 318

4,101
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement—

—

8

8
—

—
 —
 (2)
(2)
Adjusted EBITDAX$2,372

$856

$(504)
$2,724
$3,847

$788
 $111
 $(685)
$4,061
 __________________________________________________________________
(1)
Presentation has been adjusted to align with the current analysis of segment performance. Net income (loss) attributable to noncontrolling interests, previously reported within the Midstream segment, is now presented within Other and Intersegment Eliminations. Other revenues, previously reported within Other and Intersegment Eliminations, is now presented within the applicable segments.
(2) 
Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.
(3)(2) 
Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX.
(3)
Other (income) expense, net excludes restructuring charges since these expenses are excluded from Adjusted EBITDAX.



Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. The Company has made in this Form 10-Q, and may from time to time make in other public filings, press releases, and management discussions, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, concerning the Company’s operations, economic performance, and financial condition. These forward-looking statements include, among other things, information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include those statements preceded by, followed by, or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” “would,” “will,” “potential,” “continue,” “forecast,” “future,” “likely,” “outlook,” or similar expressions or variations on such expressions. For such statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will be realized. Anadarko undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events, or otherwise.

These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the following risks and uncertainties:

the Company’s assumptions about energy markets
production and sales volume levels
levels of oil, natural-gas, and NGLs reserves
operating results
competitive conditions
technology
availability of capital resources, levels of capital expenditures, and other contractual obligations
supply and demand for, the price of, and the commercialization and transporting of oil, natural gas, NGLs, and other products or services
volatility in the commodity-futures market
weather
inflation
availability of goods and services, including unexpected changes in costs
drilling and other operational risks
processing volumes, and pipeline throughput, and produced water disposal
general economic conditions, nationally, internationally, or in the jurisdictions in which the Company is, or in the future may be, doing business
the Company’s inability to timely obtain or maintain permits or other governmental approvals, including those necessary for drilling and/or development projects
legislative or regulatory changes, including changes relating to hydraulic fracturing;fracturing or other oil and natural-gas operations; retroactive royalty or production tax regimes; deepwater drilling and permitting regulations; derivatives reform; changes in state, federal, and foreign income taxes; environmental regulation, including regulations related to climate change; environmental risks; and liability under international, provincial, federal, regional, state, tribal, local, and foreign environmental laws and regulations
civil or political unrest or acts of terrorism in a region or country

the creditworthiness and performance of the Company’s counterparties, including financial institutions, operating partners, and other parties
volatility in the securities, capital, or credit markets and related risks such as general credit, liquidity, and interest-rate risk
the Company’s ability to successfully monetize select assets, repurchase shares of common stock, repay or refinance its debt, meet its debt-reduction expectations, and the impact of changes in the Company’s credit ratings
the Company’s ability to successfully complete its Share-Repurchase Program
the Company’s ability to successfully plan, secure additional government approvals, enter into additional long-term sales contracts, take FID and the timing thereof, finance, build, and operate the necessary infrastructure and LNG park in Mozambique
uncertainties and liabilities associated with acquired and divested properties and businesses
disruptions in international oil and NGLs cargo shipping activities
physical, digital, internal, and external security breaches
supply and demand, technological, political, governmental, and commercial conditions associated with long-term development and production projects in domestic and international locations
the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigation by the NTSB related to ourthe Company’s operations in Colorado, and continued or additional disruptions in operations that may occur as the Company complies with regulatory orders or other state or local changes in laws or regulations in Colorado
other factors discussed below and elsewhere in “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016,2017, this Form 10-Q, and in the Company’s other public filings, press releases, and discussions with Company management
The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Form 10-Q in Part I, Item 1; the information set forth in the Risk Factors under Part II, Item 1A; the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Part II, Item 8 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2016;2017; and the information set forth in the Risk Factors under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.2017.


MANAGEMENT OVERVIEW

Anadarko’s strategy is to explore for, develop, and commercialize resources globally; ensure health, safety, and environmental excellence; and focus on financial discipline, flexibility, and value creation; and demonstratewhile demonstrating the Company’s core values in all its business activities. The Company’s revenues, operating results, cash flows from operations, capital spending, and future growth rates are highly influenced bydependent on commodity prices, which affectdetermine the value the Company receives from its sales of oil, natural gas, and NGLs.
To effectively manage the influence of potential commodity-price volatility, in 2017, AnadarkoThe Company continues to optimizeleverage its foundational principle of efficient capital allocation to generate attractive returns on, and further concentrateof, capital while investing within cash flow. Anadarko also continues to focus on cash-margin improvement and has actively managed its portfolio to focus on higher-return, oil-levered opportunities in areas where it possesses both scale and competitive advantages, namely in the Delaware and DJ basins in the U.S. onshore and in the deepwater Gulf of Mexico. Anadarko’s deepwaterThe Company expects to use excess cash generated from its Gulf of Mexico, assets are expected to generate substantial cash flows over the next five years at current strip prices. The Company plans to use the cash flows from the Gulf of Mexico as well as from its international producingAlgeria, Ghana, and DJ basin assets to fund activity in the Company’sgrowth of its other unconventional assets in the U.S. onshore. Muchonshore and improve returns to shareholders.
In the third quarter of 2018, the Company expanded the Share-Repurchase Program from $3.0 billion to $4.0 billion and completed the repurchase of $500 million of the 2017 operationalCompany’s common stock, bringing the total repurchases to $3.5 billion. The Company also announced a $500 million increase to its debt-reduction expectations, bringing the total planned debt reduction to $1.5 billion. As of September 30, 2018, the Company had repaid $114 million of debt at maturity and investment focus is preparingplans to retire $900 million of fixed-rate debt maturing in the first half of 2019. These actions demonstrate the strength of the Company’s portfolio and commitment to capital efficiency.
In the Delaware basin, located in Texas, the Company continues to build out one of the most expansive and integrated infrastructure positions in the region and is transitioning to multi-well pad development, primarily in Reeves and Loving counties. The first ROTF in Reeves County was completed and brought online during the second quarter of 2018. During the third quarter of 2018, final commissioning activities were completed for developmentthe second ROTF in Loving County. New wells in the area were brought online and flowed into these ROTFs during the third quarter of 2018. Additionally, the WES-operated Mentone I processing train at the DBM Complex is expected to commence operations in the fourth quarter of 2018, which will facilitate incremental production growth of the asset. As of the end of the third quarter of 2018, Anadarko had secured sufficient takeaway capacity with increased operatorship and infrastructureapproximately 50% of its Delaware basin operated oil volumes being sold at Gulf Coast markets via the Enterprise pipeline to facilitate long-term growth and value.Houston. This capacity is expected to increase to approximately 100% in 2019, when the Plains Cactus II pipeline to Corpus Christi is brought online. The Company ended the third quarter of 20172018 with 7 operated drilling rigs and 5 completion crews in the Delaware basin, which compares to 13 operated drilling rigs in the Delaware basin and 6 completion crews at the end of the third quarter of 2017.
In the DJ basin, located in Colorado, the Company continues to leverage its minerals-interest ownership and extensive infrastructure position to deliver development wells with attractive rates of return. The Company ended the third quarter of 2018 with four operated drilling rigs and two completion crews in the DJ basin, which compares to 9six operated drilling rigs and four completion crews at the end of the third quarter of 2017. The Colorado general election ballot in November 2018 will include Proposition 112, which, if passed, would amend the Colorado Revised Statutes to require that new oil and gas development on non-federal lands take place a minimum distance of 2,500 feet from occupied buildings such as homes, schools, and hospitals, and other areas designated as vulnerable. Such setbacks would effectively ban new oil and gas drilling and hydraulic fracturing on a substantial portion of Colorado’s non-federal lands. If Proposition 112 passes, and is not amended or repealed by the state legislature, resulting in more stringent limitations on the production and development of oil and natural gas in Colorado, the Company will be limited or precluded in the drilling of wells or in the volumes that are ultimately able to be produced from assets in Colorado. Given the depth and quality of the Company’s portfolio, if this occurs, the Company would expect to reallocate capital in order to continue to focus on higher-return, oil-levered opportunities in areas where it possesses both scale and competitive advantages, namely in the Delaware basin and 5 operated drilling rigs in the DJ basin at year end 2016. deepwater Gulf of Mexico, and accelerate investments in the emerging oil play in Wyoming’s Powder River basin.
In the deepwater Gulf of Mexico, Anadarko has threetwo floating rigs drilling with a focus on leveragingdrillships and one platform rig available to conduct operations that are focused toward high-return oil development opportunities near the Company’s expansive infrastructure position.infrastructure. Internationally, drilling continues in offshore Ghana with new development activities at the TEN and Jubilee fields.
In September 2017,order to reduce commodity-price risk and increase the predictability of 2018 cash flows, the Company announced a $2.5 billion share-repurchase program under which shareshas strategic derivative positions covering approximately 50% of its anticipated oil sales volumes and approximately 55% of its anticipated natural-gas sales volumes for the Company’s common stock may be repurchased eitherremainder of 2018. See Note 8—Derivative Instruments in the open market or through private transactions. The program is authorizedNotes to extend through the endConsolidated Financial Statements under Part I, Item 1 of 2018. In October 2017, the Company entered into an agreement to complete $1.0 billion of the share-repurchase program prior to the end of 2017.
Following a home explosion in Firestone, Colorado in April 2017, the Company took precautionary measures to shut in all operated vertical wells in the DJ basin to conduct additional inspections. It subsequently tested and permanently plugged, abandoned, and capped all one-inch return lines associated with these wells. In May 2017, the Colorado Oil & Gas Conservation Commission (COGCC) issued a two-phase Notice to Operators (NTO) requiring all operators to inventory and integrity test existing flowlines within 1,000 feet of a building unit and abandon all inactive flowlines in such areas. During the third quarter, the Company substantially completed the requirements of the NTO. In August 2017, following a three-month review of oil and gas operations, the Governor of Colorado announced several policy initiatives designed to enhance public safety, which are to be implemented over the next several months through rulemaking or legislation. The Company continues to work cooperatively with state regulators and others and is also cooperating with the NTSB in its investigation related to the incident.this Form 10-Q.

Significant operating and financial activities for the third quarter of 20172018 include the following:

Total Company
Anadarko’sThe Company’s overall sales-volume product mix increased to 57%58% oil in the third quarter of 2017,2018, compared to 42%56% in the third quarter of 2016, which significantly improved margins and returns.2017.
Anadarko’sThe Company’s third-quarter oil sales volumes averaged 353397 MBbls/d, representing an 11%a 13% increase over the third quarter of 2017.
U.S. Onshore
U.S. onshore oil sales volumes increased by 35 MBbls/d, representing a 26% increase from the third quarter of 2016, primarily due to increased2017.
Sales volumes from the Gulf of Mexico, partially offset by the divestiture of certain U.S. onshore oil and gas assets in 2016 and 2017.
U.S. Onshore
Oil sales volumes infor the Delaware basin increased by 1032 MBbls/d, representing a 40%an 83% increase from the third quarter of 2016,2017, primarily due to continued drilling and completion activities.activities and midstream infrastructure additions in 2018.
GulfIn the Delaware basin, the second ROTF was completed in Loving County, with 47 wells flowing into the facility by the end of Mexicothe third quarter. Additionally, 23 new wells were brought online at the Reeves County ROTF during the quarter.
Oil sales volumes averaged 126 MBbls/d, representingInternational
Ghana
In the TEN fields of Ghana, the operator resumed drilling operations in early 2018, with one well completed and brought online in the third quarter. Subsequent to quarter end, drilling began on a 95% increase fromsecond well.
In the Jubilee field of Ghana, the operator drilled two wells during the second quarter of 2018, with the first of these wells completed and brought online in the third quarter.
At the end of the third quarter, of 2016, primarily due toa second drillship was mobilized for drilling operations in the GOM AcquisitionTEN and continued tieback activity at several facilities, partially offset by deferred production as a result of Hurricanes Harvey and Irma during the third quarter of 2017.Jubilee fields.

InternationalMozambique
The International TribunalCompany continues to make progress converting non-binding commitments to fully termed Sales and Purchase Agreements as required to support project financing arrangements and progress to FID.
Recommendations for the Lawaward of the Sea issued a ruling in September 2017 regarding the delimitation of the maritime boundary between Ghanaoffshore contractor and Côte d’Ivoire in the Atlantic Ocean. The new maritime boundary as determined by the tribunal does not affect the TEN fields, and the operator now plans to work with theequipment providers are awaiting Government of Ghana to put in place the permits necessary to resume development drilling.Mozambique approval.
Interim spread mooring of the FPSOSite preparation activities are fully underway at the Jubilee field in Ghana commenced inAfungi onshore site, as major infrastructure and resettlement projects are proceeding as planned, positioning the fourth quarter of 2016 and was completed during the first quarter of 2017. Anadarko continues to work with its partners to optimize a permanent turret solution that will effectively stabilize the vessel with a minimum amount of shut-in time, which is expected to start in early 2018. In October, the partnership received Ghanaian Government approval for the full-field plan of development, with drilling operations expected to commence in 2018.
The foundational legal and contractual framework was completed for the Company’s onshore LNG project in Mozambique. A few formal government approvals remain before the commencement of resettlement and site preparation activities, which will position the onshore area for construction of the LNG facilities.
Anadarko and its co-venturers inIn the third quarter, Offshore Area 14, which is owned and operated by third parties, joined the Anadarko-led resettlement and airstrip projects as a 50% participant.
The Company remains on track for FID consideration in Mozambique reached agreement on the project’s first long-term sale and purchase agreement (SPA) for 2.6 million tonnes per annum with PTT Public Company Limited (PTT), Thailand’s national oil and gas company. The SPA is subject to the approvalhalf of the Government of Thailand.2019.
Financial
The Company generated $639 million$1.6 billion of cash flowflows from operations and ended the third quarter with $5.3$1.9 billion of cash.
In September 2017, Anadarko announced a $2.5 billion share-repurchase program. In October 2017,the third quarter, the Company entered intocompleted the repurchase of an ASR Agreement to complete $1.0 billionadditional $500 million of the share-repurchase program prior toCompany’s common stock under the end of 2017.Share-Repurchase Program.


FINANCIAL RESULTS
 Three Months Ended Nine Months Ended
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		 September 30, September 30,
millions except per-share amounts 2017 2016 2017 2016 2018 2017 2018 2017
Oil, natural-gas, and NGLs sales $2,101
 $1,901
 $6,510
 $4,975
 $3,186
 $2,101
 $8,638
 $6,510
Gathering, processing, and marketing sales 509
 350
 1,417
 895
 421
 509
 1,163
 1,417
Gains (losses) on divestitures and other, net (114) (358) 1,052
 (388) 90
 (114) 232
 1,052
Revenues and other $2,496
 $1,893
 $8,979
 $5,482
 $3,697
 $2,496
 $10,033
 $8,979
Costs and expenses 3,271
 2,686
 9,989
 7,471
 2,718
 3,245
 7,684
 9,895
Other (income) expense 291
 214
 606
 1,324
 296
 317
 1,224
 700
Income tax expense (benefit) (425) (260) (366) (957) 256
 (425) 507
 (366)
Net income (loss) attributable to common stockholders $(699) $(830) $(1,432) $(2,556) $363
 $(699) $513
 $(1,432)
Net income (loss) per common share attributable to common stockholders—diluted $(1.27) $(1.61) $(2.61) $(5.00) $0.72
 $(1.27) $0.99
 $(2.61)
Average number of common shares outstanding—diluted 553
 517
 552
 512
 500
 553
 508
 552

The following discussion pertains to Anadarko’s results of operations, financial condition, and changes in financial condition. IncreasesAny increases or decreases “for the three months ended September 30, 2017,2018,” refer to the comparison of the three months ended September 30, 2017,2018, to the three months ended September 30, 2016,2017, and any increases or decreases “for the nine months ended September 30, 2017,2018,” refer to the comparison of the nine months ended September 30, 2017,2018, to the nine months ended September 30, 2016.2017. The primary factors that affect the Company’s results of operations include commodity prices for oil, natural gas, and NGLs; sales volumes; the cost of finding and developing such reserves; and operating costs.


Revenues and Sales Volumes
 Three Months Ended
 Three Months Ended September 30, September 30,
millions except percentages Oil 
Natural
Gas
 NGLs Total Oil Natural Gas NGLs Total
2016 sales revenues $1,239
 $435
 $227
 $1,901
2017 sales revenues $1,567
 $269
 $265
 $2,101
Changes associated with prices 189
 33
 103
 325
 806
 (33) 78
 851
Changes associated with sales volumes 139
 (199) (65) (125) 199
 (4) 39
 234
2017 sales revenues $1,567
 $269
 $265
 $2,101
Increase (decrease) vs. 2016 26% (38)% 17% 11%
2018 sales revenues $2,572
 $232
 $382
 $3,186
Increase (decrease) vs. 2017 64% (14)% 44% 52%
        
         Nine Months Ended
 Nine Months Ended September 30, September 30,
millions except percentages Oil 
Natural
Gas
 NGLs Total Oil Natural Gas NGLs Total
2016 sales revenues $3,214
 $1,121
 $640
 $4,975
2017 sales revenues $4,652
 $1,090
 $768
 $6,510
Changes associated with prices 1,027
 372
 269
 1,668
 1,949
 (143) 227
 2,033
Changes associated with sales volumes 411
 (403) (141) (133) 363
 (265) (3) 95
2017 sales revenues $4,652
 $1,090
 $768
 $6,510
Increase (decrease) vs. 2016 45% (3)% 20% 31%
2018 sales revenues $6,964
 $682
 $992
 $8,638
Increase (decrease) vs. 2017 50% (37)% 29% 33%

The above table illustrates the effects of the increasechanges in commodity prices and sales volumes. The changes in sales volumes primarily include increases associated with sales volumes, which include increases related to assets acquiredcontinued drilling and completion activities in the Gulf of Mexico in December 2016 (primarily oil)Delaware and DJ basins and decreases associated with U.S. onshore asset divestitures (primarily natural gas).in 2017 and 2018.

The following provides Anadarko’s sales volumes for the three and nine months ended September 30:
Three Months Ended Nine Months Ended
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		September 30, September 30,
2017 Inc (Dec) 
 vs. 2016		 2016 2017 Inc (Dec) 
 vs. 2016		 20162018 Inc (Dec) vs. 2017 2017 2018 Inc (Dec) vs. 2017 2017
Barrels of Oil Equivalent                      
(MMBOE except percentages)                      
United States50
 (22)% 64
 161
 (18)% 196
53
 7% 50
 153
 (5)% 161
International8
 —
 8
 26
 13
 23
10
 18
 8
 26
 (3) 26
Total barrels of oil equivalent58
 (20) 72
 187
 (15) 219
63
 9
 58
 179
 (4) 187
                      
Barrels of Oil Equivalent per Day                      
(MBOE/d except percentages)                      
United States535
 (22)% 689
 587
 (18)% 715
575
 7% 535
 560
 (5)% 587
International91
 —
 91
 96
 14
 85
107
 18
 91
 94
 (3) 96
Total barrels of oil equivalent per day626
 (20) 780
 683
 (15) 800
682
 9
 626
 654
 (4) 683

Sales volumes represent actual production volumes adjusted for changes in commodity inventories as well as natural-gas production volumes provided to satisfy a commitment under the Jubilee development plan in Ghana. Anadarko employs marketing strategiesThe Company has derivative instruments in place to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure.reduce the price risk associated with future production. For additional information, see Note 7—8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. Production of oil, natural gas, and NGLs is usually not affected by seasonal swings in demand.


Oil Sales Revenues, Average Prices, and Volumes
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		 Three Months Ended Nine Months Ended
 2017 Inc (Dec) 
 vs. 2016		 2016 2017 Inc (Dec) 
 vs. 2016		 2016 September 30, September 30,
Oil sales revenues (millions) $1,567
 26% $1,239
 $4,652
 45% $3,214
 2018 Inc (Dec) vs. 2017 2017 2018 Inc (Dec) vs. 2017 2017
Oil sales revenues (millions)
 $2,572
 64% $1,567
 $6,964
 50 % $4,652
                        
United States                        
Sales volumes—MMBbls 25
 14% 22
 71
 12% 63
 26
 12% 25
 78
 12 % 71
MBbls/d 266
 14
 233
 259
 12
 230
 296
 12
 266
 288
 12
 259
Price per barrel $46.89
 14
 $41.29
 $47.63
 30
 $36.52
 $68.25
 46
 $46.89
 $65.96
 38
 $47.63
                        
International                        
Sales volumes—MMBbls 8
 4% 8
 25
 15% 22
 10
 16% 8
 25
 (3)% 25
MBbls/d 87
 4
 84
 91
 15
 79
 101
 16
 87
 89
 (3) 91
Price per barrel $52.61
 15
 $45.82
 $51.59
 23
 $41.98
 $76.55
 46
 $52.61
 $72.85
 41
 $51.59
                        
Total                        
Sales volumes—MMBbls 33
 11% 30
 96
 13% 85
 36
 13% 33
 103
 8 % 96
MBbls/d 353
 11
 317
 350
 13
 309
 397
 13
 353
 377
 8
 350
Price per barrel $48.31
 14
 $42.49
 $48.66
 28
 $37.91
 $70.37
 46
 $48.31
 $67.57
 39
 $48.66

The following summarizes primary drivers for the change in oil sales revenues:
millions 
Change in
Revenues
 
Due to Change
in Prices
 
Due to Change
in Volumes
Three months ended September 30, 2017 vs. 2016 $328
 $189
 $139
Nine months ended September 30, 2017 vs. 2016 1,438
 1,027
 411
millions 
Change in
Revenues
 
Due to Change
in Prices
 
Due to Change
in Volumes
Three months ended September 30, 2018 vs. 2017 $1,005
 $806
 $199
Nine months ended September 30, 2018 vs. 2017 2,312
 1,949
 363

Oil Prices
The average oil price received increased for the three and nine months ended September 30, 2017,2018, primarily due to the expectationconcerns of decreasing global oversupplya supply shortfall as a result of OPEC’s agreement to reducereductions in output from Iran as the U.S. reimposes sanctions as well as decreased production through the first quarter of 2018.from Venezuela.


Oil Sales Volumes

20172018 vs. 20162017  The Company’s oil sales volumes increased by 3644 MBbls/d for the three months ended September 30, 2017,2018, and 4127 MBbls/d for the nine months ended September 30, 2017,2018, primarily due to the following:
U.S. Onshore
Sales volumes for the Delaware basin increased by 1032 MBbls/d for the three months ended September 30, 2017,2018, and 1127 MBbls/d for the nine months ended September 30, 2017,2018, due to continued drilling and completion activities and midstream infrastructure additions in 2018.
Sales volumes for the DJ basin increased by 13 MBbls/d for the three months ended September 30, 2018, and 19 MBbls/d for the nine months ended September 30, 2018, primarily due to continued drilling and completion activities in 2017.2018.
SalesDivestitures resulted in decreased sales volumes for the DJ basin decreased by 10of 12 MBbls/d for the three months ended September 30, 2017,2018, and 1518 MBbls/d for the nine months ended September 30, 2017, primarily due to reduced capital activity in 2016 during the low commodity-price cycle resulting in production declines during 2017 and downtime related to the Company’s response efforts in Colorado in the second and third quarters of 2017. This decrease was partially offset by increased production due to increased drilling and completion activity in 2017.
Divestitures resulted in a decrease in sales volumes of 33 MBbls/d for the three months ended September 30, 2017, and 30 MBbls/d for the nine months ended September 30, 2017,2018, primarily related to the sale of the Alaska nonoperated assets in the first quarter of 2018 and the Eagleford and West Chalk assets in the first half of 2017.
Gulf of Mexico
Sales volumes increasedfor the Gulf of Mexico decreased by 615 MBbls/d for the three months ended September 30, 2017,2018, and 62remained flat for the nine months ended September 30, 2018, primarily due to natural production declines and planned downtime at various platforms, partially offset by continued tie-back activity at Horn Mountain and Marlin.
International
Sales volumes for Algeria increased by 6 MBbls/d for the three months ended September 30, 2018, primarily due to the timing of liftings. Sales volumes decreased by 5 MBbls/d for the nine months ended September 30, 2017,2018, primarily due to the GOM Acquisitiontiming of liftings and a decrease in December 2016 and continued tieback activity at several facilities, partially offsetproduction driven by deferred production as a result of Hurricanes Harvey and Irma during the third quarter of 2017.
Internationalfacility downtime for statutory maintenance in early 2018.
Sales volumes for Ghana increased by 8 MBbls/d forthethreemonthsendedSeptember30,,2017, 2018, and 123 MBbls/d for the nine months ended September 30, 2017,2018, primarily due to liftings fromincreased field performance at the TEN development project,field, which came online lateresulted in an additional lifting in the third quarter of 2016, and downtime in 2016 to address new production and offtake procedures resulting from issues associated with the Jubilee field FPSO turret bearing.2018.


Natural-Gas Sales Volumes,Revenues, Average Prices, and RevenuesVolumes
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		 Three Months Ended Nine Months Ended
 2017 Inc (Dec) 
 vs. 2016		 2016 2017 Inc (Dec) 
 vs. 2016		 2016 September 30, September 30,
Natural-gas sales revenues (millions) $269
 (38)% $435
 $1,090
 (3)% $1,121
 2018 Inc (Dec) vs. 2017 2017 2018 Inc (Dec) vs. 2017 2017
Natural-gas sales revenues (millions)
 $232
 (14)% $269
 $682
 (37)% $1,090
                        
United States                        
Sales volumes—Bcf 100
 (46)% 184
 380
 (36)% 593
 98
 (1)% 100
 287
 (24)% 380
MMcf/d 1,086
 (46) 2,003
 1,392
 (36) 2,164
 1,071
 (1) 1,086
 1,053
 (24) 1,392
Price per Mcf $2.69
 14
 $2.36
 $2.87
 52
 $1.89
 $2.35
 (13) $2.69
 $2.37
 (17) $2.87

The following summarizes primary drivers for the change in natural-gas sales revenues:
millions 
Change in
Revenues
 
Due to Change
in Prices
 
Due to Change
in Volumes
Three months ended September 30, 2017 vs. 2016 $(166) $33
 $(199)
Nine months ended September 30, 2017 vs. 2016 (31) 372
 (403)
millions 
Change in
Revenues
 
Due to Change
in Prices
 
Due to Change
in Volumes
Three months ended September 30, 2018 vs. 2017 $(37) $(33) $(4)
Nine months ended September 30, 2018 vs. 2017 (408) (143) (265)

Natural-Gas Prices
The average natural-gas price received increaseddecreased for the three and nine months ended September 30, 2017,2018, primarily due to the industry’s year-over-yearincreased U.S. natural-gas production, declines andpartially offset by increased weather-driven consumer demand coupled with an increase in natural-gas exports to Mexico resulting in reduced gas storage industry-wide.and LNG exports.

Natural-Gas Sales Volumes
20172018 vs. 20162017  The Company’s natural-gas sales volumes decreased by 917 MMcf/dremained relatively flat for the three months ended September 30, 2017, and 7722018. Natural-gas sales volumes decreased by 339 MMcf/d for the nine months ended September 30, 2017,2018, primarily due to the sale of the Marcellus, Eagleford, and EaglefordUtah CBM assets in the first half of 2017 and the Elm Grove and CarthageMoxa assets in the second half of 2016.2017.



Natural-Gas Liquids Sales Volumes,Revenues, Average Prices, and RevenuesVolumes
  Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
  2017 Inc (Dec) 
 vs. 2016		 2016 2017 Inc (Dec) 
 vs. 2016		 2016
Natural-gas liquids sales revenues (millions) $265
 17 % $227
 $768
 20 % $640
             
United States            
Sales volumes—MMBbls 9
 (28)% 11
 27
 (23)% 34
MBbls/d 88
 (28) 122
 96
 (22) 124
Price per barrel $31.07
 65
 $18.87
 $27.43
 54
 $17.78
             
International            
Sales volumes—MMBbls —
 (44)% —
 1
 (12)% 1
MBbls/d 4
 (44) 7
 5
 (12) 6
Price per barrel $32.98
 39
 $23.74
 $34.02
 44
 $23.55
             
Total            
Sales volumes—MMBbls 9
 (29)% 11
 28
 (22)% 35
MBbls/d 92
 (29) 129
 101
 (22) 130
Price per barrel $31.15
 63
 $19.13
 $27.77
 54
 $18.04
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2018 Inc (Dec) vs. 2017 2017 2018 Inc (Dec) vs. 2017 2017
Natural-gas liquids sales revenues (millions)
 $382
 44% $265
 $992
 29% $768
             
Total            
Sales volumes—MMBbls (1)
 10
 15% 9
 28
 —% 28
MBbls/d (1)
 106
 15
 92
 101
 —
 101
Price per barrel $39.16
 26
 $31.15
 $36.00
 30
 $27.77
 _______________________________________________________________________________
(1)
The percentage of total and daily NGLs sales volumes from the U.S. was approximately 95% for three and nine months ended September 30, 2018, and 2017.

NGLs sales represent revenues from the sale of product derived from the processing of Anadarko’s natural-gas production. The following summarizes primary drivers for the change in NGLs sales revenues:
millions 
Change in
Revenues
 
Due to Change
in Prices
 
Due to Change
in Volumes
Three months ended September 30, 2017 vs. 2016 $38
 $103
 $(65)
Nine months ended September 30, 2017 vs. 2016 128
 269
 (141)
millions 
Change in
Revenues
 
Due to Change
in Prices
 
Due to Change
in Volumes
Three months ended September 30, 2018 vs. 2017 $117
 $78
 $39
Nine months ended September 30, 2018 vs. 2017 224
 227
 (3)

NGLs Prices
The average NGLs price received increased for the three and nine months ended September 30, 2017,2018, primarily due to increased demand for ethane to supply newly-constructed ethane cracker facilities as well as higher propane prices stemming from higher exports and increased domestic demand.exports.

NGLs Sales Volumes
20172018 vs. 20162017  The Company’s NGLs sales volumes decreasedincreased by 3714 MBbls/d for the three months ended September 30, 2017,2018, and 29remained flat for the nine months ended September 30, 2018, primarily due to the following:
U.S. Onshore
Sales volumes for the Delaware basin increased by 14 MBbls/d for the three months ended September 30, 2018, and 9 MBbls/d for the nine months ended September 30, 2017,2018, primarily due to continued drilling and completion activities and midstream infrastructure additions in 2018.
Sales volumes for other U.S. onshore assets decreased by 8 MBbls/d for the nine months ended September 30, 2018, primarily due to the sale of the Eagleford and West Chalk assets in the first half of 2017 and the CarthageMoxa assets in the second half of 2016.2017.


Gathering, Processing, and Marketing
  Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
millions except percentages 2017 Inc (Dec) 
 vs. 2016		 2016 2017 Inc (Dec) 
 vs. 2016		 2016
Gathering, processing, and marketing sales $509
 45% $350
 $1,417
 58% $895
Gathering, processing, and marketing expense 398
 37
 291
 1,108
 46
 758
Total gathering, processing, and marketing, net $111
 88
 $59
 $309
 126
 $137
  Three Months Ended Nine Months Ended
  September 30, September 30,
millions except percentages 2018 Inc (Dec) vs. 2017 2017 2018 Inc (Dec) vs. 2017 2017
Gathering, processing, and marketing sales (1)
 $421
 (17)% $509
 $1,163
 (18)% $1,417
Gathering, processing, and marketing expense (1)
 256
 (35) 396
 745
 (32) 1,101
Gathering, processing, and marketing, net $165
 46
 $113
 $418
 32
 $316
 __________________________________________________________________
(1)
As a result of adopting ASU 2014-09, Revenue from Contracts with Customers (Topic 606), as of January 1, 2018, gathering, processing, and marketing sales decreased by $296 million for the three months ended September 30, 2018, and $781 million for the nine months ended September 30, 2018, and gathering, processing, and marketing expenses decreased by $295 million for the three months ended September 30, 2018, and $775 million for the nine months ended September 30, 2018. Refer to Note 2—Revenue from Contracts with Customersin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for further information.

Gathering and processing sales include fee revenue earned by providing gathering, processing, compression, and treating services to third parties as well as revenue from the sale of NGLs and remaining residue gas extracted from natural gas purchased from third parties and processed by Anadarko. The net margin from the sale of NGLs and residue gas for service customers when Anadarko is acting as well as fee revenue earned by providing gathering,an agent is also included. Gathering and processing compression, and treating services to third parties. Marketing sales include the margin earned from purchasing and selling third-party oil and natural gas. Gathering, processing, and marketing expense includes the cost of third-party natural gas purchased and processed by Anadarko as well as transportation and other operating and transportation expenses related to the Company’s costs to perform gathering and processing activities.
Marketing sales include the margin earned from purchasing and selling third-party oil and natural gas. Marketing expense includes transportation and other operating expenses related to the Company’s costs to perform third-party marketing activities.
Gathering,Total gathering, processing, and marketing, net increased by $52 million for the three months ended September 30, 2017,2018, and by $172$102 million for the nine months ended September 30, 2017,2018, primarily relateddue to increased throughput volumes at the DBM complexComplex, which were partially due to increased processing capacity from the start-up of newly constructed facilities200 MMcf/d cryogenic train that commenced service in MayDecember 2017, and October 2016 and previously existing facilities returning to service after the 2016 outageincreased throughput volumes at the DBM complex.DJ Basin Complex.

Gains (Losses) on Divestitures and Other, net
 Three Months Ended Nine Months Ended
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		 September 30, September 30,
millions except percentages 2017 Inc (Dec) 
 vs. 2016		 2016 2017 Inc (Dec) 
 vs. 2016		 2016 2018 Inc (Dec) vs. 2017 2017 2018 Inc (Dec) vs. 2017 2017
Gains (losses) on divestitures, net $(194) 53% $(414) $815
 NM
 $(516) $3
 102% $(194) $31
 (96)% $815
Other 80
 43
 56
 237
 85% 128
 87
 9
 80
 201
 (15) 237
Total gains (losses) on divestitures and other, net $(114) 68
 $(358) $1,052
 NM
 $(388)
Gains (losses) on divestitures and other, net $90
 179
 $(114) $232
 (78) $1,052

Gains (losses) on divestitures and other, net includes gains (losses) on divestitures and other operating revenues, including hard-minerals royalties, earnings (losses) from equity investments, hard-minerals royalties, and other revenues.
During the three and nine months ended September 30, 20172018 and 2016,2017, Anadarko divested certain non-core U.S. onshore and Gulf of Mexico assets. See Note 3—Acquisitions, 4—Divestitures and Assets Held for Sale in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information.


Costs and Expenses

The following provides Anadarko’s total costs and expenses for the three and nine months ended September 30:
 Three Months Ended Nine Months Ended
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		 September 30, September 30,
millions 2017 2016 2017 2016 2018 2017 2018 2017
Oil and gas operating $257
 $198
 $748
 $608
 $294
 $253
 $845
 $738
Oil and gas transportation 220
 256
 698
 744
 228
 220
 633
 698
Exploration 751
 304
 2,371
 506
 118
 750
 380
 2,366
Gathering, processing, and marketing (1)
 398
 291
 1,108
 758
 256
 396
 745
 1,101
General and administrative 280
 362
 840
 1,116
Depreciation, depletion, and amortization 1,083
 1,069
 3,235
 3,202
G&A 248
 261
 814
 768
DD&A 1,130
 1,083
 3,123
 3,235
Production, property, and other taxes 159
 148
 449
 422
 246
 159
 637
 449
Impairments —
 27
 383
 61
 172
 —
 319
 383
Other operating expense 123
 31
 157
 54
 26
 123
 188
 157
Total $3,271
 $2,686
 $9,989
 $7,471
 $2,718
 $3,245
 $7,684
 $9,895

(1) 
See above explanation of gathering, processing, and marketing, net.marketing.

Oil and Gas Operating Expenseand Transportation Expenses
 Three Months Ended
Nine Months Ended
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		 September 30,
September 30,
 2017 Inc (Dec) 
 vs. 2016		 2016 2017 Inc (Dec) 
 vs. 2016		 2016 2018 Inc (Dec) vs. 2017 2017 2018 Inc (Dec) vs. 2017 2017
Oil and gas operating (millions)
 $257
 30% $198
 $748
 23% $608
 $294
 16 % $253
 $845
 14 % $738
Oil and gas operating—per BOE 4.46
 62
 2.76
 4.01
 44
 2.78
 4.69
 7
 4.40
 4.73
 20
 3.95
Oil and gas transportation (millions)
 228
 4
 220
 633
 (9) 698
Oil and gas transportation—per BOE 3.63
 (5) 3.82
 3.54
 (5) 3.74

Oil and Gas Operating Expense

Oil and gas operating expense increased by $140$107 million for the nine months ended September 30, 2017,2018, primarily due to the following:
higher operating costs of $180$97 million, primarily related to increased activity in the Gulf of Mexico and the GOM Acquisition
higher operating costs of $48 million related to increased activity in the DJ and Delaware basins, and additional costs related to the Company’s response efforts in Colorado in the second and third quarters of 2017
lower non-operating costs of $18 million in Ghana primarily related to FPSO maintenance costs in 2016, partially offset by higher costs due to increased production from the TEN development in 2017, which came online late in the third quarter of 2016
lower expenses of $67$63 million as a result of U.S. onshore asset divestitures
higher non-operating costs of $55 million in Ghana, primarily due to the Jubilee turret repair in 2018 and cost adjustment credits received from the operator in 2017
The related costs per BOE increased by $1.23$0.78 for the nine months ended September 30, 2017,2018, primarily due to increased costs as discussed above anda result of shifting to a higher-return, oil-levered portfolio.portfolio that includes the Gulf of Mexico and the DJ and Delaware basins, which operate at a higher cost compared to the divested lower-return, gas-levered assets.

Oil and Gas Transportation Expense

Oil and gas transportation expense decreased by $65 million for the nine months ended September 30, 2018, primarily due to U.S. onshore divestitures. Oil and gas transportation expense per BOE decreased by $0.20 for the nine months ended September 30, 2018, primarily due to divestitures and lower transportation expense per BOE in the DJ basin. After significant investment in its midstream infrastructure, the Company has increased the use of its midstream facilities resulting in lower transportation costs for its DJ sales volumes. These decreases are partially offset by higher third-party transportation costs in the Delaware basin.


Exploration Expense
 Three Months Ended Nine Months Ended
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		 September 30, September 30,
millions 2017 2016 2017 2016 2018 2017 2018 2017
Exploration Expense        
Dry hole expense $565
 $203
 $1,408
 $209
 $—
 $565
 $55
 $1,408
Impairments of unproved properties 113
 52
 736
 91
 64
 113
 158

736
Geological and geophysical, exploration overhead, and other expense 73
 49
 227
 206
 54
 72
 167
 222
Total exploration expense $751
 $304
 $2,371
 $506
Total $118
 $750
 $380
 $2,366

Total explorationDry Hole Expense
Dry hole expense increased by $447 million for the three months ended September 30, 2017, and $1.9 billion for the nine months ended September 30, 2017,2018, primarily related to the following:

Dry Hole Expense

The Company expensed $1.4 billion of exploratory well costs for the nine months ended September 30, 2017. See Note 5—Exploratory Well Costs$49 million related to unsuccessful drilling activities in the Notes to Consolidated Financial Statements under Part I, Item 1Gulf of this Form 10-Q for additional information.Mexico during the first quarter of 2018
Dry hole expense for the nine months ended September 30, 2017, primarily related to the following:
$438 million related to the Shenandoah project, in the Gulf of Mexico
$221$221 million related to the Phobos project, in the Gulf of Mexico
$110and $110 million related to the Warrior project in the Gulf of Mexico due to insufficient quantities of oil pay to justify development
$325 million related to certain wells in Côte d’Ivoire, where the Company relinquished its interest in its Côte d’Ivoire blocks
$243 million related to certain wells in the Grand Fuerte area in Colombia
Dry hole expense due to insufficient progress on contractual and fiscal reforms needed for the nine months ended September 30, 2016, primarily related to the following:
$92 million related to certain wells in Mozambique
$64 million related to a Shenandoah well in the Gulf of Mexico
$38 million related to a well in Côte d’Ivoiredeepwater natural-gas development

Impairments of Unproved Properties

ImpairmentsFor discussion related to impairments of unproved properties, for the nine months ended September 30, 2017, primarily related to the following:
•
The Company recognized $586 million of impairments of unproved Gulf of Mexico properties, of which $463 million related to the Shenandoah project. The unproved property balance related to the Shenandoah project originated from the purchase price allocated to the Gulf of Mexico exploration projects from the acquisition of Kerr-McGee Corporation in 2006. For additional details on the Shenandoah project, see Note 5—Exploratory Well Costs in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
The Company recognized $88 million of impairments of unproved international properties during the nine months ended September 30, 2017.
See Note 4—Impairments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.


General and Administrative ExpenseG&A
 Three Months Ended Nine Months Ended
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		 September 30, September 30,
millions except percentages 2017 Inc (Dec) 
 vs. 2016		 2016 2017 Inc (Dec) 
 vs. 2016		 2016 2018 Inc (Dec) vs. 2017 2017 2018 Inc (Dec) vs. 2017 2017
General and administrative $280
 (23)% $362
 $840
 (25)% $1,116
G&A $248
 (5)% $261
 $814
 6% $768

G&A expenses decreasedincreased by $82 million for the three months ended September 30, 2017, and $276$46 million for the nine months ended September 30, 2017. Excluding the $91 million decrease related to the 2016 workforce reduction program and other severance-related costs for the three months ended September 30, 2017, and the $285 million decrease for the nine months ended September 30, 2017, G&A expenses remained relatively flat. See Note 11—Restructuring Charges in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Depreciation, Depletion, and Amortization
  Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
millions except percentages 2017 Inc (Dec) 
 vs. 2016		 2016 2017 Inc (Dec) 
 vs. 2016		 2016
Depreciation, depletion, and amortization $1,083
 1% $1,069
 $3,235
 1% $3,202

DD&A expense increased by $33 million for the nine months ended September 30, 2017,2018, primarily due to the following:
$363 million related to higher sales volumesan increase in the Gulffair value of Mexico primarily dueperformance-based unit awards. The fair value of the performance-based unit awards is calculated using a Monte Carlo simulation that incorporates several variables, including Anadarko’s historical share price and share prices of a predetermined group of peer companies to estimate the GOM Acquisition
$236 million related to international production DDfuture total shareholder returns of each. Accordingly, future G&A primarily due tocould be higher sales volumesor lower based on the outputs from the Ghana TEN project, which came online late inMonte Carlo simulation for the third quarter of 2016performance-based unit awards.
These increases were offset by the following:
$584 million related to lower 2017 sales volumes and asset property balances associated with U.S. onshore properties as a result of divestitures in 2016 and 2017

Impairments
 Three Months Ended Nine Months Ended
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		 September 30, September 30,
millions 2017 2016 2017 2016 2018 2017 2018 2017
Impairments $—
 $27
 $383
 $61
 $172
 $—
 $319
 $383

During the nine months ended September 30, 2018, the Company recorded asset impairments related to its hard-minerals properties and a gathering system in the DJ basin. During the nine months ended September 30, 2017, the Company recorded asset impairments included $211 million associated with Gulf of Mexicorelated to various oil and gas properties due to lower forecasted commodity prices. Additional impairmentsin the Gulf of $172 million primarily related toMexico and a U.S. onshore midstream property due to a reduced throughput fee as a result of a producer’s bankruptcy.property. For further discussion related to impairments, including the potential for future impairments,additional information, see Note 4—5—Impairments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Other Operating ExpensesExpense
 Three Months Ended Nine Months Ended
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		 September 30, September 30,
millions except percentages 2017 Inc (Dec) 
 vs. 2016		 2016 2017 Inc (Dec) 
 vs. 2016		 2016 2018 Inc (Dec) vs. 2017 2017 2018 Inc (Dec) vs. 2017 2017
Other operating expense $123
 NM $31
 $157
 191% $54
 $26
 (79)% $123
 $188
 20% $157

Other operating expenses increased by $92 millionexpense includes adjustments to contingency accruals, charges for the three months ended September 30, 2017,drilling rig idle time, adjustments to drilling rig termination fees, and $103 million for the nine months ended September 30, 2017, primarily due to $105 million expensed in the third quarter of 2017 for the early termination of a drilling rig.surface owner payments.

Other (Income) Expense

The following provides Anadarko’s other (income) expense for the three and nine months ended September 30:
 Three Months Ended Nine Months Ended
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		 September 30, September 30,
millions 2017 2016 2017 2016 2018 2017 2018 2017
Interest expense $230
 $220
 $680
 $657
 $240
 $230
 $705
 $682
Loss on early extinguishment of debt —
 —
 2
 124
(Gains) losses on derivatives, net (1)
 82
 25
 (33) 629
 32
 82
 503
 (33)
Other (income) expense, net (21) (31) (43) (86) 24
 5
 16
 51
Total $291
 $214
 $606
 $1,324
 $296
 $317
 $1,224
 $700

(1) 
(Gains) losses on derivatives, net represents the changes in fair value of the Company’s derivative instruments as a result of changes in commodity prices and interest rates, contract modifications, and settlements. See Note 7—8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.


Income Tax Expense (Benefit)
 Three Months Ended Nine Months Ended
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		 September 30, September 30,
millions except percentages 2017 2016 2017 2016 2018 2017 2018 2017
Income tax expense (benefit) $(425) $(260) $(366) $(957) $256
 $(425) $507
 $(366)
Income (loss) before income taxes (1,066) (1,007) (1,616) (3,313) 683
 (1,066) 1,125
 (1,616)
Effective tax rate 40% 26% 23% 29% 37% 40% 45% 23%

Upon enactment of the Tax Reform Legislation on December 22, 2017, the Company remeasured its U.S. deferred tax assets and liabilities based on the reduction of the U.S. corporate tax rate from 35% to 21%. During the third quarter of 2018, the Company recognized an additional net tax benefit of $5 million related to the adoption of the Tax Reform Legislation. The Company reported a loss before income taxesexpects to complete the accounting for the threeincome tax effects related to the adoption of the Tax Reform Legislation and nine months ended September 30, 2017 and 2016. record any remaining adjustments to provisional tax amounts, which could be material to income tax expense, before the end of the measurement period on December 21, 2018.
The Company’s effective tax rate is impacted each year by the relative pre-tax income (loss) earned by the Company’s operations in the U.S., Algeria, and the rest of the world. Additionally, state income taxes (netThe Company is subject to statutory tax rates of federal income tax benefit),38% in Algeria and 35% in Ghana. These higher-taxed foreign operations as well as non-deductible Algerian exceptional profits tax for Algerian income tax purposes generally cause the Company’s effective tax rate to vary significantly from the U.S. corporate tax rate. Additionally, the Company’s effective tax rate is typically impacted by net changes in uncertain tax positions, and pre-tax income allocatedattributable to noncontrolling interest typically impactinterests, state income taxes (net of federal benefit), and dispositions of non-deductible goodwill.
The Company received an $881 million tentative refund in 2016 related to its $5.2 billion Tronox settlement payment in 2015. In April 2018, the IRS issued a final notice of proposed adjustment denying the deductibility of the settlement payment. In September 2018, the Company received a statutory notice of deficiency from the IRS disallowing the net operating loss carryback and rejecting the Company’s effectiverefund claim. As a result, the Company intends to file a petition with the U.S. Tax Court to dispute the disallowances, and pursuant to standard U.S. Tax Court procedures, is not required to repay the $881 million refund to dispute the IRS’s position. Accordingly, the Company has not revised its estimate of the benefit that will ultimately be realized. After the case is tried and briefed in the Tax Court, the court will issue an opinion and then enter a decision. If the Company does not prevail on the issue, the earliest potential date the Company might be required to repay the refund received, plus interest, would be 91 days after entry of the decision. At such time, the Company would reverse the portion of the $346 million net benefit previously recognized in its consolidated financial statements to the extent necessary to reflect the result of the Tax Court decision. It is reasonably possible the amount of uncertain tax rate. position and/or tax benefit could materially change as the Company asserts its position in the Tax Court proceedings. Although management cannot predict the timing of a final resolution of the Tax Court proceedings, the Company does not anticipate a decision to be entered within the next three years.
For additional information on income taxes, see Note 9—11—Income Taxes in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.


LIQUIDITY AND CAPITAL RESOURCES
 Nine Months Ended
 Nine Months Ended 
 September 30,		 September 30,
millions 2017 2016 2018 2017
Net cash provided by (used in) operating activities $2,619
 $1,877
 $4,302
 $2,619
Net cash provided by (used in) investing activities (26) (1,256) (4,659) (28)
Net cash provided by (used in) financing activities (527) 2,421
 (2,306) (527)

Overview  The Company has a variety of funding sources available, including cash, an asset portfolio that provides ongoing cash-flow-generating capacity, opportunities for liquidity enhancement through divestitures and joint-venture arrangements that reduce future capital expenditures, the Company’s credit facilities, and access to both debt and equity capital markets. In addition, an effective registration statement is available to Anadarko covering the sale of WGP common units owned by the Company. WGP and WES function with capital structures that are separate from Anadarko, consisting of their own debt instruments and publicly traded common units.
ThroughDuring the nine months ended September 2017,30, 2018, Anadarko paid $2.4 billion to repurchase shares under the Share-Repurchase Program and received net proceeds of $3.5 billion$393 million from divestitures, primarily related to the sale of the Company’s Eagleford, Marcellus, Eaglebine, and Utah CBM assets.nonoperated interest in Alaska. As of September 30, 2017,2018, Anadarko had $5.3$1.9 billion of cash plus $5.0 billion of borrowing capacity under its RCFs.APC RCF and 364-Day Facility. Anadarko believes that its current available cash and anticipatedfuture operating cash flows will be sufficient to fund the Company’s remaining 2017 and projected long-term operational and capital programs, as well asits quarterly dividends, the planned debt retirements, and the repurchase of $500 million of the Company’s $2.5 billion share-repurchase program announced bycommon stock remaining under the Company in September 2017.Share-Repurchase Program. The Company continuously monitors its liquidity position and evaluates available funding alternatives in light of current and expected conditions.

Operating Activities

One of the primary sources of variability in the Company’s cash flows from operating activities is the fluctuation in commodity prices, the impact of which Anadarko partially mitigates by periodically entering into commodity derivatives. Sales volumeSales-volume changes also impact cash flow but historically have not been as volatile as commodity prices. Anadarko’s cash flows from operating activities are also impacted by the costs related to operations and interest payments related to the Company’s outstanding debt.
Cash provided byflows from operating activities was $2.6were $4.3 billion for the nine months ended September 30, 2017, $742 million2018, $1.7 billion higher compared tothan the same period of 2016. This increase wasin 2017, primarily a result ofdue to higher sales revenues in 2017 due to the impact ofresulting from higher commodity prices as well as the $159.5 million paymentand a higher oil composition of the Clean Water Act penalty in 2016 and $217 million related to severance costs and retirement benefits paid in 2016 in connection with the workforce reduction program. These increases were partially offset by an $881 million tax refund received in 2016 related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback.sales volumes.


Investing Activities

Capital Expenditures  Anadarko currently estimates a 2017 capital spending range of $5.0 billion to $5.25 billion, which includes WES capital spending of approximately $800 million to $850 million. These capital spending estimates represent decreases of more than 5% for Anadarko and 10% for WES from the initial 2017 estimates. The Company has currently allocated approximately 80% of its 2017 capital spending budget to the U.S. onshore upstream and midstream and deepwater Gulf of Mexico development; 15% to future value areas, such as deepwater exploration and Mozambique LNG; 2% to international cash generation assets in Algeria and Ghana; and 3% to corporate activities. The Company’s 2017 capital program was designed to leverage its streamlined portfolio and sharpened focus on higher-margin oil production.
The following presents the Company’s capital expenditures for the nine months ended September 30:expenditures:
 Nine Months Ended
 September 30,
millions 2017 2016 2018 2017
Cash Flows from Investing Activities        
Additions to properties and equipment (1)
 $3,538
 $2,618
 $4,891
 $3,538
Adjustments for capital expenditures        
Changes in capital accruals 237
 (300) 61
 237
Other 21
 3
 (7) 21
Total capital expenditures (2)
 $3,796
 $2,321
Total capital expenditures $4,945
 $3,796
        
Exploration and Production and other capital expenditures $2,877
 $1,921
 $3,367
 $2,876
Midstream capital expenditures - Anadarko (3)
 258
 45
Midstream capital expenditures - WES 661
 355
WES Midstream capital expenditures 920
 662
Other Midstream capital expenditures 658
 258
 ________________________________________________________________________________________
(1) 
Additions to properties and equipment as presented within Anadarko’s cash flows from investing activities include cash payments for cost of properties, equipment, and facilities. The cost of properties includes the initial capitalization of drilling costs associated with all exploratory wells, whether or not they were deemed to have a commercially sufficient quantity of proved reserves.
(2)
Capital expenditures exclude the FPSO capital lease asset.
(3)
Excludes WES.

The Company’s capital expenditures increased by $1.5$1.1 billion for the nine months ended September 30, 2017.2018. Exploration and Production capital expenditures increased primarily due to increasedhigher development costs of $694$850 million driven by U.S. onshoreincreased drilling activityand completion activities primarily in the DelawareDJ and DJDelaware basins and increased explorationthe Gulf of Mexico. Exploration costs of $281decreased by $396 million primarily duerelated to decreased exploration drilling in the Gulf of Mexico, Côte d’Ivoire, and $216 million primarily driven by U.S. onshore acreage acquisitions,Colombia partially offset by decreased development costs of $220 million driven by the TEN development project in Ghana, which achieved first oilhigher exploration drilling in the third quarter of 2016.U.S. onshore. Other Midstream capital expenditures increased primarily$400 million due to $306asset development primarily in the Delaware basin. WES Midstream capital expenditures increased $258 million primarily related to the development of WES midstream assets primarily in the Delaware and DJ basinsbasins.

Investments  During the nine months ended September 30, 2018, the Company made capital contributions of $235 million for equity investments, which are presented as cash flows from investing activities as a component of Other, net. These contributions were primarily associated with joint ventures for the Midland-to-Sealy and $213Cactus II pipelines in West Texas.

Divestitures  During the nine months ended September 30, 2018, Anadarko received net proceeds of $393 million from divestitures, primarily related to the developmentsale of APC midstream assets primarily in the Delaware basin.

Property Exchange On March 17, 2017, WES acquired a third party’s 50%Company’s nonoperated interest in the DBJV system in exchange for WES’s 33.75% interest in nonoperated Marcellus midstream assets and $155 million in cash. WES funded the cash consideration with cash on hand and recognized a gain of $126 million as a result of this transaction. After the acquisition, the DBJV system is 100% owned by WES and consolidated by Anadarko.Alaska. See Note 3—Acquisitions, 4—Divestitures and Assets Held for Sale in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Carried-Interest Arrangements  In the third quarter of 2014, the Company entered into a carried-interest arrangement that required a third party to fund $442 million of Anadarko’s capital costs in exchange for a 34% working interest in the Company’s Eaglebine development, located in Southeast Texas. The carry was canceled as part of the sale of the Eaglebine assets in the second quarter of 2017.

Divestitures  During the nine months ended September 30, 2017, Anadarko received net proceeds of $3.5 billion from divestitures, primarily related to the sale of the Company’s Eagleford, Marcellus, Eaglebine, and Utah CBM assets. See Note 3—Acquisitions, Divestitures, and Assets Held for Salein the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Financing Activities
September 30, December 31,
millions except percentagesSeptember 30, 
 2017		 December 31, 
 2016		2018 2017
Anadarko$12,201
 $12,204
$12,099
 $12,196
WES3,344
 3,091
4,566
 3,465
WGP28
 28
28
 28
Total debt$15,573
 $15,323
$16,693
 $15,689
Total equity13,922
 15,497
11,237
 13,790
Debt to total capitalization ratio52.8% 49.7%
Consolidated debt to total capitalization ratio59.8% 53.2%

Debt Activity
Anadarko Debentures  The Company repaid $114 million of 7.050% Debentures at maturity in May 2018.

Anadarko RCFs  Anadarko has aIn January 2018, the Company amended its $3.0 billion senior unsecured RCF that matures into extend the maturity date to January 20212022 (APC RCF) and aamended its $2.0 billion 364-Day Facility that matures in364-day senior unsecured RCF to extend the maturity date to January 2018.2019 (364-Day Facility). At September 30, 2017, the Company2018, Anadarko had no outstanding borrowings under the APC RCF or the 364-Day Facility.Facility and was in compliance with all covenants.
WES Senior Notes  In August 2018, WES completed a public offering of $400 million aggregate principal amount of 4.750% Senior Notes due August 2028 and a public offering of $350 million aggregate principal amount of 5.500% Senior Notes due August 2048. The net proceeds from the public offerings were used to repay the maturing $350 million of 2.600% Senior Notes due August 2018 and amounts outstanding under the WES RCF. The remaining net proceeds were used for general partnership purposes, including to fund capital expenditures.
In March 2018, WES completed a public offering of $400 million aggregate principal amount of 4.500% Senior Notes due March 2028 and a public offering of $700 million aggregate principal amount of 5.300% Senior Notes due March 2048. Net proceeds from the public offerings were used to repay amounts outstanding under the WES RCF. The remaining net proceeds were used for general partnership purposes, including to fund capital expenditures.

WES and WGP RCFs  In February 2018, WES has a $1.2 billionamended its RCF that matures into extend the maturity date from February 2020 to February 2023 and expanded the borrowing capacity to $1.5 billion (WES RCF). As part of the amendment, the WES RCF is expandable to $1.5a maximum of $2.0 billion. During the nine months ended September 30, 2017,2018, WES borrowed $250$320 million under its RCF, which was used for general partnership purposes.purposes, and made repayments of $690 million. At September 30, 2017,2018, WES had $250 million ofno outstanding borrowings under its RCF, at an interest rate of 2.54%, had outstanding letters of credit of $5 million, and had available borrowing capacity of $945 million.$1.495 billion, and was in compliance with all covenants.
In February 2018, WGP has a $250 millionvoluntarily reduced the aggregate commitments of the lenders under its senior secured RCF that maturesmaturing in March 2019 and is expandablefrom $250 million to $500$35 million subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions.(WGP RCF). At September 30, 2017,2018, WGP had outstanding borrowings under its RCF of $28 million at an interest rate of 3.24%4.25% classified as short-term debt on the Company’s Consolidated Balance Sheet, and had available borrowing capacity of $222$7 million.

For additional information on the Company’s RCFs,debt instruments, see Note 8—10—Debt in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Debt Maturities  At September 30, 2017, Anadarko’s remaining scheduled debt maturities during 2017 consisted2018, Anadarko had outstanding borrowings of $9$600 million of senior amortizing notes associated with the TEUs. At September 30, 2017, Anadarko’s scheduled debt maturities during 2018 consisted of $17 million of senior amortizing notes associated with the TEUs and $114 million of 7.05% Debentures due May 2018. In addition, WES has a scheduled debt maturity during 2018 of $350 million of 2.60%8.700% Senior Notes due August 2018.
WES’s $350March 2019 and $300 million 2.60%of 6.950% Senior Notes due August 2018 wereJune 2019 classified as long-termshort-term debt on the Company’s Consolidated Balance Sheet at September 30, 2017, as WES has the ability and intent to refinance these obligations using long-term debt.Sheet.
Anadarko’s Zero Coupons can be put to the Company in October of each year, in whole or in part, for the then-accreted value of the outstanding Zero Coupons. None of the Zero Coupons were put to the Company in October 2017.2018. The Zero Coupons can next be put to the Company in October 2018,2019, which, if put in whole, or in part, for the then-accreted value of $930would be $980 million.
For additional information on the Company’s debt instruments, see Note 8—10—Debt in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Equity Transactions  WES can issueIn February 2018, as part of the Share-Repurchase Program, the Company completed the repurchase of 8.5 million shares of its common units to the public under itsstock for $500 million continuous offering program,(average price of $58.82 per share) under an ASR Agreement. In March 2018, the Company entered into an additional ASR Agreement, which allowswas completed in June 2018 and resulted in the repurchase of 22.1 million shares of its common stock for $1.4 billion (average price of $65.28 per share). In July 2018, the Share-Repurchase Program was expanded to $4.0 billion and extended through June 30, 2019. In the third quarter of 2018, the Company completed the repurchase of 7.7 million shares of its common stock for $500 million through open-market repurchases. For additional information, see Note 14—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
In July 2017, WES filed a registration statement with the SEC for the issuance of up to an aggregate of $500 million of WES common units.units pursuant to a continuous offering program that has not yet been initiated.

Derivative Instruments  For information on derivative instruments, including cash flow treatment, see Note 7—8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Common Stock Repurchase Program  In September 2017, the Company announced a $2.5 billion share-repurchase program under which shares of the Company’s common stock may be repurchased either in the open market or through private transactions. The program is authorized to extend through the end of 2018. In October 2017, the Company entered into an agreement to complete $1.0 billion of the share-repurchase program prior to the end of 2017. See Note 13—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.


Common Stock Dividends  Anadarko paid dividends to its common stockholders of $380 million during the nine months ended September 30, 2018, and $84 million during the nine months ended September 30, 2017, and $78 million during the nine months ended September 30, 2016.2017. In response to the commodity-price environment,February 2018, the Company decreasedannounced an increase to the quarterly dividend from $0.27to $0.25 per share to $0.05 per share in February 2016.share. Anadarko has paid a dividend to its common stockholders quarterly since becoming a public company in 1986.
The amount of future dividends paid to Anadarko common stockholders is determined by the Board on a quarterly basis and is based on the Company’s earnings, financial condition, capital requirements, the effect a dividend payment would have on the Company’s compliance with relevant financial covenants, and other factors deemed relevant by the Board.

Distributions to Noncontrolling Interest Owners  Distributions to noncontrolling interest owners primarily relate to the following for the nine months ended September 30:following:
 Nine Months Ended
 September 30,
millions 2017 2016 2018 2017
WES distributions to unitholders (excluding Anadarko and WGP) (1)
 $235
 $192
 $282
 $235
WES distributions to Series A Preferred unitholders (2)
 22
 16
 —
 22
WGP distributions to unitholders (excluding Anadarko) (3)
 60
 41
 73
 60

(1) 
WES has made quarterly distributions to its unitholders since its IPO in the second quarter of 2008 and has increased its distribution from $0.30 per common unit for the third quarter of 2008 to $0.905$0.965 per common unit for the third quarter of 20172018 (to be paid in November 2017)2018).
(2) 
WES made quarterly distributions of $0.68 per unit, prorated based on issuance date, to its Series A Preferred unitholders since the unit issuances in March and April 2016. As of June 30, 2017, all Series A Preferred units havehad converted into WES common units; see Note 14—15—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10‑Q.
(3) 
WGP has made quarterly distributions to its unitholders since its IPO in December 2012 and has increased its distribution from $0.17875 per common unit for the first quarter of 2013 to $0.53750$0.59500 per unit for the third quarter of 20172018 (to be paid in November 2017)2018).

RECENT ACCOUNTING DEVELOPMENTS 

See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for discussion of recent accounting developments affecting the Company.


Item 3.  Quantitative and Qualitative Disclosures About Market Risk

The Company’s primary market risks are attributable to fluctuations in energy prices and interest rates. These risks can affect revenues and cash flows, and the Company’s risk-management policies provide for the use of derivative instruments to manage these risks. The types of commodity derivative instruments used by the Company include futures, swaps, options, and fixed-price physical-delivery contracts. The volume of commodity derivatives entered into by the Company is governed by risk-management policies and may vary from year to year. Both exchange and over-the-counter traded derivative instruments may be subject to margin-deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 7—8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

COMMODITY-PRICE RISK  The Company’s most significant market risk relates to prices for oil, natural gas, and NGLs. Management expects energy prices to remain unpredictable and potentially volatile. As energy prices decline or rise significantly, revenues and cash flows are likewise affected. In addition, a non-cash write-down of the Company’s oil and gas properties or goodwill may be required if commodity prices experience a significant decline. Below is a sensitivity analysis for the Company’s commodity-price-related derivative instruments.

Derivative Instruments Held for Non-Trading Purposes  The Company had derivative instruments in place to reduce the price risk associated with future production of 849 MMBbls of oil and 17049 Bcf of natural gas at September 30, 2017,2018, with a net derivative assetliability position of $9$458 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduceincrease the fair value of these derivativesnet derivative liability by $34$308 million, while a 10% decrease in underlying commodity prices would increasedecrease the fair value of these derivativesnet derivative liability by $36$270 million. However, any cash received or paid to settle these derivatives would be substantially offset by the sales value of production covered by the derivative instruments.

Derivative Instruments Held for Trading Purposes  At September 30, 2017, the Company had a net derivative asset position of $3 million on outstanding derivative instruments entered into for trading purposes. Based on actual derivative contractual volumes, a 10% increase or decrease in underlying commodity prices would not materially impact the Company’s gains or losses on these derivative instruments.

INTEREST-RATE RISK  Borrowings, if any, under each of the 364-Day Facility, the APC RCF, the WES RCF, and the WGP RCF are subject to variable interest rates. The remaining balance of Anadarko’s long-term debt on the Company’s Consolidated Balance Sheetsshort-term and long-term borrowings has fixed interest rates. The Company has $2.9 billion of LIBOR-based obligations that are presented on the Company’s Consolidated Balance Sheets net of preferred investments in two noncontrolled entities. These obligations give rise to minimal net interest-rate risk because coupons on the related preferred investments are also LIBOR-based. While a 10% change in LIBORthe applicable benchmark interest rate would not materially impact the Company’s interest cost, it would affect the fair value of outstanding fixed-rate debt.
At September 30, 2017,2018, the Company had a net derivative liability position of $1.4$1.0 billion related to interest-rate swaps. A 10% increase (decrease) in the three-month LIBOR interest-rate curve would decrease (increase) the aggregate fair value of outstanding interest-rate swap agreements by $88$103 million. However, any change in the interest-rate derivative gain or loss could be substantially offset by changes in actual borrowing costs associated with future debt issuances. For a summary of the Company’s outstanding interest-rate derivative positions, see Note 7—8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.


Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (Exchange Act). The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and to ensure that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of September 30, 2017.2018.

Changes in Internal Control over Financial Reporting

There were no changes in Anadarko’s internal control over financial reporting during the third quarter of 20172018 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.


PART II. OTHER INFORMATION

Item 1.  Legal Proceedings
The Company is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the ordinary course of business, including personal injury and death claims; title disputes; tax disputes; royalty claims; contract claims; contamination claims relating to oil and gas exploration, development, production, transportation, and processing; and environmental claims, including claims involving assets owned by acquired companies and claims involving assets previously sold to third parties and no longer a part of the Company’s current operations. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, tribal, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that the resolution of pending proceedings will not have a material adverse effect on the Company’s financial condition, results of operations, or cash flows.
WGR Operating, LP, a wholly owned subsidiary of the Company, is currently in negotiations with the EPAU.S. Environmental Protection Agency (EPA) with respect to alleged noncompliance with the leak detection and repair requirements of the Clean Air Act at its Granger, Wyoming facilities. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matterthese matters will result in a fine or penalty in excess of $100,000.
In September 2018, Anadarko E&P Onshore LLC, a wholly owned subsidiary of the Company, is currently in negotiationsentered into a final consent assessment with the Pennsylvania Department of Environmental Protection resolving issues concerning enforcement over a produced water release in Pennsylvania in 2015. Although management cannot predict the outcome2015 and agreed to pay a penalty of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.$350,000.
Kerr-McGee Oil and Gas Onshore, LP, a wholly owned subsidiary of the Company, is currently in negotiations with the State of Colorado’s Department of Public Health and Environment with respect to alleged noncompliance with the Colorado Air Quality Control Commission’s Regulations. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.
Kerr-McGee Gathering, LLC, a wholly owned subsidiary of the Company, is currently in negotiations with the EPA and the Department of Justice with respect to alleged noncompliance with the leak detection and repair requirements of the Clean Air Act at its Fort Lupton complex. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.
TheIn May 2018, Delaware Basin Midstream, LLC, a subsidiary of the Company, is currently in negotiationsentered into a consent agreement and final order with the EPA with respect to alleged violations ofnoncompliance with certain Risk Management Plan regulations under the Resource Conservation and RecoveryClean Air Act at certain facilitiesits Ramsey Gas Plant and agreed to pay a penalty of $226,000.
The Company continues to work cooperatively with Colorado state regulators and others following a home explosion that occurred in Firestone, Colorado in April 2017. The Company also is cooperating with the Gulf of Mexico. Although management cannot predictNTSB at the outcome of settlement discussions, it is likely a resolution of this matter will resultfederal level in a fine or penalty in excess of $100,000.its investigation related to the accident.
See Note 10—12—Contingencies intheNotestoConsolidatedFinancialStatementsunderPartI,Item1ofthisForm10-Q, which is incorporated herein by reference, for a discussion of material legal matters that have arisen sinceproceedings to which the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.Company is a party.


Item 1A.  Risk Factors
There have been no material changes fromConsider carefully the risk factors included below, as well as those included under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.2017.

Our operations in Colorado involve risks that could increase our costs of doing business, result in additional operating restrictions or delays, limit the areas in which we can operate, and adversely affect our production.

We have significant operations in the DJ basin located in the state of Colorado. Certain interest groups in Colorado opposed to oil and natural-gas development generally, and hydraulic fracturing in particular, have from time to time advanced various options for ballot initiatives that, if passed, would make exploration and production activities in the state more difficult in the future. For example, Colorado Proposition 112 qualified for inclusion on the Colorado general election ballot in November 2018. The proposition, which requires a majority vote to become law, would amend the Colorado Revised Statutes to require that new oil and gas developments, including hydraulic fracturing, take place a minimum distance of 2,500 feet from occupied buildings such as homes, schools and hospitals, and other areas designated as vulnerable. Although an exemption is made for federal lands, such setbacks would effectively ban new oil and gas drilling on a substantial portion of Colorado’s non-federal lands. According to an analysis prepared at the request of the Colorado Oil & Gas Conservation Commission (COGCC), Proposition 112 could preclude oil and gas development on more than 54% of the total land surface area of Colorado. If only non-federal land is considered, the COGCC has stated that Proposition 112 could preclude development on more than 85% of the land surface. In addition, according to the COGCC, in Colorado’s top five oil and gas producing counties combined, 61% of the surface acreage (94% of non-federal land) would be unavailable. In the event that Proposition 112 or other ballot initiatives, local or state restrictions, or other prohibitions are adopted and result in more stringent limitations on the production and development of oil and natural gas in areas where we conduct operations, or in the future plan to conduct operations, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of exploration, development, or production activities and possibly be limited or precluded in the drilling of wells or in the volumes that we are ultimately able to produce from our assets in Colorado. Such compliance costs and delays, curtailments, limitations, or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.



Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds
The following sets forth information with respect to repurchases by the Company of its shares of common stock during the third quarter of 2017:2018:
Period 
Total number of shares purchased (1)
 Average price paid per share Total number of shares purchased as part of publicly announced plans or programs 
Approximate dollar value of shares that may yet be purchased under the plans or programs (2)
July 1 - 31, 2017 4,369
 $44.80
 —
 $—
August 1 - 31, 2017 2,304
 $44.69
 —
 $—
September 1 - 30, 2017 1,158
 $40.92
 —
 $2,500,000,000
Total 7,831
 $44.20
 —
  
Period 
Total number of shares purchased (1)
 Average price paid per share 
Total number of shares purchased as part of publicly announced plans or programs (2)
 
Approximate dollar value of shares that may yet be purchased under the plans or programs (2)(3)
July 1 - 31, 2018 2,591
 $72.92
 —
 $1,000,000,000
August 1 - 31, 2018 (2)
 3,782,348
 $66.14
 3,781,259
 $749,924,384
September 1 - 30, 2018 (2)
 4,002,869
 $63.11
 3,960,089
 $500,000,003
Total 7,787,808
 $64.58
 7,741,348
 

 ____________________________________________________________
(1) 
During the third quarter of 2017,2018, (i) no7.7 million shares were purchasedrepurchased under the Company’s share-repurchase programShare-Repurchase Program and (ii) all46 thousand shares purchasedwere repurchased related to stock received by the Company for the payment of withholding taxes due on employee share issuances under share-based compensation plans. For additional information, see Note 14—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10‑Q.
(2) 
On September 20, 2017,During the third quarter of 2018, the Company repurchased 7.7 million shares of common stock for $500 million through open-market repurchases. For additional information, see Note 14—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10‑Q.
(3)
The Company announced a share-repurchase program to purchase up to $2.5 billion Share-Repurchase Program in shares of common stock. The program is authorizedSeptember 2017, which was expanded to extend$3.0 billion in February 2018.In July 2018, the Share-Repurchase Program was further expanded to $4.0 billion and extended through the end of 2018. In October 2017, the Company entered into the ASR Agreement to complete $1.0 billion of the share-repurchase program prior to the end of 2017.June 30, 2019.

Item 6.  Exhibits

Exhibits designated by an asterisk (*) are filed herewith or double asterisk (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing under File Number 1-8968 as indicated.
Exhibit Number Description
 3(i) 
Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated May 21, 2009, filed as Exhibit 3.3 to Form 8-K filed on May 22, 2009
  (ii) 
By-Laws of Anadarko Petroleum Corporation, amended and restated as of September 15, 2015,November 14, 2017, filed as Exhibit 3.1 to Form 8-K filed on September 21, 2015November 16, 2017
*31(i) 
Rule 13a-14(a)/15d-14(a) Certification—Chief Executive Officer
*31(ii) 
Rule 13a-14(a)/15d-14(a) Certification—Chief Financial Officer
**32  
Section 1350 Certifications
*101.INS XBRL Instance Document
*101.SCH XBRL 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

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, thereunto duly authorized.
  ANADARKO PETROLEUM CORPORATION
                               (Registrant) 
   
October 31, 201730, 2018By:/s/ ROBERT G. GWIN
  
Robert G. Gwin
Executive Vice President, Finance and Chief Financial Officer

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