Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, 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 June 30, 2016March 31, 2017
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  ☒    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  ☒    No  ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer  ☒    Accelerated filer  ☐    Non-accelerated filer  ☐    Smaller reporting company☐ Emerging growth company  ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒
The number of shares outstanding of the Company’s common stock at July 15, 2016,April 19, 2017, is shown below:
Title of Class Number of Shares Outstanding
Common Stock, par value $0.10 per share 510,457,469560,339,140


TABLE OF CONTENTS
PART I
 Page
Item 1.
Financial Statements
 
 
Consolidated Statements of Income for the Three and Six Months Ended June 30,March 31, 2017 and 2016 and 2015
23
 
Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30,March 31, 2017 and 2016 and 2015
34
 
Consolidated Balance Sheets at June 30, 2016,March 31, 2017, and December 31, 20152016
45
 
Consolidated Statement of Equity for the SixThree Months Ended June 30, 2016March 31, 2017
56
 
Consolidated Statements of Cash Flows for the SixThree Months Ended June 30,March 31, 2017 and 2016 and 2015
67
 
Notes to Consolidated Financial Statements
78
 
Note 1 - Summary of Significant Accounting Policies
78
 
Note 2 - Inventories
811
 
Note 3 - Acquisitions, Divestitures, and Assets Held for Sale
811
 
Note 4 - Impairments
912
 
Note 5 - Suspended Exploratory Well Costs
1013
 
Note 6 - Derivative InstrumentsCurrent Liabilities
1013
 
Note 7 - Tangible Equity UnitsDerivative Instruments
1614
 
Note 8 - Debt and Interest Expense
1619
 
Note 9 - Income Taxes
1920
 
Note 10 - Conveyance of Future Hard Minerals Royalty RevenuesContingencies
1921
 
Note 11 - Contingencies
20
Note 12 - Restructuring Charges
21
 
Note 1312 - Pension Plans and Other Postretirement Benefits
21
Note 13 - Stockholders’ Equity
22
 
Note 14 - Stockholders’ EquityNoncontrolling Interests
2322
 
Note 15 - Accumulated Other Comprehensive Income (Loss)Variable Interest Entities
23
 
Note 16 - Noncontrolling InterestsSupplemental Cash Flow Information
24
 
Note 17 - Variable Interest Entities
24
Note 18 - Supplemental Cash Flow Information
25
Note 19 - Segment Information
25
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
2927
 
Cautionary Statement About Forward-Looking Statements
2927
 
Outlook
30
Management Overview
3129
 
Financial Results
3330
 
Liquidity and Capital Resources
4239
 
Recent Accounting Developments
4642
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
4743
Item 4.
Controls and Procedures
4844
PART II
  
Item 1.
Legal Proceedings
4945
Item 1A.
Risk Factors
4945
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
4945
Item 6.
Exhibits
5046

COMMONLY USED TERMS AND DEFINITIONS

TableUnless 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
ASU - Accounting Standards Update
Bcf - Billion cubic feet
BOE - Barrels of Contentsoil equivalent
DBJV - Delaware Basin JV Gathering LLC
DBJV system - A gathering system and related facilities located in the Delaware basin in Loving, Ward, Winkler, and Reeves Counties in West Texas
DBM complex - 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
EPA - U.S. Environmental Protection Agency
Five-Year Facility - Anadarko’s $3.0 billion five-year senior unsecured RCF maturing in January 2021
FPSO - Floating production, storage, and offloading unit
G&A - General and administrative expenses
GAAP - U.S. Generally Accepted Accounting Principles
GOM Acquisition - Acquisition of oil and natural-gas assets in the Gulf of Mexico, which closed on December 15, 2016
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
NGLs - Natural gas liquids
NM - Not meaningful
NYMEX - New York Mercantile Exchange
Oil - Includes crude oil and condensate
OPEC - Organization of the Petroleum Exporting Countries
RCF - Revolving credit facility
S&P - Standard and Poor’s
TEN - Tweneboa/Enyenra/Ntomme
TEU or TEUs - Tangible equity units
VIE - Variable interest entity
WES - Western Gas Partners, LP, a limited partnership and publicly-traded consolidated subsidiary of Anadarko
WES RCF - WES’s $1.2 billion five-year senior unsecured RCF maturing in February 2020
WGP - Western Gas Equity Partners, LP, a limited partnership and publicly-traded consolidated subsidiary of Anadarko
WGP RCF - WGP’s $250 million three-year senior secured RCF maturing in March 2019
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 
 June 30,		 Six Months Ended 
 June 30,
millions except per-share amounts 2016 2015 2016 2015
Revenues and Other        
Oil and condensate sales $1,125
 $1,616
 $1,975
 $3,035
Natural-gas sales 320
 487
 686
 1,128
Natural-gas liquids sales 235
 229
 413
 461
Gathering, processing, and marketing sales 305
 305
 545
 598
Gains (losses) on divestitures and other, net (70) (1) (30) (265)
Total 1,915
 2,636
 3,589
 4,957
Costs and Expenses        
Oil and gas operating 202
 226
 410
 522
Oil and gas transportation 246
 283
 488
 588
Exploration 76
 103
 202
 1,186
Gathering, processing, and marketing 252
 255
 467
 509
General and administrative 305
 278
 754
 585
Depreciation, depletion, and amortization 984
 1,214
 2,133
 2,470
Other taxes 157
 151
 274
 333
Impairments 18
 30
 34
 2,813
Other operating expense 7
 6
 23
 69
Total 2,247
 2,546
 4,785
 9,075
Operating Income (Loss) (332) 90
 (1,196) (4,118)
Other (Income) Expense        
Interest expense 217
 201
 437
 417
Loss on early extinguishment of debt 124
 —
 124
 —
(Gains) losses on derivatives, net 307
 (311) 604
 (159)
Other (income) expense, net (55) 15
 (55) 62
Tronox-related contingent loss —
 —
 —
 5
Total 593
 (95) 1,110
 325
Income (Loss) Before Income Taxes (925) 185
 (2,306) (4,443)
Income tax expense (benefit) (314) 77
 (697) (1,315)
Net Income (Loss) (611) 108
 (1,609) (3,128)
Net income (loss) attributable to noncontrolling interests 81
 47
 117
 79
Net Income (Loss) Attributable to Common Stockholders $(692) $61
 $(1,726) $(3,207)
         
Per Common Share        
Net income (loss) attributable to common stockholders—basic $(1.36) $0.12
 $(3.39) $(6.32)
Net income (loss) attributable to common stockholders—diluted $(1.36) $0.12
 $(3.39) $(6.32)
Average Number of Common Shares Outstanding—Basic 510
 508
 510
 507
Average Number of Common Shares Outstanding—Diluted 510
 509
 510
 507
Dividends (per common share) $0.05
 $0.27
 $0.10
 $0.54

See accompanying Notes to Consolidated Financial Statements.

2
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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
  Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
millions 2016 2015 2016 2015
Net Income (Loss) $(611) $108
 $(1,609) $(3,128)
Other Comprehensive Income (Loss)        
Adjustments for derivative instruments        
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net 2
 3
 5
 5
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net (1) (1) (2) (2)
Total adjustments for derivative instruments, net of taxes 1
 2
 3
 3
Adjustments for pension and other postretirement plans        
Net gain (loss) incurred during period (24) —
 (190) —
Income taxes on net gain (loss) incurred during period 9
 —
 70
 —
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 34
 13
 42
 26
Income taxes on amortization of net actuarial (gain) loss to general and administrative expense (13) (5) (16) (9)
Amortization of net prior service (credit) cost to general and administrative expense (6) 1
 (21) 1
Income taxes on amortization of net prior service (credit) cost to general and administrative expense 3
 —
 8
 —
Total adjustments for pension and other postretirement plans, net of taxes 3
 9
 (107) 18
Total 4
 11
 (104) 21
Comprehensive Income (Loss) (607) 119
 (1,713) (3,107)
Comprehensive income (loss) attributable to noncontrolling interests 81
 47
 117
 79
Comprehensive Income (Loss) Attributable to Common Stockholders $(688) $72
 $(1,830) $(3,186)

  Three Months Ended 
 March 31,
millions except per-share amounts 2017 2016
Revenues and Other    
Oil sales $1,663
 $850
Natural-gas sales 502
 366
Natural-gas liquids sales 289
 178
Gathering, processing, and marketing sales 444
 240
Gains (losses) on divestitures and other, net 869
 40
Total 3,767
 1,674
Costs and Expenses    
Oil and gas operating 258
 208
Oil and gas transportation 249
 242
Exploration 1,085
 126
Gathering, processing, and marketing 351
 215
General and administrative 269
 449
Depreciation, depletion, and amortization 1,115
 1,149
Production, property, and other taxes 155
 117
Impairments 373
 16
Other operating expense 22
 16
Total 3,877
 2,538
Operating Income (Loss) (110) (864)
Other (Income) Expense    
Interest expense 223
 220
(Gains) losses on derivatives, net (147) 297
Other (income) expense, net (8) —
Total 68
 517
Income (Loss) Before Income Taxes (178) (1,381)
Income tax expense (benefit) 97
 (383)
Net Income (Loss) (275) (998)
Net income (loss) attributable to noncontrolling interests 43
 36
Net Income (Loss) Attributable to Common Stockholders $(318) $(1,034)
     
Per Common Share    
Net income (loss) attributable to common stockholders—basic $(0.58) $(2.03)
Net income (loss) attributable to common stockholders—diluted $(0.58) $(2.03)
Average Number of Common Shares Outstanding—Basic 551
 509
Average Number of Common Shares Outstanding—Diluted 551
 509
Dividends (per Common Share) $0.05
 $0.05

See accompanying Notes to Consolidated Financial Statements.

3
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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETSSTATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
millions June 30,
2016		 December 31,
2015
ASSETS    
Current Assets    
Cash and cash equivalents ($160 and $100 related to VIEs) $1,394
 $939
Accounts receivable (net of allowance of $13 and $11)    
   Customers ($67 and $81 related to VIEs) 770
 652
   Others ($76 and $84 related to VIEs) 730
 1,817
Other current assets 318
 573
Total 3,212
 3,981
Properties and Equipment    
Cost 69,610
 70,683
Less accumulated depreciation, depletion, and amortization 37,265
 36,932
Net properties and equipment ($5,002 and $4,859 related to VIEs) 32,345
 33,751
Other Assets ($621 and $644 related to VIEs)
 2,239
 2,268
Goodwill and Other Intangible Assets ($1,237 and $1,220 related to VIEs)
 6,237
 6,331
Total Assets $44,033
 $46,331
     
LIABILITIES AND EQUITY    
Current Liabilities    
Accounts payable ($172 and $179 related to VIEs) $2,200
 $2,850
Current asset retirement obligations 221
 309
Interest payable 242
 247
Other taxes payable ($21 and $18 related to VIEs) 282
 318
Accrued expenses 267
 424
Short-term debt 32
 32
Total 3,244
 4,180
Long-term Debt 15,641
 15,636
Other Long-term Liabilities    
Deferred income taxes 4,686
 5,400
Asset retirement obligations ($135 and $127 related to VIEs) 1,726
 1,750
Other 4,136
 3,908
Total 10,548
 11,058
     
Equity    
Stockholders’ equity    
Common stock, par value $0.10 per share (1.0 billion shares authorized, 531.2 million and 528.3 million shares issued) 53
 52
Paid-in capital 9,638
 9,265
Retained earnings 3,103
 4,880
Treasury stock (20.7 million and 20.0 million shares) (1,026) (995)
Accumulated other comprehensive income (loss) (487) (383)
Total Stockholders’ Equity 11,281
 12,819
Noncontrolling interests 3,319
 2,638
Total Equity 14,600
 15,457
Total Liabilities and Equity $44,033
 $46,331
  Three Months Ended 
 March 31,
millions 2017 2016
Net Income (Loss) $(275) $(998)
Other Comprehensive Income (Loss)    
Adjustments for derivative instruments    
Reclassification of previously deferred derivative losses to (gains) losses on
derivatives, net
 1
 3
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net —
 (1)
Total adjustments for derivative instruments, net of taxes 1
 2
Adjustments for pension and other postretirement plans    
Net gain (loss) incurred during period (4) (166)
Income taxes on net gain (loss) incurred during period 1
 61
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 9
 8
Income taxes on amortization of net actuarial (gain) loss to general and
administrative expense
 (3) (3)
Amortization of net prior service (credit) cost to general and administrative expense (6) (15)
Income taxes on amortization of net prior service (credit) cost to general and administrative expense 2
 5
Total adjustments for pension and other postretirement plans, net of taxes (1) (110)
Total —
 (108)
Comprehensive Income (Loss) (275) (1,106)
Comprehensive income (loss) attributable to noncontrolling interests 43
 36
Comprehensive Income (Loss) Attributable to Common Stockholders $(318) $(1,142)

Parenthetical references reflect amounts as of June 30, 2016, and December 31, 2015.

See accompanying Notes to Consolidated Financial Statements.

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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF EQUITYBALANCE SHEETS
(Unaudited)
  Total Stockholders’ Equity    
  
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Treasury
Stock
 
Accumulated Other
Comprehensive
Income (Loss)
 
Non-
controlling
Interests
 
Total
Equity
millions              
Balance at December 31, 2015 $52
 $9,265
 $4,880
 $(995) $(383) $2,638
 $15,457
Net income (loss) —
 —
 (1,726) —
 —
 117
 (1,609)
Common stock issued 1
 108
 —
 —
 —
 —
 109
Dividends—common stock —
 —
 (51) —
 —
 —
 (51)
Repurchase of common stock —
 —
 —
 (31) —
 —
 (31)
Subsidiary equity transactions —
 265
 —
 —
 —
 723
 988
Distributions to noncontrolling interest owners —
 —
 —
 —
 —
 (159) (159)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net —
 —
 —
 —
 3
 —
 3
Adjustments for pension and other postretirement plans —
 —
 —
 —
 (107) —
 (107)
Balance at June 30, 2016 $53
 $9,638
 $3,103
 $(1,026) $(487) $3,319
 $14,600
millions March 31, 
 2017		 December 31, 
 2016
ASSETS    
Current Assets    
Cash and cash equivalents ($123 and $359 related to VIEs) $5,831
 $3,184
Accounts receivable (net of allowance of $16 and $14)    
   Customers ($81 and $70 related to VIEs) 973
 1,007
   Others ($12 and $80 related to VIEs) 604
 721
Other current assets 299
 354
Total 7,707
 5,266
Properties and Equipment    
Cost 64,485
 69,013
Less accumulated depreciation, depletion, and amortization 35,420
 36,845
Net properties and equipment ($5,264 and $5,050 related to VIEs) 29,065
 32,168
Other Assets ($608 and $609 related to VIEs)
 2,182
 2,226
Goodwill and Other Intangible Assets ($1,214 and $1,221 related to VIEs)
 5,739
 5,904
Total Assets $44,693
 $45,564
     
LIABILITIES AND EQUITY    
Current Liabilities    
Accounts payable    
Trade ($166 and $234 related to VIEs) $1,637
 $1,617
Other 342
 303
Short-term debt 42
 42
Current asset retirement obligations 258
 129
Other current liabilities 1,483
 1,237
Total 3,762
 3,328
Long-term Debt 15,284
 15,281
Other Long-term Liabilities    
Deferred income taxes 3,664
 4,324
Asset retirement obligations ($142 and $140 related to VIEs) 2,684
 2,802
Other 4,220
 4,332
Total 10,568
 11,458
     
Equity    
Stockholders’ equity    
Common stock, par value $0.10 per share
(1.0 billion shares authorized, 573.0 million and 572.0 million shares issued)		 57
 57
Paid-in capital 11,914
 11,875
Retained earnings 1,330
 1,704
Treasury stock (21.1 million and 20.8 million shares) (1,054) (1,033)
Accumulated other comprehensive income (loss) (391) (391)
Total Stockholders’ Equity 11,856
 12,212
Noncontrolling interests 3,223
 3,285
Total Equity 15,079
 15,497
Total Liabilities and Equity $44,693
 $45,564


Parenthetical references reflect amounts as of March 31, 2017, and December 31, 2016.

See accompanying Notes to Consolidated Financial Statements.

5
Table of Contents

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTSSTATEMENT OF CASH FLOWSEQUITY
(Unaudited)
  Six Months Ended 
 June 30,
millions 2016 2015
Cash Flows from Operating Activities    
Net income (loss) $(1,609) $(3,128)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities    
Depreciation, depletion, and amortization 2,133
 2,470
Deferred income taxes (820) (1,187)
Dry hole expense and impairments of unproved properties 45
 1,040
Impairments 34
 2,813
(Gains) losses on divestitures, net 102
 425
Loss on early extinguishment of debt 124
 —
Total (gains) losses on derivatives, net 610
 (158)
Operating portion of net cash received (paid) in settlement of derivative instruments 165
 172
Other 203
 74
Changes in assets and liabilities    
Tronox-related contingent liability —
 (5,210)
(Increase) decrease in accounts receivable 922
 (105)
Increase (decrease) in accounts payable and accrued expenses (717) (198)
Other items, net (100) (269)
Net cash provided by (used in) operating activities 1,092
 (3,261)
Cash Flows from Investing Activities    
Additions to properties and equipment and dry hole costs (1,879) (3,501)
Divestitures of properties and equipment and other assets 900
 700
Other, net 14
 16
Net cash provided by (used in) investing activities (965) (2,785)
Cash Flows from Financing Activities    
Borrowings, net of issuance costs 5,275
 4,787
Repayments of debt (5,425) (3,857)
Financing portion of net cash received (paid) for derivative instruments (727) (77)
Increase (decrease) in outstanding checks (159) (109)
Dividends paid (51) (277)
Repurchase of common stock (31) (37)
Issuance of common stock, including tax benefit on share-based compensation awards 30
 19
Sale of subsidiary units 1,163
 187
Issuance of tangible equity units — equity component —
 348
Distributions to noncontrolling interest owners (159) (135)
Proceeds from conveyance of future hard minerals royalty revenues, net of transaction costs 413
 —
Net cash provided by (used in) financing activities 329
 849
Effect of Exchange Rate Changes on Cash (1) 1
Net Increase (Decrease) in Cash and Cash Equivalents 455
 (5,196)
Cash and Cash Equivalents at Beginning of Period 939
 7,369
Cash and Cash Equivalents at End of Period $1,394
 $2,173
  Total Stockholders’ Equity    
millions 
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
Net income (loss) —
 —
 (318) —
 —
 43
 (275)
Common stock issued (1)
 —
 42
 —
 —
 —
 —
 42
Dividends—common stock —
 —
 (28) —
 —
 —
 (28)
Repurchase of common stock —
 —
 —
 (21) —
 —
 (21)
Distributions to noncontrolling interest owners —
 —
 —
 —
 —
 (105) (105)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net —
 —
 —
 —
 1
 —
 1
Adjustments for pension and other postretirement plans —
 —
 —
 —
 (1) —
 (1)
Cumulative effect of accounting change —
 (3) (28) —
 —
 —
 (31)
Balance at March 31, 2017 $57
 $11,914
 $1,330
 $(1,054) $(391) $3,223
 $15,079

(1)
Represents share-based compensation expense.



See accompanying Notes to Consolidated Financial Statements.

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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
  Three Months Ended 
 March 31,
millions 2017 2016
Cash Flows from Operating Activities    
Net income (loss) $(275) $(998)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities    
Depreciation, depletion, and amortization 1,115
 1,149
Deferred income taxes (660) (413)
Dry hole expense and impairments of unproved properties 1,012
 35
Impairments 373
 16
(Gains) losses on divestitures, net (804) (2)
Total (gains) losses on derivatives, net (147) 299
Operating portion of net cash received (paid) in settlement of derivative instruments (8) 105
Other 83
 115
Changes in assets and liabilities    
(Increase) decrease in accounts receivable 68
 46
Increase (decrease) in accounts payable and other current liabilities 395
 (326)
Other items, net (29) (163)
Net cash provided by (used in) operating activities 1,123
 (137)
Cash Flows from Investing Activities    
Additions to properties and equipment (1,194) (1,022)
Divestitures of properties and equipment and other assets 2,851
 35
Other, net 65
 14
Net cash provided by (used in) investing activities 1,722
 (973)
Cash Flows from Financing Activities    
Borrowings, net of issuance costs —
 4,682
Repayments of debt (10) (1,608)
Financing portion of net cash received (paid) for derivative instruments (37) (555)
Increase (decrease) in outstanding checks 28
 (150)
Dividends paid (28) (25)
Repurchase of common stock (21) (30)
Issuance of common stock —
 30
Sale of subsidiary units —
 440
Distributions to noncontrolling interest owners (105) (78)
Proceeds from conveyance of future hard minerals royalty revenues, net of transaction costs —
 413
Payments of future hard minerals royalty revenues conveyed (25) —
Net cash provided by (used in) financing activities (198) 3,119
Effect of Exchange Rate Changes on Cash —
 (1)
Net Increase (Decrease) in Cash and Cash Equivalents 2,647
 2,008
Cash and Cash Equivalents at Beginning of Period 3,184
 939
Cash and Cash Equivalents at End of Period $5,831
 $2,947


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

GeneralAnadarko Petroleum Corporation is engaged in the exploration, development, production, and marketing of oil, condensate, natural gas, and natural gas liquids (NGLs),NGLs and in the marketing of anticipated production of liquefied natural gas (LNG).LNG. In addition, the Company engages in the gathering, processing, treating, and transporting of oil, condensate, natural gas, and NGLs.NGLs as well as gathering and disposal of produced water. The Company also participates in the hard-minerals business through royalty arrangements. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

Basis of Presentation  The Consolidated Financial Statementsaccompanying unaudited consolidated financial statements have been prepared in conformityaccordance with generally accepted accounting principlesGAAP 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 United States (GAAP).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-yearcurrent-period presentation. These Consolidated Financial Statementsinterim financial statements should be read in conjunction with the Consolidated Financial Statementsconsolidated financial statements and accompanying notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015.2016.
The Consolidated Financial Statementsconsolidated financial statements include the accounts of Anadarko and subsidiaries in which Anadarko holds, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs)VIEs for which Anadarko is the primary beneficiary. 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 over which 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 reported as a component ofincluded in other assets.

Recently IssuedAdopted Accounting Standards  The Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2015-03,ASU 2017-01, Interest—ImputationBusiness Combinations (Topic 805): Clarifying the Definition of Interest (Subtopic 835-30)—Simplifyinga 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 Presentationfair value of Debt Issuance Coststhe gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the set will not be considered a business. If the screen is not met, a set must include an input and ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30)—Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. These ASUs require capitalized debt issuance costs, except for those relateda substantive process that together significantly contribute to revolving credit facilities,the ability to create an output to be presented in the balance sheet asconsidered a direct deduction from the carrying amountbusiness. The Company’s adoption of the related debt liability, rather than as an asset. The Company adopted these ASUsthis ASU on January 1, 2016,2017, using a retrospective approach.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 to be a business. The adoption resultedCompany’s disposition of Eagleford oil and gas properties in the first quarter of 2017 was not considered a reclassification that reduced other current assetsbusiness under this ASU and short-term debt by $1 milliontherefore not allocated goodwill, see Note 3—Acquisitions, Divestitures, and reduced other assets and long-term debt by $82 million on the Company’s Consolidated Balance Sheet at December 31, 2015.Assets Held for Sale.
The FASB issued ASU 2015-02,2016-16, ConsolidationIncome Taxes (Topic 810)—Amendments740): Intra-Entity Transfers of Assets Other Than Inventory, requires an entity to recognize the Consolidation Analysis.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, 2016. In accordance with2017, using a modified retrospective approach, and recognized a cumulative adjustment to retained earnings of $31 million during the new ASU, Western Gas Equity Partners, LP (WGP) and Western Gas Partners, LP (WES), publicly traded consolidated subsidiariesfirst quarter of the Company, are considered VIEs for which the Company is the primary beneficiary. Prior to adoption of the ASU, WGP and WES were consolidated by the Company under the voting interest model. After adoption, WGP and WES were consolidated by the Company under the variable interest model. While this ASU requires additional financial statement disclosure, it has no impact on the Company’s consolidated results of operations, cash flows, or financial position. See Note 17—Variable Interest Entities.
The FASB issued ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This ASU will simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, classification on the statement of cash flows, and accounting for forfeitures. This ASU is effective for annual and interim periods beginning in 2017 with early adoption permitted. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements.2017.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. Summary of Significant Accounting Policies (Continued)

The FASB issued ASU 2016-02,2016-09, LeasesCompensation—Stock Compensation (Topic 842).718): Improvements to Employee Share-Based Payment Accounting, This ASU requiressimplifies the lessees to recognize a lease liability and a right-of-use assetaccounting for all leases,share-based payment transactions, including operating leases, with a term greater than 12 monthsthe income tax consequences, classification on the balance sheetstatement of cash flows, accounting for forfeitures, and disclose key information about their leasing transactions.classification of awards as either equity or liabilities. The Company adopted this ASU on January 1, 2017. As a result of adoption, share-based compensation excess tax benefits and tax deficiencies 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 three months ended March 31, 2017, the Company recognized a $15 million tax deficiency as an increase to the provision for income taxes. Cash flows related to excess tax benefits have been 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 is effective2017-07, 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 annualcapitalization. The Company will adopt this ASU on January 1, 2018, with retrospective presentation of the service cost component and interim periods beginningthe other components of net benefit cost in 2019.the income statement and prospective presentation for the capitalization of the service cost component of net benefit cost in assets. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements.
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. 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 FASB issued Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements.
ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, 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 does not expect the adoption of this ASU to have a material impact on its Consolidated Statement of Cash Flows.

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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), ,which supersedes current revenue recognition requirements and industry-specific guidance. The codification was amended through additional ASUs and, as amended, 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 requireddeveloping accounting policies to address the provisions of the ASU. While the Company does not currently expect net earnings to be materially impacted, the Company is currently analyzing whether total revenues and total expenses may increase as a result of recognizing both revenue for noncash consideration for services provided by our midstream business and revenue and associated cost of product for the subsequent sale of commodities received as such noncash consideration. Anadarko continues to evaluate the impact of this and other provisions of the ASU on its accounting policies, internal controls, and consolidated financial statements and related disclosures and has not finalized any estimates of the potential impacts. The Company will adopt the new standard in the first quarter ofon January 1, 2018, using onethe modified retrospective method with a cumulative adjustment to retained earnings.
ASU 2016-02, Leases (Topic 842), requires lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. The provisions of two retrospective application methods.ASU 2016-02 also modify the definition of a lease and outline the requirements for recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. This ASU is effective for annual and interim periods beginning after December 15, 2018. The Company is continuingcurrently analyzing its portfolio of contracts to evaluateassess the provisionsimpact future adoption of this ASU and has not determined the impact this standard may have on its consolidated financial statements and related disclosures or decided upon the method of adoption.statements.


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

2. Inventories

The following summarizes the major classes of inventories included in other current assets:
millionsJune 30,
2016		 December 31,
2015		March 31, 
 2017		 December 31, 
 2016
Oil$111
 $116
$130
 $169
Natural gas28
 36
19
 38
NGLs77
 64
94
 106
Total inventories$216
 $216
$243
 $313

3. Acquisitions, Divestitures, and Assets Held for Sale

For the six months ended June 30,Acquisition On December 15, 2016, the Company received $900 million inclosed the GOM Acquisition for $1.8 billion using a portion of the net proceeds from divestituresthe September 2016 issuance of 40.5 million shares of its common stock. The GOM Acquisition constitutes a business combination and was accounted for using the acquisition method of accounting. The fair-value measurements of the assets acquired and liabilities assumed at the acquisition date were still preliminary as of March 31, 2017, pending customary closing adjustments. There were no material changes to the fair value of the assets acquired and liabilities assumed from the amounts included on the Company’s Consolidated Balance Sheet at December 31, 2016.

Property Exchange On March 17, 2017, WES acquired a third party’s 50% 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 net lossesa gain of $102$125 million fromas a result of this transaction. After the acquisition, the DBJV system 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.sale for the three months ended March 31:
millions2017 2016
Proceeds received, net of closing adjustments$2,851
 $35
Gains (losses) on divestitures, net804
 2

Divestitures The following divestitures primarily related toDuring the three months ended March 31, 2017, the Company divested certain U.S. onshore assets thatlocated in the Eagleford area of South Texas for net proceeds of $2.1 billion and a net gain of $726 million. These assets were included in the oil and gas exploration and production reporting segment:segment.
The Company sold certainCertain Marcellus U.S. onshore assets located in East Texas/Louisiana with a sales price of $107 million, for net proceeds of $99 million, and recognized a gain of $13 million.
The Company sold certain U.S. onshore assets in West Texas for net proceeds of $138 million, with no gain or loss recognized.
The Company sold certain U.S. onshore assets in the Rockies for net proceeds of $593 million, and recognized a loss of $53 million.

Assets Held for Sale Certain U.S. onshore assetsPennsylvania included in the oil and gas exploration and production and midstream reporting segments satisfied criteria to be considered held for sale during the secondfourth quarter of 2016, at which time the Company remeasured themthese assets to their current fair value using a market approach and Level 2 fair-value measurementinputs and recognized a loss of $50$129 million. The sale of these assets is expected to close inclosed during the thirdfirst quarter of 2016.
Gains2017 for net proceeds of $763 million and losses on assetsan additional loss of $44 million. Remaining proceeds of $196 million are currently held for sale are included in gains (losses) on divestitures and other, net inescrow by the purchaser, pending regulatory approval. At March 31, 2017, the Company’s Consolidated StatementsBalance Sheet included long-term assets of Income. At June 30, 2016, the balances$215 million, which includes $35 million of assetsgoodwill, and long-term liabilities of $15 million, primarily associated with Marcellus assets held for sale were not material.in escrow subject to regulatory approval.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

4. Impairments

Impairments of Long-Lived Assets Impairments of long-lived assets are included in impairment expense in the Company’s Consolidated Statements of Income. The following summarizes impairments of long-lived assets and the related post-impairment fair values by segment:
  Three Months Ended Six Months Ended
millionsImpairment 
Fair Value (1)
 Impairment 
Fair Value (1)
June 30, 2016       
Oil and gas exploration and production       
Long-lived assets held for use       
U.S. onshore properties$—
 $—
 $4
 $585
Gulf of Mexico properties1
 —
 2
 —
Cost-method investment (2)
1
 32
 2
 32
Midstream       
Long-lived assets held for use11
 2
 21
 5
Other       
Long-lived assets held for use5
 1
 5
 1
Total$18
 $35
 $34
 $623
        
June 30, 2015       
Oil and gas exploration and production       
Long-lived assets held for use       
U.S. onshore properties$4
 $12
 $2,303
 $1,303
Gulf of Mexico properties17
 —
 25
 —
Cost-method investment (2)
1
 32
 1
 32
Midstream       
Long-lived assets held for use8
 199
 484
 202
Total$30
 $243
 $2,813
 $1,537
  Three Months Ended
millionsImpairment 
Fair Value (1)
March 31, 2017   
Oil and gas exploration and production   
Gulf of Mexico properties$204
 $231
Midstream169
 49
Total$373
 $280

(1) 
Measured as of the impairment date using the income approach and Level 3 inputs.
(2)
Represents the after-tax The primary assumptions used to estimate undiscounted future net investment.cash flows include anticipated future production, commodity prices, and capital and operating costs.

Impairments during the sixthree months ended June 30, 2015,March 31, 2017, were primarily related to the Company’s Greater Natural Buttes oil and gas and midstream properties in the Rockies, which were impairedGulf of Mexico due to lower forecasted commodity prices.
In additionprices and a U.S. onshore midstream property due to the long-lived asset impairments above, the Company recognized a $935 million impairment of unproved Greater Natural Buttes properties during the six months ended June 30, 2015,reduced throughput fee as a result of lower commodity prices.a producer’s bankruptcy.

Impairments of Unproved Properties Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. The Company recognized $532 million of impairments of unproved Gulf of Mexico properties during the three months ended March 31, 2017, of which $467 million related to the Shenandoah project. The unproved property balance related to the Shenandoah project originated from the purchase price allocated to Gulf of Mexico exploration projects from the acquisition of Kerr-McGee Corporation in 2006. For additional details on the Shenandoah project, see Note 5—Suspended Exploratory Well Costs.

Potential for Future Impairments  

Oil price sensitivity At March 31, 2017, the Company’s estimate of undiscounted future cash flows attributable to certain asset groups, primarily related to international and offshore properties, with a combined net book value of approximately $2.7 billion indicated that the carrying amounts were expected to be recovered; however, these asset groups may be at risk for impairment if the estimates of future cash flows decline. The Company estimates that a 10% decline in oil prices (with all other assumptions unchanged) could result in non-cash impairments in excess of $1.0 billion.

Natural-gas price sensitivityAt March 31, 2017, the Company’s estimate of undiscounted future cash flows attributable to certain U.S. onshore asset groups with a combined net book value of approximately $1.3 billion indicated that the carrying amounts were expected to be recovered; however, these asset groups may be at risk for impairment if the estimates of future cash flows decline. The Company estimates that a 10% decline in natural-gas prices (with all other assumptions unchanged) could result in non-cash impairments in excess of $500 million.
It is also reasonably possible that prolonged low or furthersignificant 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 futureother additional impairments.



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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

5. Suspended Exploratory Well Costs

The Company’s suspended exploratory well costs were $1.1 billion at March 31, 2017, and $1.2 billion at June 30, 2016, and $1.1 billion at December 31, 2015. The increase in suspended exploratory well costs during 2016 is primarily related to the capitalization of costs associated with appraisal activities in Côte d’Ivoire. There were no material charges to exploration expense during the six months ended June 30, 2016, related to suspended exploratory well costs previously capitalized for a period greater than one year since the completion of drilling at December 31, 2015.2016. Projects with suspended exploratory well costs are those identified by management as exhibitinginclude wells that have sufficient quantities of hydrocarbonsreserves to justify potential developmentcompletion as a producing well and where managementsufficient progress is actively pursuing efforts to assess whetherbeing made in assessing the reserves can be attributed to these projects.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 three months ended March 31, 2017, the Company expensed suspended exploratory well costs of $435 million related to the Shenandoah project in the Gulf of Mexico, including $267 million previously capitalized for a period greater than one year. The Shenandoah-6 appraisal well and subsequent sidetrack, which completed appraisal activities in April 2017, did not encounter the oil-water contact in the eastern portion of the field. Given the results of this well and the present commodity-price environment, the Company has currently suspended further appraisal activities. Accordingly, the Company determined that the Shenandoah project no longer satisfies the accounting requirements for the continued capitalization of the exploratory well costs.

6. Current Liabilities

Accounts Payable Accounts payable, trade included liabilities of $290 million at March 31, 2017, and $262 million at December 31, 2016, 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:
millionsMarch 31, 
 2017		 December 31, 
 2016
Accrued income taxes$671
 $6
Interest payable161
 244
Production, property, and other taxes payable253
 239
Accrued employee benefits185
 355
Other213
 393
Total other current liabilities$1,483
 $1,237


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

7. 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).
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. See Note 15—Accumulated Other Comprehensive Income (Loss).


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

6. Derivative Instruments (Continued)

Oil and Natural-Gas Production/Processing Derivative Activities  The oil prices listed below are a combination of New York Mercantile Exchange (NYMEX)NYMEX West Texas Intermediate 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 June 30, 2016:March 31, 2017:
 2016 Settlement 2017 Settlement 2018 Settlement
Oil     
Three-Way Collars (MBbls/d)83
 —
 —
Average price per barrel     
Ceiling sold price (call)$63.82
 $—
 $—
Floor purchased price (put)$54.46
 $—
 $—
Floor sold price (put)$42.77
 $—
 $—
Natural Gas     
Three-Way Collars (thousand MMBtu/d)—
 682
 250
Average price per MMBtu     
Ceiling sold price (call)$—
 $3.60
 $3.54
Floor purchased price (put)$—
 $2.75
 $2.75
Floor sold price (put)$—
 $2.00
 $2.00
Fixed-Price Contracts (thousand MMBtu/d)14
 32
 —
Average price per MMBtu$2.38
 $3.14
 $—
NGLs     
Fixed-Price Contracts (MBbls/d)—
 2
 —
Average price per barrel$—
 $15.84
 $—

MBbls/d—thousand barrels per day
MMBtu/d—million British thermal units per day
MMBtu—million British thermal units
 2017 Settlement 2018 Settlement
Oil   
Three-Way Collars (MBbls/d)91
 —
Average price per barrel
  
Ceiling sold price (call)$59.80
 $—
Floor purchased price (put)$50.00
 $—
Floor sold price (put)$40.00
 $—
Natural Gas   
Three-Way Collars (thousand MMBtu/d)682
 250
Average price per MMBtu   
Ceiling sold price (call)$3.60
 $3.54
Floor purchased price (put)$2.75
 $2.75
Floor sold price (put)$2.00
 $2.00
Fixed-Price Contracts (thousand MMBtu/d)19
 —
Average price per MMBtu$2.82
 $—

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.


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

7. Derivative Instruments (Continued)

Marketing and Trading Derivative Activities  The Company had financial derivative transactions with notional volumes of natural gas totaling 5 billion cubic feet (Bcf) at June 30, 2016, and 82 Bcf at March 31, 2017, and December 31, 2015,2016, that were entered into to mitigate commodity-price risk related to fixed-price purchase and sales contracts and storage activity.


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

6. 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 London Interbank Offered Rate (LIBOR). In February 2016, in exchange for amended terms with certain counterparties, the Company modified the mandatory termination dates from 2021 to 2018 and, in some cases, the related fixed interest rates on interest-rate swaps with an aggregate notional principal amount of $500 million. Additionally, an interest-rate swap agreement was settled in March 2016, resulting in a cash payment of $193 million.LIBOR.
At June 30, 2016,March 31, 2017, the Company had outstanding interest-rate swaps with a notional amount of $1.7$1.6 billion due prior to or atin September 2021 that will manage interest-rate risk associated with the potential refinancing of the Company’s $900 million Senior Notes due 2019 and the Zero-Coupon Senior NotesZero Coupons due 2036, (Zero Coupons), should the Zero Coupons be put to the Company prior to the swap termination dates. At the next put date in October 2016,2017, the accreted value of the Zero Coupons will be $839$883 million. See Note 8—Debt and Interest Expense. 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. 
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 or collateralization related to these extended interest-rate derivatives are classified as cash flows from financing activities. Cash payments related to interest-rate swap agreements were $24 million during the three months ended March 31, 2017, and $193 million during the three months ended March 31, 2016.
The Company had the following outstanding interest-rate swaps at June 30, 2016:March 31, 2017: 
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
$50
 September 2016 – 2026 September 2016 5.910%500
 September 2016 – 2046
September 2018 6.559%
$50
 September 2016 – 2046 September 2016 6.290%300
 September 2016 – 2046 September 2020 6.509%
$500
 September 2016 – 2046 September 2018 6.559%450
 September 2017 – 2047 September 2018 6.445%
$300
 September 2016 – 2046 September 2020 6.509%100
 September 2017 – 2047 September 2020 6.891%
$450
 September 2017 – 2047 September 2018 6.445%250
 September 2017 – 2047 September 2021 6.570%
$100
 September 2017 – 2047 September 2020 6.891%
$250
 September 2017 – 2047 September 2021 6.570%


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

6.7. 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 June 30, December 31, June 30, December 31, March 31, December 31, March 31, December 31,
Balance Sheet Classification 2016 2015 2016 2015 2017 2016 2017 2016
Commodity derivatives                
Other current assets $111
 $462
 $(29) $(177) $51
 $10
 $(31) $(3)
Other assets 10
 8
 —
 —
 12
 9
 —
 —
Accrued expenses 4
 —
 (30) (3)
Other current liabilities 15
 66
 (35) (201)
Other liabilities 2
 —
 (15) —
 —
 —
 —
 (12)
 127
 470
 (74) (180) 78
 85
 (66) (216)
Interest-rate derivatives         
      
Other current assets 3
 2
 —
 —
 8
 8
 —
 —
Other assets 15
 54
 —
 —
 23
 23
 —
 —
Accrued expenses —
 —
 (99) (54)
Other current liabilities —
 —
 (69) (48)
Other liabilities —
 —
 (1,749) (1,488) —
 —
 (1,271) (1,328)
 18
 56
 (1,848) (1,542) 31
 31
 (1,340) (1,376)
Total derivatives $145
 $526
 $(1,922) $(1,722) $109
 $116
 $(1,406) $(1,592)

Effect of Derivative Instruments—Statement of Income  The following summarizes gains and losses related to derivative instruments:
millions Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,		 Three Months Ended 
 March 31,
Classification of (Gain) Loss Recognized 2016 2015 2016 2015 2017 2016
Commodity derivatives            
Gathering, processing, and marketing sales (1)
 $4
 $1
 $6
 $1
 $—
 $2
(Gains) losses on derivatives, net 94
 1
 66
 (52) (135) (28)
Interest-rate derivatives         
 
(Gains) losses on derivatives, net 213
 (312) 538
 (107) (12) 325
Total (gains) losses on derivatives, net $311
 $(310) $610
 $(158) $(147) $299

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


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

6.7. 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. At June 30, 2016, $100 million of the Company’s $1.922 billion gross derivative liability balance, and at December 31, 2015, $347 million of the Company’s $1.722 billion gross derivative liability balance, would have been eligible for setoff against the Company’s gross derivative asset balance in the event of default. Other than in the event of default, the Company does not net settle 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 also require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered, such as if the Company’s credit rating from major credit rating agenciesS&P and Moody’s declines to a level that is below investment grade. In February 2016, Moody’s Investors Service (Moody’s) downgradedAs of March 31, 2017, the Company’s long-term debtcredit rating from “Baa2” to “Ba1,” which is was rated below investment grade. The downgrade triggered credit-risk-related features withgrade (Ba1) by Moody’s and investment grade (BBB) by both S&P and Fitch Ratings. Although certain derivative counterparties and required the Company to post collateral under its derivative instruments. The amount of cash posted as collateral pursuantdue to the contractual requirements applicable to derivative instruments with financial institutions was $599 million at June 30, 2016, and $58 million at December 31, 2015. NoMoody’s rating, no counterparties have requested termination or full settlement of derivative positions. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.3$1.2 billion (net of $130 million of collateral) at eachMarch 31, 2017, and $1.4 billion (net of June 30, 2016, and$117 million of collateral) at December 31, 2015.2016.


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

6.7. 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:
millions           Level 1 Level 2 Level 3 
Netting (1)
 Collateral Total
June 30, 2016Level 1 Level 2 Level 3 
Netting (1)
 Collateral Total
March 31, 2017           
Assets                      
Commodity derivatives$1
 $126
 $—
 $(35) $—
 $92
$—
 $78
 $—
 $(45) $—
 $33
Interest-rate derivatives—
 18
 —
 —
 —
 18
—
 31
 —
 —
 —
 31
Total derivative assets$1
 $144
 $—
 $(35) $—
 $110
$—
 $109
 $—
 $(45) $—
 $64
Liabilities                      
Commodity derivatives$(4) $(70) $—
 $35
 $5
 $(34)$(1) $(65) $—
 $45
 $2
 $(19)
Interest-rate derivatives—
 (1,848) —
 —
 592
 (1,256)—
 (1,340) —
 —
 130
 (1,210)
Total derivative liabilities$(4) $(1,918) $—
 $35
 $597
 $(1,290)$(1) $(1,405) $—
 $45
 $132
 $(1,229)
                      
December 31, 2015           
December 31, 2016           
Assets                      
Commodity derivatives$10
 $460
 $—
 $(178) $(8) $284
$2
 $83
 $—
 $(69) $—
 $16
Interest-rate derivatives—
 56
 —
 —
 —
 56
—
 31
 —
 —
 —
 31
Total derivative assets$10
 $516
 $—
 $(178) $(8) $340
$2
 $114
 $—
 $(69) $—
 $47
Liabilities                      
Commodity derivatives$(1) $(179) $—
 $178
 $—
 $(2)$(3) $(213) $—
 $69
 $6
 $(141)
Interest-rate derivatives—
 (1,542) —
 —
 58
 (1,484)—
 (1,376) —
 —
 117
 (1,259)
Total derivative liabilities$(1) $(1,721) $—
 $178
 $58
 $(1,486)$(3) $(1,589) $—
 $69
 $123
 $(1,400)
 __________________________________________________________________
(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)

7. Tangible Equity Units

In June 2015, the Company issued 9.2 million 7.50% tangible equity units (TEUs) at a stated amount of $50.00 per TEU for net proceeds of $445 million. Each TEU is comprised of a prepaid equity purchase contract for common units of WGP and a senior amortizing note. Subsequent to issuance, each TEU may be legally separated into the two components. The prepaid equity purchase contract is considered a freestanding financial instrument, indexed to WGP common units, and meets the conditions for equity classification. The prepaid equity purchase contracts are included in noncontrolling interests, net of issuance costs, and the senior amortizing notes are included in short-term debt and long-term debt on the Company’s Consolidated Balance Sheets.

Equity ComponentUnless settled earlier at the holder’s option, each purchase contract has a mandatory settlement date of June 7, 2018. Anadarko has a right to elect to issue and deliver shares of Anadarko Petroleum Corporation common stock (APC shares) in lieu of delivering WGP common units at settlement. The Company will deliver not more than 0.8591 WGP common units and not less than 0.7159 WGP common units (or a computed number of APC shares) per TEU on the settlement date, subject to adjustment, at the settlement rate based upon the applicable market value of WGP common units (or APC shares).8. Debt

Debt Component Each senior amortizing note has an initial principal amount of $10.95 and bears interest at 1.50% per year. On September 7, 2015, Anadarko began paying equal quarterly cash installments of $0.9375 per amortizing note (except for the September 7, 2015 installment payment, which was $0.9063 per amortizing note). The payments constitute a payment of interest and partial repayment of principal, with the aggregate per-year payments of principal and interest equating to a 7.50% cash payment with respect to each TEU. The senior amortizing notes have a final installment payment date of June 7, 2018, and are senior unsecured obligations of the Company.

8. Debt and Interest Expense

Debt Activity  The following summarizes the Company’s debt activity, after eliminating the effect of intercompany transactions, during the six months ended June 30, 2016:
 Carrying Value  
millionsWES 
WGP (1)
 
Anadarko (2)
 Anadarko Consolidated Description
Balance at December 31, 2015$2,691
 $—
 $12,957
 $15,648
  
Issuances—
 —
 794
 794
 4.850% Senior Notes due 2021
 —
 —
 1,088
 1,088
 5.550% Senior Notes due 2026
 —
 —
 1,088
 1,088
 6.600% Senior Notes due 2046
Borrowings—
 —
 1,750
 1,750
 364-Day Facility
 530
 —
 —
 530
 WES RCF
 —
 28
 —
 28
 WGP RCF
Repayments—
 —
 (1,749) (1,749) 5.950% Senior Notes due 2016
 —
 —
 (1,245) (1,245) 6.375% Senior Notes due 2017
 —
 —
 (1,750) (1,750) 364-Day Facility
 (290) —
 —
 (290) WES RCF
 —
 —
 (250) (250) Commercial paper notes, net
 —
 —
 (17) (17) TEUs - senior amortizing notes
Other, net1
 —
 27
 28
 Amortization of discounts, premiums, and debt issuance costs
Balance at June 30, 2016$2,932
 $28
 $12,693
 $15,653
  

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

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

8. Debt and Interest Expense (Continued)

Debt  The Company’s outstanding debt, excluding theincluding capital lease obligation and any borrowings under the WGP revolving credit facility, is senior unsecured. The following summarizes the Company’s outstanding debtobligations, after eliminating the effect of intercompany transactions:
millionsWES 
WGP (1)
 
Anadarko (2)
 Anadarko ConsolidatedWES 
WGP (1)
 
Anadarko (2)
 Anadarko Consolidated
June 30, 2016       
March 31, 2017       
Total borrowings at face value$2,960
 $28
 $14,325
 $17,313
$3,120
 $28
 $13,550
 $16,698
Net unamortized discounts, premiums, and debt issuance costs (3)
(28) —
 (1,632) (1,660)(28) —
 (1,587) (1,615)
Total borrowings2,932
 28
 12,693
 15,653
Capital lease obligation—
 —
 20
 20
Total borrowings (4)
3,092
 28
 11,963
 15,083
Capital lease obligations—
 —
 243
 243
Less short-term debt—
 —
 32
 32
—
 —
 42
 42
Total long-term debt$2,932
 $28
 $12,681
 $15,641
$3,092
 $28
 $12,164
 $15,284
              
December 31, 2015       
December 31, 2016       
Total borrowings at face value$2,720
 $—
 $14,592
 $17,312
$3,120
 $28
 $13,558
 $16,706
Net unamortized discounts, premiums, and debt issuance costs (3)
(29) —
 (1,635) (1,664)(29) —
 (1,599) (1,628)
Total borrowings2,691
 —
 12,957
 15,648
Capital lease obligation—
 —
 20
 20
Total borrowings (4)
3,091
 28
 11,959
 15,078
Capital lease obligations—
 —
 245
 245
Less short-term debt—
 —
 32
 32
—
 —
 42
 42
Total long-term debt$2,691
 $—
 $12,945
 $15,636
$3,091
 $28
 $12,162
 $15,281

(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 revolving credit facilitiesRCFs are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.

During the second quarter of 2016, the Company used proceeds from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.250 billion of its $2.0 billion 6.375% Senior Notes due September 2017 pursuant to a tender offer and to redeem its $1.750 billion 5.950% Senior Notes due September 2016. The Company recognized a loss of $124 million for the early retirement and redemption of these senior notes, which included $114 million of premiums paid.
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, which will be $839 million at the next put date in October 2016. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at June 30, 2016, as the Company has the ability and intent to refinance these obligations using long-term debt, should the put be exercised.
(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 $17.2$17.0 billion at June 30, 2016,March 31, 2017, and $15.7$17.1 billion at December 31, 2015.2016.


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

8. Debt and Interest Expense (Continued)

Anadarko Revolving Credit Facilities and Commercial Paper ProgramBorrowings  Anadarko has a $3.0 billion five-year senior unsecured revolving credit facilityRCF maturing in January 2021 (Five-Year Facility). In addition, in January 2016 the Company replaced its previous and a $2.0 billion 364-day senior unsecured revolving credit facility with a new $2.0 billion 364-day senior unsecured revolving credit facilityRCF (364-Day Facility), on identical terms, that will mature in. In January 2017.2017, the Company extended the maturity date of the 364-Day Facility until January 2018. At June 30, 2016,March 31, 2017, the Company had no outstanding borrowings under the Five-Year Facility or the 364-Day Facility and was in compliance with all related covenants.
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, which will be $883 million at the next put date in October 2017. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at March 31, 2017, as the Company has the ability and intent to refinance these obligations using long-term debt, should the put be exercised.
In January 2015, the Company initiated a commercial paper program, which allows for a maximum of $3.0 billion of unsecured commercial paper notes and is supported by the Five-Year Facility. The maturities of the commercial paper notes may vary, but may not exceed 397 days. In February 2016, Moody’s downgradedDue to the Company’s commercial paper programbelow-investment-grade credit rating which essentially eliminatedfrom Moody’s, the Company’sCompany currently does not have access to the commercial paper market. As a result, the Company has not issued commercial paper notes since the downgrade. At June 30, 2016, the Companymarket and had no outstanding borrowings under the commercial paper program.program at March 31, 2017.


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Table of Contents
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

8. Debt (Continued)

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 Method Investments in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.

WES and WGP Borrowings  At March 31, 2017, WES has a five-yearwas in compliance with all related covenants contained in its $1.2 billion five-year senior unsecured revolving credit facilityRCF maturing in February 20192020 (WES RCF), which is expandable to $1.5 billion. At June 30, 2016,March 31, 2017, WES had no outstanding borrowings under its RCF, of $540 million at an interest rate of 1.77%, had outstanding letters of credit of $5 million, and had available borrowing capacity of $655 million. $1.195 billion.
At June 30, 2016, WESMarch 31, 2017, WGP was in compliance with all related covenants.
In March 2016, WGP entered into a three-yearcovenants contained in its $250 million three-year senior secured revolving credit facilityRCF maturing in March 2019 (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. Borrowings under the WGP RCF bear interest at LIBOR (with a floor of 0%), plus applicable margins ranging from 2.00% to 2.75% depending on WGP’s consolidated leverage ratio, or at a base rate equal to the greatest of (i) the prime rate, (ii) the federal funds rate plus 0.50%, or (iii) LIBOR plus 1.00%, in each case plus applicable margins ranging from 1.00% to 1.75% based upon WGP’s consolidated leverage ratio. At June 30, 2016,March 31, 2017, WGP had outstanding borrowings under its RCF of $28 million at an interest rate of 2.72%,2.99% and had available borrowing capacity of $222 million, and was in compliance with all related covenants.
In July 2016, WES completed a public offering of $500 million aggregate principal amount of 4.650% Senior Notes due July 2026. Net proceeds were used to repay a portion of the amount outstanding under the WES RCF.million.

Interest Expense  The following summarizes interest expense:
 Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
millions2016 2015 2016 2015
Debt and other$259
 $244
 $517
 $498
Capitalized interest(42) (43) (80) (81)
Total interest expense$217
 $201
 $437
 $417


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

9. Income Taxes

The following summarizes income tax expense (benefit) and effective tax rates:
Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,		Three Months Ended 
 March 31,
millions except percentages2016 2015 2016 20152017 2016
Income tax expense (benefit)$(314) $77
 $(697) $(1,315)$97
 $(383)
Income (loss) before income taxes(925) 185
 (2,306) (4,443)(178) (1,381)
Effective tax rate34% 42% 30% 30%(54)% 28%

The Company reported a loss before income taxes for the three and six months ended June 30, 2016,March 31, 2017 and the six months ended June 30, 2015.2016. As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The variance from the 35% U.S. federal statutory rate for the three and six months ended June 30, 2016 and 2015, was primarily attributable to the non-deductible Algerian exceptional profits tax for Algerian income tax purposes and the tax impact from foreign operations. In addition, the decrease from the 35% U.S. federal statutory rate for the three and six months ended June 30,March 31, 2017, was primarily attributable to the following decreases:
state taxes, net of federal benefit
non-deductible Algerian exceptional profits tax for Algerian income tax purposes
tax impact from foreign operations
net changes in uncertain tax positions
•
tax deficiency related to share-based compensation due to the adoption of ASU 2016-09, see Note 1—Summary of Significant Accounting Policies
These decreases were partially offset by the following increases:
•income attributable to noncontrolling interests
•federal manufacturing deduction

The decrease from the 35% U.S. federal statutory rate for the three months ended March 31, 2016, was primarily attributable to non-deductible goodwill related to divestituresAlgerian exceptional profits tax for Algerian income tax purposes, the tax impact from foreign operations, and net changes in uncertain tax positions.
At June 30, 2016,March 31, 2017, the Company’s Consolidated Balance Sheet included a $192$167 million taxof income taxes receivable includedpresented in accounts receivable—others.

10. Conveyance of Future Hard Minerals Royalty Revenues

During the first quarter of 2016, the Company conveyed a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party for $413 million, net of transaction costs. Such conveyance entitles the third party to receive up to $553 million in future royalty revenue over a period of not less than 10 years and not greater than 15 years. Additionally, such third party is entitled to receive 3% of the aggregate royalties earned during the first 10 years between $800 million and $900 million and 4% of the aggregate royalties earned during the first 10 years that exceed $900 million. Generally, such third party relies solely on the royalty payments to recover its investment and, as such, has the risk of the royalties not being sufficient to recover its investment over the term of the conveyance.
Proceeds from this transaction have been accounted for as deferred revenues and are included in accrued expenses and other long-term liabilities on the Company’s Consolidated Balance Sheet. The deferred revenues will be amortized to other revenues, included in gains (losses) on divestitures and other, net on a unit-of-revenue basis over the term of the agreement. During the six months ended June 30, 2016, the Company amortized $19 million of deferred revenues as a result of this agreement. Proceeds from the transaction and payments to the third party are reported in financing activities in the Company’s Consolidated Statement of Cash Flows.
The Company will make the first payment for royalties in September 2016. The specified future amounts that the Company expects to pay and the payment timing are subject to change based upon the actual royalties received by the Company during the term of the conveyance. The following summarizes the future amounts, prior to the 3% to 4% of any excess described above, that the Company expects to pay:
millions 
2016$25
201750
201850
201952
202056
Later years320
Total$553


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

11.10. Contingencies

Litigation  The following is a discussion of anyThere are no material developments in previously reported contingencies andnor 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, 2015.

Deepwater Horizon Events  In April 2010, the Macondo well in the Gulf of Mexico blew out and an explosion occurred on the Deepwater Horizon drilling rig, resulting in an oil spill. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% nonoperated interest. In October 2011, the Company and BP entered into a settlement agreement relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company is fully indemnified by BP against all claims and damages arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and assessment costs, and any claims arising under the Operating Agreement with BP.
Numerous Deepwater Horizon event-related civil lawsuits were filed against BP and other parties, including the Company. Generally, the plaintiffs sought actual damages, punitive damages, declaratory judgment, and/or injunctive relief. This litigation was consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the U.S. District Court for the Eastern District of Louisiana in New Orleans, Louisiana (Louisiana District Court).

BP Consent Decree In July 2015, BP announced a settlement agreement in principle with the U.S. Department of Justice (DOJ) and certain states and local government entities regarding essentially all of the outstanding claims against BP related to the Deepwater Horizon event (BP Settlement) and, in October 2015, lodged a proposed consent decree with the Louisiana District Court. In April 2016, the Louisiana District Court approved the consent decree. As a result of the BP Settlement and approval of the consent decree, all liability relating to OPA-related environmental costs was resolved and all NRD claims and claims by the United States and the Gulf states impacted by the event relating to the MDL action were dismissed. For any remaining claims relating to the MDL action, the Company is fully indemnified by BP against any losses pursuant to the Settlement Agreement. For additional disclosure related to the Deepwater Horizon events, see Note 15—Contingencies—Deepwater Horizon Events in the Notes to Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015.

Penalties and Fines  In December 2010, the DOJ, on behalf of the United States, filed a civil lawsuit in the Louisiana District Court against several parties, including the Company, seeking an assessment of civil penalties under the Clean Water Act (CWA) in an amount to be determined by the Louisiana District Court. After previously finding that Anadarko, as a nonoperating investor in the Macondo well, was not culpable with respect to the Deepwater Horizon events, the Louisiana District Court found Anadarko liable for civil penalties under Section 311 of the CWA as a working-interest owner in the Macondo well and entered a judgment of $159.5 million in December 2015. Neither party appealed the decision and the Company paid the penalty in the first quarter of 2016.


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

12.11. Restructuring Charges

In the first quarter of 2016, the Company initiated a workforce reduction program to align the size and composition of Anadarko’sits workforce with the Company’sits expected future operating and capital plans. Employee notifications related to the workforce reduction program were completed by June 30, 2016. The Company recognized $203 million of restructuring charges included in G&A in the Company’s Consolidated Statements of Income during the three months ended March 31, 2016. All restructuring charges will bewere recognized in 2016, with the exception of approximately $10an estimated $29 million of settlement expense for retirement benefits expected to be recognized induring 2017 for lump-sum payments to terminated participants for which the first quarter of 2017. The following summarizes the total expected restructuring chargesamount could vary depending on market conditions and the amounts expensed during the three and six months ended June 30, 2016, which are included in general and administrative expenses in the Company’s Consolidated Statements of Income:
millionsTotal Expected Costs Three Months Ended 
 June 30, 2016		 Six Months Ended 
 June 30, 2016
Costs by category     
Cash severance$153
 $15
 $146
Retirement benefits (1)
220
 27
 76
Share-based compensation34
 6
 29
Total$407
 $48
 $251

(1)
Includes termination benefits, curtailments, and settlements. See Note 13—Pension Plans and Other Postretirement Benefits.

The following summarizes the changes in the cash severance-related liability included in accounts payable on the Company’s Consolidated Balance Sheet:
millions2016
Balance at January 1$—
Accruals146
Payments(126)
Balance at June 30$20
participant elections.


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

13.12. 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
millions2016 2015 2016 20152017 2016 2017 2016
Three Months Ended June 30       
Three Months Ended March 31       
Service cost$23
 $29
 $—
 $2
$21
 $26
 $—
 $1
Interest cost23
 26
 3
 4
21
 26
 3
 3
Expected return on plan assets(24) (28) —
 —
Expected (return) loss on plan assets(21) (27) —
 —
Amortization of net actuarial loss (gain)10
 13
 —
 —
6
 8
 —
 —
Amortization of net prior service cost (credit)—
 —
 (6) 1
—
 —
 (6) (6)
Settlement expense24
 —
 —
 —
3
 —
 —
 —
Curtailment expense—
 —
 3
 —
Termination benefits expense (1)
4
 44
 —
 —
Curtailment expense (1)
—
 8
 —
 (3)
Net periodic benefit cost$56
 $40
 $—
 $7
$34
 $85
 $(3) $(5)
       
Six Months Ended June 30       
Service cost$49
 $59
 $1
 $5
Interest cost49
 51
 6
 8
Expected return on plan assets(51) (55) —
 —
Amortization of net actuarial loss (gain)18
 26
 —
 —
Amortization of net prior service cost (credit)—
 —
 (12) 1
Settlement expense24
 —
 —
 —
Termination benefits expense44
 —
 —
 —
Curtailment expense8
 —
 —
 —
Net periodic benefit cost$141
 $81
 $(5) $14

(1)
Termination benefits expense and curtailment expense for the three months ended March 31, 2016, relate to the workforce reduction program initiated in the first quarter of 2016. See Note 11—Restructuring Charges.

The Company’s workforce reduction program resulted in remeasurements of its pensionCompany contributed $60 million during the three months ended March 31, 2017, and other postretirement benefit obligations during 2016. The remeasurements resulted in increases in the benefit obligation of $171 million for the pension benefit plans and $23 million for the other postretirement benefit plans, with a corresponding decrease in other comprehensive income.
At December 31, 2015, total expected contributions related to unfunded pension plans were $25 million for 2016. The Company expects to contribute an additional $82$107 million in 2016 and $23 million in 2017 to unfundedfunded pension plans primarily related to the workforce reduction program. See Note 12—Restructuring Charges.during 2017.


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

14.13. 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 TEUsTangible Equity Units (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, if the inclusion of these items is dilutive.
The following provides a reconciliation between basic and diluted earnings per shareEPS attributable to common stockholders:
Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,		Three Months Ended 
 March 31,
millions except per-share amounts2016 2015 2016 20152017 2016
Net income (loss)          
Net income (loss) attributable to common stockholders$(692) $61
 $(1,726) $(3,207)$(318) $(1,034)
Income (loss) effect of TEUs(2) —
 (3) —
(2) (1)
Less distributions on participating securities—
 1
 —
 2
Basic$(694) $60
 $(1,729) $(3,209)$(320) $(1,035)
Income (loss) effect of TEUs(1) —
 (1) —
Diluted$(695) $60
 $(1,730) $(3,209)$(320) $(1,035)
Shares          
Average number of common shares outstanding—basic510
 508
 510
 507
551
 509
Dilutive effect of stock options—
 1
 —
 —
Average number of common shares outstanding—diluted510
 509
 510
 507
551
 509
Excluded due to anti-dilutive effect11
 6
 10
 11
11
 10
Net income (loss) per common share          
Basic$(1.36) $0.12
 $(3.39) $(6.32)$(0.58) $(2.03)
Diluted$(1.36) $0.12
 $(3.39) $(6.32)$(0.58) $(2.03)

15. Accumulated Other Comprehensive Income (Loss)

The following summarizes the after-tax changes in the balances of accumulated other comprehensive income (loss):
millions
Interest-rate
Derivatives
Previously
Subject to Hedge
Accounting
 
Pension and Other Postretirement
Plans
 Total
Balance at December 31, 2015$(42) $(341) $(383)
Other comprehensive income (loss), before reclassifications—
 (120) (120)
Reclassifications to Consolidated Statement of Income3
 13
 16
Balance at June 30, 2016$(39) $(448) $(487)


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

16.14. Noncontrolling Interests

WES a publicly traded consolidated subsidiary, is a limited partnership formed by Anadarko to acquire, own, develop, and operate midstream assets. During the first quarter of 2016, WES issued 1422 million Series A Preferred units to private investors for net proceeds of $440$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. DuringPursuant to an agreement between WES and the second quarterholders of 2016,the Series A Preferred units, 50% of the Series A Preferred units converted into WES issued an additional eight millioncommon units on a one-for-one basis March 1, 2017, with the remaining Series A Preferred units to private investors, pursuant to the full exercise of an option grantedbe converted in connection with the initial issuance, and raised net proceeds of $247 million.May 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 end of 2017,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 534179 thousand Class C units to Anadarko during the sixthree months ended June 30, 2016,March 31, 2017, and 498946 thousand Class C units to Anadarko during 2015. During 2015, WES issued approximately 874 thousand common units to the public for net proceeds of $57 million.2016.
WGP a publicly traded consolidated subsidiary, is a limited partnership formed by Anadarko to own partnership interests in WES. During the three months ended June 30, 2016, Anadarko sold 12.5 million of its WGP common units to the public for net proceeds of $476 million. At June 30, 2016,March 31, 2017, Anadarko’s ownership interest in WGP consisted of an 81.6% limited partner interest and the entire non-economic general partner interest. The remaining 18.4% limited partner interest in WGP was owned by the public.
At June 30, 2016,March 31, 2017, WGP’s ownership interest in WES consisted of a 30.0%29.9% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At June 30, 2016,March 31, 2017, Anadarko also owned an 8.4%8.7% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 60.1%59.9% limited partner interest in WES was owned by the public.


22
Table of Contents
17.ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

15. 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 and WES. See Note 16—14—Noncontrolling Interests for additional information on WGP and WES.

Assets and Liabilities of VIEs The assets of WGP and WES cannot be used by Anadarko for general corporate purposes and are both included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets. The carrying amounts of liabilities related to WGP and WES for which the creditors do not have recourse to other assets of the Company are both included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets.
All outstanding debt for WES at June 30, 2016,March 31, 2017, and December 31, 2015,2016, 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 June 30, 2016,March 31, 2017, and December 31, 2015,2016, 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—Debt and Interest Expense for additional information on WGP and WES long-term debt balances.

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, or debt offerings. See Note 8—Debt and Interest Expense and Note 16—14—Noncontrolling Interests for additional information on WGP and WES financing activity.


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

17. Variable Interest Entities (Continued)

Financial Support Provided to VIEs Concurrent with the closing of its May 2008 initial public offering,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 $4 million for each of the three months ended June 30, 2016March 31, 2017 and 2015, and $8 million for each of the six months ended June 30, 2016 and 2015.2016. The note receivable and related interest income are eliminated in consolidation.
In March 2015, WES acquired the Company’s interest in Delaware Basin JV Gathering LLC.DBJV. The acquisition was financed using a deferred purchase price obligation which requires a cash payment from WES to the Company due on March 31, 2020. The cash payment due to the Company is equal to eight multiplied by the average of WES’s share in DBJV Net Earnings (defined below) for 2018 and 2019 less WES’s share of capital expenditures incurred for DBJV from March 1, 2015 to February 29, 2020. Net Earnings is defined as all revenues less cost of product, operating expenses, and property taxes. The net present value of this obligation was $29$37 million at June 30, 2016,March 31, 2017, and $189$41 million at December 31, 2015.2016. The reduction in the value of the deferred purchase price obligation was primarily due to revisions reflecting a decrease in WES’s estimate of future Net Earnings, partially offset by a decrease in WES’s estimate of capital expenditures to be incurred by DBJV.
In order to reduce WES’s exposure to a majority of the commodity-price risk inherent in certain of their contracts, Anadarko has commodity price swap agreements in place with WES expiring in 2016.on December 31, 2017. WES has recorded a capital contribution from Anadarko in its Consolidated Statement of Equity and Partners’ Capital for the amount by which the swap price exceeds the applicable market price. WES recorded a $16 million capital contribution from Anadarko of $12 million for the sixthree months ended June 30, 2016,March 31, 2017, and a capital contribution of zero$7 million for the sixthree months ended June 30, 2015.March 31, 2016.


23
Table of Contents
18.ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

16. 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:
Six Months Ended 
 June 30,		Three Months Ended 
 March 31,
millions2016 20152017 2016
Cash paid (received)      
Interest, net of amounts capitalized (1)
$427
 $1,621
$308
 $299
Income taxes, net of refunds (2)
(883) 6
1
 (8)
Non-cash investing activities      
Fair value of properties and equipment from non-cash transactions$3
 $126
$549
 $—
Asset retirement cost additions49
 90
61
 27
Accruals of property, plant, and equipment505
 901
608
 623
Net liabilities assumed (divested) in acquisitions and divestitures(36) (29)(82) —
Non-cash investing and financing activities      
Floating production, storage, and offloading vessel construction period obligation$11
 $43
FPSO construction period obligation (1)
$—
 $2
Deferred drilling lease liability7
 —

(1) 
Includes $1.2 billionUpon completion of interest related to the Tronox settlement paymentFPSO in 2015.
(2)
Includes $881 million fromthe third quarter of 2016, the Company reported the construction period obligation as a tax refund related tocapital lease obligation based on the income tax benefit associated withfair value of the Company’s 2015 tax net operating loss carryback.FPSO.


24
19.
Table of Contents
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

17. Segment Information

Anadarko’s business segments are separately managed due to distinct operational differences and unique technology, distribution, and marketing requirements. The Company’s three reporting segments are oil and gas exploration and production, midstream, and marketing. The oil and gas exploration and production segment explores for and produces oil, condensate, natural gas, and NGLs and plans for the development and operation of the Company’s LNG project in Mozambique. The midstream segment engages in gathering, processing, treating, and transporting Anadarko and third-party oil, condensate, natural-gas, and NGLs production.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. The marketing segment sells much of Anadarko’s oil, condensate, natural-gas, and NGLs production as well as third-party purchased volumes.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

19. Segment Information (Continued)

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; exploration expense; depreciation, depletion, and amortization (DD&A); impairments; interest expense; total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives; 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 general and administrative expenses, Deepwater Horizon settlement and related costs included in other operating expenses, loss on early extinguishment of debt, Tronox-related contingent loss, and certain other nonoperating items included in other (income) expense, net. G&A did not relate to the Company’s normal operations.
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. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, 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 that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s operating and financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders.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 or cash flows from operating activities.income. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes:
Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,		 Three Months Ended 
 March 31,
millions2016 2015 2016 2015 2017 2016
Income (loss) before income taxes$(925) $185
 $(2,306) $(4,443) $(178) $(1,381)
Interest expense 223
 220
DD&A 1,115
 1,149
Exploration expense 1,085
 126
(Gains) losses on divestitures, net104
 91
 102
 425
 (804) (2)
Exploration expense76
 103
 202
 1,186
DD&A984
 1,214
 2,133
 2,470
Impairments18
 30
 34
 2,813
 373
 16
Interest expense217
 201
 437
 417
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives371
 (229) 775
 14
 (155) 404
Restructuring charges48
 —
 251
 —
 (1) 203
Other operating expense—
 —
 1
 4
 —
 1
Loss on early extinguishment of debt124
 —
 124
 —
Tronox-related contingent loss—
 —
 —
 5
Certain other nonoperating items(56) —
 (56) 22
Less net income (loss) attributable to noncontrolling interests81
 47
 117
 79
 43
 36
Consolidated Adjusted EBITDAX$880
 $1,548
 $1,580
 $2,834
 $1,615
 $700

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

19.17. Segment Information (Continued)

Information presented below as “Other and Intersegment Eliminations” includes corporate costs, results from hard-minerals royalties, and net cash from settlement of commodity derivatives.derivatives, and net income (loss) attributable to noncontrolling interests. The following summarizes selected financial information for Anadarko’s reporting segments:
millions
Oil and Gas
Exploration
& Production
 Midstream Marketing 
Other and
Intersegment
Eliminations
 Total
Oil and Gas
Exploration
& Production
 Midstream Marketing 
Other and
Intersegment
Eliminations
 Total
Three Months Ended June 30, 2016         
Three Months Ended March 31, 2017         
Sales revenues$1,033
 $141
 $811
 $—
 $1,985
$1,524
 $225
 $1,149
 $—
 $2,898
Intersegment revenues567
 340
 (676) (231) —
871
 361
 (1,024) (208) —
Other—
 —
 —
 34
 34
Total revenues and other (1)
1,600
 481
 135
 (197) 2,019
Operating costs and expenses (2)
790
 219
 177
 (65) 1,121
Other (1)
2
 33
 6
 24
 65
Total revenues and other (2)
2,397
 619
 131
 (184) 2,963
Operating costs and expenses (3)
866
 317
 165
 (43) 1,305
Net cash from settlement of commodity derivatives—
 —
 —
 (60) (60)—
 —
 —
 6
 6
Other (income) expense, net (3)
—
 —
 —
 1
 1
—
 —
 —
 (8) (8)
Net income (loss) attributable to noncontrolling interests (1)
—
 —
 —
 43
 43
Total expenses and other866
 317
 165
 (2) 1,346
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement—
 —
 (2) —
 (2)
Adjusted EBITDAX$1,531
 $302
 $(36) $(182) $1,615
         
Three Months Ended March 31, 2016         
Sales revenues$711

$125

$798

$—

$1,634
Intersegment revenues601

302

(663)
(240)
—
Other (1)
(1)
13

1

25

38
Total revenues and other (2)
1,311

440

136

(215)
1,672
Operating costs and expenses (3)
773

183

176

(89)
1,043
Net cash from settlement of commodity derivatives—

—

—

(103)
(103)
Net income (loss) attributable to noncontrolling interests—
 81
 —
 —
 81
—

—

—

36

36
Total expenses and other790
 300
 177
 (124) 1,143
773

183

176

(156)
976
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement—
 —
 4
 —
 4
—

—

4

—

4
Adjusted EBITDAX$810
 $181
 $(38) $(73) $880
$538

$257

$(36)
$(59)
$700
         
Three Months Ended June 30, 2015         
Sales revenues$1,356
 $191
 $1,090
 $—
 $2,637
Intersegment revenues885
 303
 (954) (234) —
Other—
 —
 —
 90
 90
Total revenues and other (1)
2,241
 494
 136
 (144) 2,727
Operating costs and expenses (2)
832
 234
 192
 (59) 1,199
Net cash from settlement of commodity derivatives—
 —
 —
 (82) (82)
Other (income) expense, net—
 —
 —
 15
 15
Net income (loss) attributable to noncontrolling interests—
 47
 —
 —
 47
Total expenses and other832
 281
 192
 (126) 1,179
Adjusted EBITDAX$1,409
 $213
 $(56) $(18) $1,548
 __________________________________________________________________
(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.
(2)(3) 
Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenseexpenses since these expenses are excluded from Adjusted EBITDAX.
(3)
Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

19. Segment Information (Continued)

millions
Oil and Gas
Exploration
& Production
 Midstream Marketing 
Other and
Intersegment
Eliminations
 Total
Six Months Ended June 30, 2016         
Sales revenues$1,744
 $266
 $1,609
 $—
 $3,619
Intersegment revenues1,168
 642
 (1,339) (471) —
Other—
 —
 —
 72
 72
Total revenues and other (1)
2,912
 908
 270
 (399) 3,691
Operating costs and expenses (2)
1,563
 402
 353
 (154) 2,164
Net cash from settlement of commodity derivatives—
 —
 —
 (163) (163)
Other (income) expense, net (3)
—
 —
 —
 1
 1
Net income (loss) attributable to noncontrolling interests—
 117
 —
 —
 117
Total expenses and other1,563
 519
 353
 (316) 2,119
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement—
 —
 8
 —
 8
Adjusted EBITDAX$1,349
 $389
 $(75) $(83) $1,580
          
Six Months Ended June 30, 2015         
Sales revenues$2,426
 $365
 $2,431
 $—
 $5,222
Intersegment revenues2,002
 605
 (2,145) (462) —
Other—
 —
 —
 160
 160
Total revenues and other (1)
4,428
 970
 286
 (302) 5,382
Operating costs and expenses (2)
1,834
 474
 390
 (96) 2,602
Net cash from settlement of commodity derivatives—
 —
 —
 (172) (172)
Other (income) expense, net (3)
—
 —
 —
 40
 40
Net income (loss) attributable to noncontrolling interests—
 79
 —
 —
 79
Total expenses and other1,834
 553
 390
 (228) 2,549
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement—
 —
 1
 —
 1
Adjusted EBITDAX$2,594
 $417
 $(103) $(74) $2,834
 __________________________________________________________________
(1)
Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.
(2)
Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and other operating expense since these expenses are excluded from Adjusted EBITDAX.
(3)
Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.




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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 natural-gas liquids (NGLs)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 risks
processing volumes and pipeline throughput
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; retroactive royalty or production tax regimes; deepwater drilling and permitting regulations; derivatives reform; changes in state, federal, and foreign income taxes; environmental regulation;regulation, including regulations related to climate change; environmental risks; and liability under international, provincial, federal, regional, state, foreign,tribal, local, and localforeign 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

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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, repay or refinance its debt, and the impact of changes in the Company’s credit ratings
uncertainties associated with acquired properties and businesses
disruptions in international oil NGLs, and condensateNGLs 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
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, 2015,2016, 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, 2015;2016; 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, 2015.2016.

OUTLOOKMANAGEMENT OVERVIEW

During 2015,In 2017, Anadarko continues to optimize and further concentrate its portfolio on higher-return, oil-levered opportunities in areas where it possesses both scale and competitive advantages, namely the oilDelaware and natural-gas industry experienced a significant decrease in commodity prices driven by a global supply/demand imbalance for oil and an oversupply of natural gasDJ basins in the United States. Low commodity prices have continued into 2016U.S. onshore and may exist for an extended period.deepwater Gulf of Mexico. The Company’s revenues, operating results,GOM Acquisition expanded Anadarko’s operated infrastructure and substantial tie-back inventory and doubled its net production from the Gulf of Mexico to approximately 160 MBOE/d, more than 80% of which is comprised of oil. The acquired assets are expected to generate substantial cash flow over the next five years at current strip prices. The Company plans to use the cash flows from operations, capital spending,the Gulf of Mexico as well as from our international cash generating assets to fund growth in the Company’s unconventional assets in the Delaware and future growth rates are highly dependent on the global commodity-price markets, which affect the value the Company receives from its sales of oil, natural gas, and NGLs.
DJ basins. The Company has continued its disciplined and focused approach in 2016 by emphasizing value over growth, preserving and building value through capital allocation, enhancing operational efficiencies, and continuing an active monetization program. Inended the first quarter of 2016,2017 with 14 operated drilling rigs in the Company initiatedDelaware basin and 6 operated drilling rigs in the DJ basin, which compares to 9 operated drilling rigs in the Delaware basin and 5 operated drilling rigs in the DJ basin at year-end 2016. In the deepwater Gulf of Mexico, Anadarko has three floating rigs drilling with a workforce reduction program to align the size and composition of Anadarko’s workforce withfocus on leveraging the Company’s expected future operating and capital plans. Employee notifications related to the workforce reduction program were completed by June 30, 2016. All of the $407 million of expected restructuring charges will be recognized in 2016, with the exception of approximately $10 million of expense for retirement benefits expected to be recognized in the first quarter of 2017.expansive infrastructure position.
The CompanyAnadarko currently estimates a 20162017 initial capital spending range of $3.1$5.4 billion to $3.3$5.7 billion, includingwhich represents an increase of more than 63% from 2016. The estimated capital spending range includes approximately $450$900 million to $490 million$1.0 billion for Western Gas Partners, LP (WES), a publicly traded consolidated subsidiary, excluding any acquisitions made by WES. The Company has currently allocated approximately 65%80% of its 20162017 capital spending budget to development activities, 15% to exploration activities, and 20% to gathering and processing activities and other business activities. The Company currently expects its 2016 capital spending by area to be approximately 40% for the U.S. onshore regionupstream and Alaska, 20% for themidstream and deepwater Gulf of Mexico, 20% for MidstreamMexico; 15% to future value areas, such as deepwater exploration and other (including WES),global LNG; 2% to international cash generation assets, such as oil projects in Algeria and 20% for International.
Ghana; and 3% to corporate activities. The Company’s 2017 initial capital program was designed to leverage its streamlined portfolio and sharpened focus on higher-margin oil production. The Company will continue to evaluate the oil and natural-gas price environments and may adjust its capital spending plans to maintain thewhile maintaining appropriate liquidity and financial flexibility. Anadarko expects that its 2016 capital expenditures will be within its
As an oil and natural-gas exploration and production company, Anadarko’s revenues, operating results, cash flows from operations, capital spending, and asset monetizations. As of June 30, 2016,future growth rates are highly influenced by commodity prices, which affect the value the Company closed monetizations totaling $2.5 billion in 2016, including asset divestitures, the sale of Anadarko’s interest in Springfield Pipeline LLC to WES, the sale of 12.5 million of the Company’s common units in Western Gas Equity Partners, LP (WGP) to the public, and the Company’s conveyance of a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party. These monetizations continue Anadarko’s track record of actively managing its portfolio and reaffirm the Company’s commitment toward strengthening its balance sheet.


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Liquidity  As of June 30, 2016, Anadarko had $1.4 billion of cash on hand plus $5.0 billion of borrowing capacity under its revolving credit facilities.
Anadarko believes that its cash on hand, anticipated operating cash flows, and proceeds from expected future asset monetizations will be sufficient to fund the Company’s projected 2016 operational and capital programs. In response to the current commodity price environment, the Board of Directors (Board) decreased the quarterly dividend from $0.27 per share to $0.05 per share in February 2016. On an annualized basis, the dividend decrease and the workforce reduction program (without consideration for restructuring charges) are expected to have the effect of providing approximately $800 million of available cash to enhance the Company’s operations and financial flexibility. During the second quarter of 2016, the Company used proceedsreceives from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.250 billionsales of its $2.0 billion 6.375% Senior Notes due September 2017 pursuant to a tender offer and to redeem its $1.750 billion 5.950% Senior Notes due September 2016. Also during the second quarter of 2016, Anadarko received cash of $881 million from a tax refund related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback and sold 12.5 million of its common units in WGP to the public for net proceeds of $476 million. Further, Anadarko enters into strategic derivative positions to reduce commodity-price risk and increase the predictability of cash flows. At June 30, 2016, derivative positions covered 26% of Anadarko’s anticipated oil, sales volumes and 1% of its anticipated natural-gas sales volumes for 2016, 41% of its anticipated natural-gas sales volumes and 2% of its anticipated NGLs sales volumes for 2017, and 14% of anticipated natural-gas sales volumes for 2018. These instruments had a fair value of $45 million as of June 30, 2016. See Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. Anadarko believes that the actions taken to enhance the Company’s liquidity position coupled with its asset portfolio and operating and financial performance provide the necessary financial flexibility to fund the Company’s current and long-term operations.

Potential for Future Impairments  The Company did not recognize any material impairments during the six months ended June 30, 2016, although it is reasonably possible that prolonged low or further declines in commodity prices, changes to the Company’s drilling plans in response to lower prices, or increases in drilling or operating costs could result in future property impairments.

OVERVIEW

Anadarko is among the world’s largest independent exploration and production companies. Anadarko is engaged in the exploration, development, production, and marketing of oil, condensate, natural gas, and NGLs, and in the marketing of anticipated production of liquefied natural gas. The Company also engages in the gathering, processing, treating, and transporting of oil, condensate, natural gas, and NGLs. The Company has exploration and production activities in various countries around the world, including activities in the United States, Algeria, Ghana, Mozambique, Colombia, Côte d’Ivoire, New Zealand, Kenya, and other countries.


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Significant operating and financial activities for the secondfirst quarter of 20162017 include the following:

OverallTotal Company
Anadarko’s second-quarteroverall sales-volume product mix increased to 61% liquids in the first quarter of 2017, compared to 53% in the first quarter of 2016, which significantly improved margins.
Anadarko’s first-quarter oil sales volumes averaged 792 thousand barrels of oil equivalent per day (MBOE/d),367 MBbls/d, representing a 6% decrease16% increase from the secondfirst quarter of 2015,2016, primarily due to a decrease in natural-gasincreased volumes from the GOM Acquisition and the startup of TEN offshore Ghana, partially offset by divestitures of U.S. onshore oil and condensategas assets in 2016 and 2017.
U.S. Onshore
Oil sales volumes.volumes in the Delaware basin increased 10 MBbls/d, representing a 46% increase from the first quarter of 2016, due to increased drilling activity.
The Company recognized workforce reduction program expenses of $48WES acquired a third party’s 50% nonoperated interest in the DBJV system in exchange for WES’s 33.75% interest in nonoperated Marcellus midstream assets and $155 million in cash.
Anadarko closed the second quarter for a totaldivestiture of $251 million for the six months ended June 30, 2016. Total program expenses are expected to be $407 million. 
The Company closed $2.5 billion of monetizations year to date, including proceeds receivedits Eagleford and Marcellus assets during the quarter from asset divestitures and the salefor net proceeds of a portion$2.8 billion, prior to final closing adjustments.
Gulf of the Company’s WGP common units to the public.Mexico
U.S. Onshore
Second-quarter liquidsOil sales volumes averaged 291 thousand barrels per day (MBbls/d), representing a 5% decrease from the second quarter of 2015, primarily due to a natural production decline in the Eagleford shale and reduced capital activity in the Wattenberg field.
Second-quarter natural-gas sales volumes averaged 353 MBOE/125 MBbls/d, representing a 6% decrease116% increase from the secondfirst quarter of 2015,2016, primarily due to the September 2015 sale of certain coalbed methane properties in the Rockies, the July 2015 sale of certain U.S. onshore properties in East Texas,GOM Acquisition and natural production declinescontinued tieback activity at Greater Natural Buttes. These decreases were partially offset by improved well performance in the Wattenberg field and the injection of volumes into storage in 2015.several facilities.
Gulf of Mexico
International
Second-quarterFirst-quarter sales volumes averaged 74 MBOE/104 MBbls/d, representing an 11% decreasea 17% increase from the secondfirst quarter of 2015,2016, primarily due to a decrease in natural-gas sales volumes as a result of the last producing well going off line at Independence Hub (IHUB)TEN development project (19% nonoperated participating interest) in December 2015.
Ghana achieving first oil in the third quarter of 2016.
The Shenandoah-5 appraisal well (33% working interest) encountered more than 1,040 net feet of oil pay, extending the eastern limitsInterim mooring of the field.
International
Second-quarter sales volumes averaged 74 MBbls/d, representing an 11% decrease fromFPSO at the second quarter of 2015, primarilyJubilee field in Ghana due to downtime related to a maintenance issue withcommenced in the floating, production, storage, and offloading unit (FPSO) turret bearing.
Financial
Anadarko’s net loss attributable to common stockholders for the secondfourth quarter of 2016 totaled $692 million.and was completed during the first quarter of 2017. Final decisions and approvals will be sought for the long-term turret system solution in mid-2017. It is anticipated that a facility shutdown of up to 12 weeks may be required in the second half of 2017. The partnership is actively seeking optimization solutions to minimize the duration of any shutdown period.
During the quarter, the Company made progress towards finalizing major components of the legal and contractual framework for the LNG project in Mozambique, which will support investment, beginning with the resettlement project, and also position the Company to secure long-term LNG offtake contracts.
Financial
The Company generated $1.2$1.1 billion of cash flow from operations and ended the quarter with $1.4$5.8 billion of cash on hand.cash.
In April 2016, WES issued an additional eight million Series A Preferred units to private investors, pursuant toJanuary 2017, the full exerciseCompany extended the maturity date of an option granted in connection with the initial March 2016 issuance, for net proceeds of $247 million.
The Company used proceeds from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.250 billion of its $2.0 billion 6.375% Senior Notes due September 2017 pursuant to a tender offer and to redeem its $1.750 billion 5.950% Senior Notes due September 2016. The Company recognized a loss of $124 million for the early retirement and redemption of these senior notes, which included $114 million of premiums paid.
In July 2016, WES completed a public offering of $500 million aggregate principal amount of 4.650% Senior Notes due July 2026.364-Day Facility until January 2018.


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FINANCIAL RESULTS
 Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,		 Three Months Ended 
 March 31,
millions except per-share amounts 2016 2015 2016 2015 2017 2016
Oil and condensate, natural-gas, and NGLs sales $1,680
 $2,332
 $3,074
 $4,624
Oil, natural-gas, and NGLs sales $2,454
 $1,394
Gathering, processing, and marketing sales 305
 305
 545
 598
 444
 240
Gains (losses) on divestitures and other, net (70) (1) (30) (265) 869
 40
Revenues and other 1,915
 2,636
 3,589
 4,957
 $3,767
 $1,674
Costs and expenses 2,247
 2,546
 4,785
 9,075
 3,877
 2,538
Other (income) expense 593
 (95) 1,110
 325
 68
 517
Income tax expense (benefit) (314) 77
 (697) (1,315) 97
 (383)
Net income (loss) attributable to common stockholders $(692) $61
 $(1,726) $(3,207) $(318) $(1,034)
Net income (loss) per common share attributable to common stockholders—diluted $(1.36) $0.12
 $(3.39) $(6.32) $(0.58) $(2.03)
Average number of common shares outstanding—diluted 510
 509
 510
 507
 551
 509

The following discussion pertains to Anadarko’s results of operations, financial condition, and changes in financial condition. Any increases or decreases “for the three months ended June 30, 2016,March 31, 2017,” refer to the comparison of the three months ended June 30, 2016,March 31, 2017, to the three months ended June 30, 2015, and any increases or decreases “for the six months ended June 30, 2016,” refer to the comparison of the six months ended June 30, 2016, to the six months ended June 30, 2015.March 31, 2016. 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 such reserves; and operating costs.


Revenues and Sales Volumes
 Three Months Ended June 30, Three Months Ended March 31,
millions except percentages Oil and
Condensate		 
Natural
Gas
 NGLs Total Oil 
Natural
Gas
 NGLs Total
2015 sales revenues $1,616
 $487
 $229
 $2,332
2016 sales revenues $850
 $366
 $178
 $1,394
Changes associated with prices 684
 210
 126
 1,020
Changes associated with sales volumes (114) (34) (7) (155) 129
 (74) (15) 40
Changes associated with prices (377) (133) 13
 (497)
2016 sales revenues $1,125
 $320
 $235
 $1,680
Increase (decrease) vs. 2015 (30)% (34)%
3 %
(28)%
        
 Six Months Ended June 30,
millions except percentages Oil and
Condensate		 
Natural
Gas
 NGLs Total
2015 sales revenues $3,035
 $1,128
 $461
 $4,624
Changes associated with sales volumes (178) (127) (30) (335)
Changes associated with prices (882) (315) (18) (1,215)
2016 sales revenues $1,975
 $686
 $413
 $3,074
Increase (decrease) vs. 2015 (35)% (39)% (10)% (34)%
2017 sales revenues $1,663
 $502
 $289
 $2,454
Increase (decrease) vs. 2016 96% 37% 62% 76%

ChangesThe above table illustrates the effects of the increase in commodity prices and changes associated with sales volumes, forwhich include increases related to the threeGOM Acquisition (primarily oil) and six months ended June 30, 2016, include decreases associated with U.S. onshore asset divestitures.

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divestitures (primarily natural gas).

The following provides Anadarko’s sales volumes for the three and six months ended June 30:March 31:
   Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
   2016 Inc (Dec) vs. 2015 2015 2016 Inc (Dec) vs. 2015 2015
Barrels of Oil Equivalent             
(MMBOE except percentages)             
United States  65
 (6)% 69
 132
 (8)% 144
International  7
 (11) 8
 15
 (13) 17
Total barrels of oil equivalent  72
 (6) 77
 147
 (9) 161
              
Barrels of Oil Equivalent per Day             
(MBOE/d except percentages)             
United States  718
 (6)% 762
 728
 (8)% 796
International  74
 (11) 84
 81
 (13) 94
Total barrels of oil equivalent per day  792
 (6) 846
 809
 (9) 890
 _______________________________________________________________________________
MMBOE—million barrels of oil equivalent
   2017 Inc (Dec) 
 vs. 2016		 2016
Barrels of Oil Equivalent       
(MMBOE except percentages)       
United States  62
 (7)% 67
International  10
 16
 8
Total barrels of oil equivalent  72
 (5) 75
        
Barrels of Oil Equivalent per Day       
(MBOE/d except percentages)       
United States  691
 (6)% 738
International  104
 17
 89
Total barrels of oil equivalent per day  795
 (4) 827

Sales volumes represent actual production volumes adjusted for changes in commodity inventories andas well as natural-gas production volumes provided to satisfy a commitment established in conjunction withunder the Jubilee development plan in Ghana. Anadarko employs marketing strategies to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. For additional information, see Note 6—7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q and Other (Income) Expense—(Gains) Losses on Derivatives, net.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
34
  Three Months Ended 
 March 31,
  2017 Inc (Dec) 
 vs. 2016		 2016
Oil sales revenues (millions) $1,663
 96% $850
       
United States      
Sales volumes—MMBbls 24
 15% 21
MBbls/d 269
 16
 232
Price per barrel $49.23
 76
 $28.04
       
International      
Sales volumes—MMBbls 9
 16% 8
MBbls/d 98
 18
 83
Price per barrel $53.36
 56
 $34.11
       
Total      
Sales volumes—MMBbls 33
 15% 29
MBbls/d 367
 16
 315
Price per barrel $50.34
 70
 $29.65

The following summarizes primary drivers for the change in oil sales revenues:
Table of Contents
millions Change in Revenues Due to Change in Prices Due to Change in Volumes
Three months ended March 31, 2017 vs. 2016 $813
 $684
 $129

Oil and Condensate Sales Volumes, Average Prices and Revenues
  Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
  2016 Inc (Dec) vs. 2015 2015 2016 Inc (Dec) vs. 2015 2015
United States            
Sales volumes—MMBbls 20
 (5)% 21
 41
 (3)% 43
MBbls/d 227
 (5) 240
 229
 (3) 238
Price per barrel $40.25
 (26) $54.14
 $34.07
 (31) $49.23
International            
Sales volumes—MMBbls 6
 (12)% 8
 14
 (13)% 16
MBbls/d 69
 (12) 78
 76
 (13) 88
Price per barrel $46.75
 (23) $60.81
 $39.84
 (30) $57.12
Total            
Sales volumes—MMBbls 26
 (7)% 29
 55
 (6)% 59
MBbls/d 296
 (7) 318
 305
 (6) 326
Price per barrel $41.77
 (25) $55.78
 $35.51
 (31) $51.37
Oil and condensate sales revenues (millions)
 $1,125
 (30) $1,616
 $1,975
 (35) $3,035
 _______________________________________________________________________________
MMBbls—million barrelsThe average oil price received increased for the three months ended March 31, 2017, primarily due to OPEC’s agreement to reduce production for the first six months of 2017, which reduced the global oversupply.

Anadarko’sOil Sales Volumes
2017 vs. 2016  The Company’s oil and condensate sales volumes decreasedincreased by 2252 MBbls/d for the three months ended June 30, 2016, and 21 MBbls/dMarch 31, 2017, primarily due to the following:
U.S. Onshore
Sales volumes for the six months ended June 30, 2016.

Sales volumes in the Rockies decreasedDelaware basin increased by 910 MBbls/d for the three months ended June 30, 2016, and 13 MBbls/d for the six months ended June 30, 2016,March 31, 2017, primarily due to reduced capital activity in the Wattenberg field. continued drilling activity.
Sales volumes for the six months ended June 30, 2016, also decreased as a result of the April 2015 sale of certain enhanced oil recovery (EOR) assets.
International sales volumesDJ basin decreased by 916 MBbls/d for the three months ended June 30, 2016, and 12 MBbls/d for the six months ended June 30, 2016,March 31, 2017, primarily in Ghana due to downtime to address new production and offtake procedures resulting from a maintenance issue withreduced capital investment during the FPSO turret bearing. The partnership has determined a long-term solution to convert the FPSO to a permanently moored facility and is expecting the work program to be completelow commodity price cycle in the first half of 2017. In the meantime, shuttle tankers continue to successfully conduct offtakes. 2016.
Sales volumes for the six months ended June 30, 2016, also decreased as a result of the timing of liftings in Ghana.
Sales volumes in the Southern and Appalachia RegionEagleford decreased by 615 MBbls/d for the three months ended June 30, 2016, and 4 MBbls/d for the six months ended June 30, 2016,March 31, 2017, primarily due to a natural production declinethe sale of the assets in the Eagleford shale, partially offset by higher sales volumes due to continued development in the Delaware basin.March 2017.
Gulf of Mexico
Sales volumes in the Gulf of Mexico were relatively flatincreased by 67 MBbls/d for the three months ended June 30, 2016, andMarch 31, 2017, primarily due to the GOM Acquisition in December 2016.
International
Sales volumes for Ghana increased by 510 MBbls/d for the sixthree months ended June 30, 2016, primarily from the Lucius development, which achieved first oil in the first quarter of 2015.

Anadarko’s average oil price received decreased for the three and six months ended June 30, 2016,March 31, 2017, primarily due to continued global oversupply and concernsliftings from the TEN development project, which came online late in the third quarter of slowing oil demand growth.

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2016.

Natural-Gas Sales Volumes, Average Prices, and Revenues
  Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
  2016 Inc (Dec) vs. 2015 2015 2016 Inc (Dec) vs. 2015 2015
United States            
Sales volumes—Bcf 199
 (7)% 215
 409
 (11)% 461
MMcf/d 2,188
 (7) 2,354
 2,245
 (11) 2,545
Price per Mcf $1.61
 (29) $2.28
 $1.68
 (31) $2.45
Natural-gas sales revenues (millions)
 $320
 (34) $487
 $686
 (39) $1,128
 _______________________________________________________________________________
Bcf—billion cubic feet
MMcf/d—million cubic feet per day
Mcf—thousand cubic feet
  Three Months Ended 
 March 31,
  2017 Inc (Dec) 
 vs. 2016		 2016
Natural-gas sales revenues (millions) $502
 37 % $366
       
United States      
Sales volumes—Bcf 167
 (20)% 210
MMcf/d 1,859
 (19) 2,303
Price per Mcf $3.00
 71
 $1.75

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 March 31, 2017 vs. 2016 $136
 $210
 $(74)

Natural-Gas Prices
The average natural-gas price Anadarko received increased for the three months ended March 31, 2017, primarily due to the industry’syear-over-year production declines. This lower domestic production resulted in lower gas in storage despite lower residential and commercial demand due to warmer than normal temperatures in the first quarter of 2017.

Natural-Gas Sales Volumes
2017 vs. 2016The Company’s natural-gas sales volumes decreased by 166444 MMcf/d for the three months ended June 30, 2016, and 300 MMcf/d forMarch 31, 2017, primarily due to the six months ended June 30, 2016.following:
U.S. Onshore
Sales volumes in the Rockies for Eagleford decreased by 15061 MMcf/d for the three months ended June 30, 2016, and 161 MMcf/d for the six months ended June 30, 2016,March 31, 2017, primarily due to the September 2015 sale of certain coalbed methane properties and a natural production decline at Greater Natural Buttes, partially offset by higher 2016 sales volumesthe assets in the Wattenberg field as a result of improved well performance.
March 2017.
Sales volumes in the Gulf of Mexicofor Marcellus decreased by 4043 MMcf/d for the three months ended June 30, 2016, and 89 MMcf/d for the six months ended June 30, 2016,March 31, 2017, primarily as a result of the last producing well going off line at IHUB in December 2015.due to natural production declines. The assets were sold on March 31, 2017.
Sales volumes in the Southern and Appalachia Region increaseddecreased by 24402 MMcf/d for the three months ended June 30, 2016,March 31, 2017, primarily due to the injectionsale of certain Wyoming and East Texas/Louisiana assets in 2016.
Gulf of Mexico
Sales volumes into storage in 2015, third-party infrastructure downtime in the Marcellus shale in 2015, and continued development in the Delaware basin. The increaseincreased by 44 MMcf/d for the three months ended June 30, 2016, was partially offset by decreased sales volumes in 2016 as a result of the July 2015 sale of certain U.S. onshore properties in East Texas and a natural production decline in the Eagleford shale. Sales volumes for the six months ended June 30, 2016, decreased by 50 MMcf/d,March 31, 2017, primarily due to the decreases discussed above, partially offset by higher 2016 sales volumesGOM Acquisition in the Delaware basin due to continued development.
December 2016.

The average natural-gas price Anadarko received decreased for the three and six months ended June 30, 2016, primarily due to lower weather-driven residential and commercial demand, which have contributed to sustained high gas storage levels.

Natural-Gas Liquids Sales Volumes, Average Prices, and Revenues
 Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,		 Three Months Ended 
 March 31,
 2017 Inc (Dec) 
 vs. 2016		 2016
Natural-gas liquids sales revenues (millions) $289
 62 % $178
      
United States      
Sales volumes—MMBbls 10
 (10)% 11
MBbls/d 112
 (9) 122
Price per barrel $26.57
 77
 $14.98
      
International      
Sales volumes—MMBbls 1
 14 % —
MBbls/d 6
 15
 6
Price per barrel $37.57
 65
 $22.78
 2016 Inc (Dec) vs. 2015 2015 2016 Inc (Dec) vs. 2015 2015      
Total                  
Sales volumes—MMBbls 13
 (3)% 12
 24
 (7)% 25
 11
 (9)% 11
MBbls/d 131
 (3) 136
 130
 (7) 140
 118
 (8) 128
Price per barrel $19.60
 6
 $18.50
 $17.49
 (4) $18.24
 $27.17
 77
 $15.32
Natural-gas liquids sales revenues (millions)
 $235
 3
 $229
 $413
 (10) $461

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 March 31, 2017 vs. 2016 $111
 $126
 $(15)

NGLs Prices
The average NGLs price received increased for the three months ended March 31, 2017, primarily due to increasedpropane and butane prices stemming from higher demand.

NGLs Sales Volumes
2017 vs. 2016  The Company’s NGLs sales volumes decreased by 10 MBbls/d for the three months ended March 31, 2017, primarily due to the following:
U.S. Onshore
Sales volumes for DJ basin increased by 9 MBbls/d for the three months ended March 31, 2017, primarily due to improved well performance.
Sales volumes decreased by 22 MBbls/d for the three months ended March 31, 2017, primarily due to the sale of certain Wyoming and East Texas/Louisiana assets in 2016.
Gulf of Mexico
Sales volumes increased by 5 MBbls/d for the three months ended June 30, 2016, and by 10 MBbls/d for the six months ended June 30, 2016,March 31, 2017, primarily due to increased ethane rejectionthe GOM Acquisition in the United States in 2016.

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December 2016.

Gathering, Processing, and Marketing
 Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,		 Three Months Ended 
 March 31,
millions except percentages 2016 Inc (Dec) vs. 2015 2015 2016 Inc (Dec) vs. 2015 2015 2017 Inc (Dec) 
 vs. 2016		 2016
Gathering, processing, and marketing sales $305
 — % $305
 $545
 (9)% $598
 $444
 85% $240
Gathering, processing, and marketing expense 252
 (1) 255
 467
 (8) 509
 351
 63
 215
Total gathering, processing, and marketing, net $53
 6
 $50
 $78
 (12) $89
 $93
 NM
 $25

Gathering and processing sales includes revenue from the sale of NGLs and remaining residue gas extracted from natural gas purchased from third parties and processed by Anadarko as well as fee revenue earned by providing gathering, 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 other operating and transportation expenses related to the Company’s costs to perform gathering, processing, and marketing activities.
Gathering, processing, and marketing, net was relatively flatincreased by $68 million for the three months ended June 30,March 31, 2017, primarily related to an increase in throughput volumes at the DBM complex in the Delaware basin due to downtime throughout the first quarter of 2016 and decreased by $11 million forhigher natural-gas and NGLs marketing margins during the six months ended June 30, 2016, primarily due to plant downtime in 2016 and the 2015 divestituresfirst quarter of certain midstream assets, partially offset by higher marketing margins.2017.

Gains (Losses) on Divestitures and Other, net
  Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
millions except percentages 2016 Inc (Dec) vs. 2015 2015 2016 Inc (Dec) vs. 2015 2015
Gains (losses) on divestitures $(104) (14)% $(91) $(102) 76 % $(425)
Other 34
 (62) 90
 72
 (55) 160
Total gains (losses) on divestitures and other, net $(70) NM
 $(1) $(30) 89
 $(265)
 _______________________________________________________________________________
NM—not meaningful
  Three Months Ended 
 March 31,
millions except percentages 2017 Inc (Dec) 
 vs. 2016		 2016
Gains (losses) on divestitures, net $804
 NM
 $2
Other 65
 71% 38
Total gains (losses) on divestitures and other, net $869
 NM
 $40

Gains (losses) on divestitures and other, net includes gains (losses) on divestitures and other operating revenues, including hard-minerals royalties, earnings from equity investments, and other revenues.

2016
The Company recognized a loss of $53 million associated with the June divestiture of certain U.S. onshore assets in the Rockies for net proceeds of $593 million.
The Company recognized a loss of $50 million on assets held for sale associated with the divestiture of certain U.S. onshore assets that is expected to close in the third quarter of 2016.
2015
The Company recognized losses of $340 million associated with the April divestiture of certain EOR assets in the Rockies, with a sales price of $703 million, for net proceeds of $675 million.
The Company recognized a loss of $97 million associated with the July divestiture of certain oil and gas properties and related midstream assets in East Texas, with a sales price of $440 million, for net proceeds of $425 million.
The Company recognized income of $63 million duringFor the three months ended June 30, 2015,March 31, 2017, Anadarko divested certain non-core U.S. onshore assets and $117 million during the six months ended June 30, 2015, related to the settlementrecognized net gains of a royalty lawsuit associated with a property $804 million.
See Note 3—Acquisitions, Divestitures, and Assets Held for Salein the GulfNotes to Consolidated Financial Statements under Item 1 of Mexico.this Form 10-Q for additional information.

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Costs and Expenses

The following provides Anadarko’s total costs and expenses for three months ended March 31:
  Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
  2016 Inc (Dec) vs. 2015 2015 2016 Inc (Dec) vs. 2015 2015
Oil and gas operating (millions)
 $202
 (11)% $226
 $410
 (21)% $522
Oil and gas operating—per BOE 2.80
 (4) 2.93
 2.78
 (14) 3.24
Oil and gas transportation (millions)
 246
 (13) 283
 488
 (17) 588
Oil and gas transportation—per BOE 3.41
 (7) 3.67
 3.32
 (9) 3.65
millions2017 2016
Oil and gas operating$258
 $208
Oil and gas transportation249
 242
Exploration1,085
 126
Gathering, processing, and marketing351
 215
General and administrative269
 449
Depreciation, depletion, and amortization1,115
 1,149
Production, property, and other taxes155
 117
Impairments373
 16
Other operating expense22
 16
Total$3,877
 $2,538

BOE—barrel of oil equivalent
Oil and Gas Operating Expenses
  Three Months Ended 
 March 31,
  2017 Inc (Dec) 
 vs. 2016		 2016
Oil and gas operating (millions)
 $258
 24% $208
Oil and gas operating—per BOE 3.60
 30
 2.77

Oil and gas operating expense decreasedincreased by $24$50 million for the three months ended June 30, 2016,March 31, 2017, primarily as a result of divestitures in 2015. Oil and gas operating expense decreased by $112 million for the six months ended June 30, 2016, due to the following:
higher overall operating costs of $54 million primarily related to the GOM Acquisition
higher non-operated costs of $32 million in Ghana partially related to the completion of interim mooring of the Jubilee FPSO during the first quarter of 2017 along with production from the TEN development, which came online late in the third quarter of 2016
lower expenses of $56$21 million as a result of U.S. onshore asset divestitures in 2015; lower workover costs of $31 million in Ghana, the Gulf of Mexico, and the Rockies; and lower nonoperated costs of $18 million across all areas.
The related costs per BOE decreasedincreased by $0.13$0.83 for the three months ended June 30, 2016, and by $0.46 for the six months ended June 30, 2016.
Oil and gas transportation expense decreased by $37 million for the three months ended June 30, 2016, and $100 million for the six months ended June 30, 2016,March 31, 2017, primarily due to lower sales volumes across all areas. The related costs per BOE decreased by $0.26 for the three months ended June 30, 2016, and by $0.33 for the six months ended June 30, 2016, due to lowerincreased costs as discussed above and shifting to a result of decreased sales volumes.higher-return, oil-levered portfolio.

Exploration Expense
 Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,		 Three Months Ended 
 March 31,
millions 2016 2015 2016 2015 2017 2016
Exploration Expense            
Dry hole expense $(5) $13
 $6
 $42
 $476
 $11
Impairments of unproved properties 15
 18
 39
 998
 537
 24
Geological and geophysical expense 32
 16
 69
 38
 37
 37
Exploration overhead and other 34
 56
 88
 108
 35
 54
Total exploration expense $76
 $103
 $202
 $1,186
 $1,085
 $126

For the three months ended June 30, 2016,March 31, 2017, total exploration expense decreasedincreased by $27 million.$959 million primarily related to the following:

Dry Hole Expense
Dry hole expense decreased by $18 million. The Company recognized $13 million in the second quarter of 2015 primarily associated with wells in the Rockies.
Geological and geophysical expense increased by $16$465 million, primarily due to seismicthe following:
•
The Company expensed suspended exploratory well costs of $435 million during the three months ended March 31, 2017, related to the Shenandoah project in the Gulf of Mexico. See Note 5—Suspended Exploratory Well Costs in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
The Company expensed $41 million during the three months ended March 31, 2017, due to unsuccessful drilling activities in Colombia in 2016.primarily associated with the Gulf of Mexico and an international property.
Exploration overhead
Impairments of Unproved Properties
•
The Company recognized $532 million of impairments of unproved Gulf of Mexico properties during the three months ended March 31, 2017, of which $467 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. See Note 5—Suspended Exploratory Well Costs in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

General and otherAdministrative Expenses
  Three Months Ended 
 March 31,
millions except percentages 2017 Inc (Dec) 
 vs. 2016		 2016
General and administrative $269
 (40)% $449

For the three months ended March 31, 2017, G&A decreased by $22$180 million primarily due to lower employee-related expenses in 2016.
For the six months ended June 30, 2016, total exploration expense decreased by $984 million.
Dry hole expense decreased by $36 million. The Company recognized $42charges of $203 million in 2015 primarily associated with wells in Mozambique.
Impairments of unproved properties decreased by $959 million. The Company recognized a $935 million impairment in the first quarter of 2015 related to the Company’s unproved Greater Natural Buttes properties as a result of lower commodity prices.
Geological and geophysical expense increased by $31 million primarily due to seismic activities in Colombia in 2016.
Exploration overhead and other decreased by $20 million primarily due to lower employee-related expenses in 2016.

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  Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
millions except percentages 2016 Inc (Dec) vs. 2015 2015 2016 Inc (Dec) vs. 2015 2015
General and administrative $305
 10 % $278
 $754
 29 % $585
Depreciation, depletion, and amortization 984
 (19) 1,214
 2,133
 (14) 2,470
Other taxes 157
 4
 151
 274
 (18) 333
Impairments 18
 (40) 30
 34
 (99) 2,813
Other operating expense 7
 17
 6
 23
 (67) 69

General and administrative expense (G&A) included $48 million of charges2016 associated with the workforce reduction program for the three months ended June 30, 2016, and $251 million for the six months ended June 30, 2016. Excluding the workforce reduction expenses, G&A decreased by $21 million for the three months ended June 30, 2016, and by $82 million for the six months ended June 30, 2016, primarily due to lower employee-related expenses primarily associated with decreased benefit, bonus plan, and salary expenses.program. See Note 12—11—Restructuring Charges in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Depreciation, depletion, and amortization expense decreased by $230 million for
Impairments

The Company recognized the following impairments:
  Three Months Ended 
 March 31,
millions 2017 2016
Oil and gas exploration and production    
U.S. onshore properties $—
 $4
Gulf of Mexico properties 204
 1
Cost-method investment —
 1
Midstream 169
 10
Total $373
 $16

Impairments during the three months ended June 30, 2016, and by $337 million for the six months ended June 30, 2016, primarily due to the following:
lower costs for U.S. onshore and midstream properties as a result of 2015 asset impairments
lower 2016 sales volumes associated with U.S. onshore properties
lower costs and sales volumes as a result of 2015 divestitures of certain gathering and processing facilities
cost revisions related to certain asset retirement obligations associated with fully depreciated assets

Other taxes decreased by $59 million for the six months ended June 30, 2016, primarily due to lower ad valorem taxes of $36 million and lower Algerian exceptional profits taxes of $23 million. These decreasesMarch 31, 2017, were primarily due to lower commodity prices and lower sales volumes.

Impairment expense for the six months ended June 30, 2015, included $2.3 billion related to the Company’s Greater Natural Buttes oil and gas properties and $449 million for related midstream properties in the Rockies, which were impairedGulf of Mexico due to lower forecasted commodity prices.

Other operating expense decreased by $46 million for the six months ended June 30, 2016, primarilyprices and a U.S. onshore midstream property due to expenses in 2015 for the early termination of a drilling rig.

Other (Income) Expense
  Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
millions 2016 2015 2016 2015
Interest Expense        
Debt and other $259
 $244
 $517
 $498
Capitalized interest (42) (43) (80) (81)
Total interest expense $217
 $201
 $437
 $417

Interest expense increased by $16 million for the three months ended June 30, 2016, and by $20 million for the six months ended June 30, 2016, primarily due to the $3.0 billion March 2016 Senior Notes issuances.

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  Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
millions 2016 2015 2016 2015
Loss on early extinguishment of debt $124
 $—
 $124
 $—

During the second quarter of 2016, the Company used proceeds from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.250 billion of its $2.0 billion 6.375% Senior Notes due September 2017 pursuant to a tender offer and to redeem its $1.750 billion 5.950% Senior Notes due September 2016. The Company recognized a loss of $124 million for the early retirement and redemption of these senior notes, which included $114 million of premiums paid.
  Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
millions 2016 2015 2016 2015
(Gains) Losses on Derivatives, net        
(Gains) losses on commodity derivatives, net $94
 $1
 $66
 $(52)
(Gains) losses on interest-rate derivatives, net 213
 (312) 538
 (107)
Total (gains) losses on derivatives, net $307
 $(311) $604
 $(159)

(Gains) losses on derivatives, net represents the changes in fair value of the Company’s derivative instrumentsreduced throughput fee as a result of changes in commodity prices and interest rates, contract modifications, and settlements. An interest-rate swap agreement was settled in March 2016, resulting in a cash payment of $193 million. The Company settled commodity derivatives resulting in cash receipts of $60 million for the three months ended June 30, 2016, $81 million for the three months ended June 30, 2015, $165 million for the six months ended June 30, 2016, and $172 million for the six months ended June 30, 2015.producer’s bankruptcy.
For additional information,further discussion related to impairments, including the potential for future impairments, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
  Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
millions 2016 2015 2016 2015
Other (Income) Expense, net        
Interest income $(4) $(2) $(7) $(7)
Other (51) 17
 (48) 69
Total other (income) expense, net $(55) $15
 $(55) $62

For the three months ended June 30, 2016, other income, net increased by $70 million.
As a result of a Chapter 11 bankruptcy declaration by a third party, the U.S. Department of the Interior ordered Anadarko to perform the decommissioning of a production facility and related wells, previously sold to the third party. The Company accrued the costs to decommission the facility and wells in prior years. During the second quarter of 2016, the Company substantially completed the decommissioning of the wells. Final costs were lower than expected and the Company recognized income of $56 million as a result of the reduced obligation.

For the six months ended June 30, 2016, other income, net increased by $117 million.
Other income, net increased by $78 million related to the decommissioning obligation mentioned above.
Favorable changes in foreign currency gains/losses of $34 million were primarily associated with foreign currency held in escrow pending final determination of the Company’s Brazilian tax liability attributable to the 2008 divestiture of the Peregrino field offshore Brazil.



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Income Tax Expense
  Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
millions except percentages 2016 2015 2016 2015
Income tax expense (benefit) $(314) $77
 $(697) $(1,315)
Income (loss) before income taxes (925) 185
 (2,306) (4,443)
Effective tax rate 34% 42% 30% 30%

The Company reported a loss before income taxes for the three and six months ended June 30, 2016, and the six months ended June 30, 2015. As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The variance from the 35% U.S. federal statutory rate for the three and six months ended June 30, 2016 and 2015, was primarily attributable to the non-deductible Algerian exceptional profits tax for Algerian income tax purposes and the tax impact from foreign operations. In addition, the decrease from the 35% U.S. federal statutory rate for the three and six months ended June 30, 2016, was attributable to non-deductible goodwill related to divestitures and net changes in uncertain tax positions.

Net Income (Loss) Attributable to Noncontrolling Interests
  Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
millions except percentages 2016 2015 2016 2015
Net income (loss) attributable to noncontrolling interests $81
 $47
 $117
 $79
Public ownership in WES, limited partnership interest 60.1% 55.2% 60.1% 55.2%
Public ownership in WGP, limited partnership interest 18.4% 12.7% 18.4% 12.7%

See Note 16—Noncontrolling Interests4—Impairments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Other (Income) Expense

The following provides Anadarko’s other (income) expense for the three months ended March 31:

41
millions 2017 2016
Interest expense $223
 $220
(Gains) losses on derivatives, net (1)
 (147) 297
Other (income) expense, net (8) —
Total $68
 $517

(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—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Income Tax Expense (Benefit)
Table
  Three Months Ended 
 March 31,
millions except percentages 2017 2016
Income tax expense (benefit) $97
 $(383)
Income (loss) before income taxes (178) (1,381)
Effective tax rate (54)% 28%

The Company reported a loss before income taxes for the three months ended March 31, 2017 and 2016. As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. 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 Contentsthe world. Additionally, state income taxes (net of federal income tax benefit), non-deductible Algerian exceptional profits tax for Algerian income tax purposes, net changes in uncertain tax positions, and pre-tax income allocated to noncontrolling interest typically impact the Company’s effective tax rate. The Company’s effective tax rate decreased from 28% for three months ended March 31, 2016, to (54)% for the three months ended March 31, 2017, primarily due to the impact from the items discussed above.
For additional information on income taxes, see Note 9—Income Taxesin the Notes to Consolidated Financial
Statements under Item 1 of this Form 10-Q.


LIQUIDITY AND CAPITAL RESOURCES
 Six Months Ended 
 June 30,		 Three Months Ended 
 March 31,
millions 2016 2015 2017 2016
Net cash provided by (used in) operating activities $1,092
 $(3,261) $1,123
 $(137)
Net cash provided by (used in) investing activities (965) (2,785) 1,722
 (973)
Net cash provided by (used in) financing activities 329
 849
 (198) 3,119

Overview  Anadarko believes that its cash on hand, anticipated operating cash flows, and proceeds from expected future asset monetizations will be sufficient to fund the Company’s projected 2016 operational and capital programs. In addition, the Company has available borrowing capacity to supplement its working capital needs. The Company continuously monitors its liquidity needs and evaluates available funding alternatives in light of current and expected conditions. Anadarko has a variety of funding sources available, including cash, on hand, 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, and the Company’s credit facilities.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.

EffectsDuring the first quarter of Moody’s Credit Rating Downgrade  In February 2016, Standard2017, Anadarko closed on the divestitures of its U.S. onshore Eagleford and Poor’s affirmed Anadarko’s “BBB” long-term debt credit ratingMarcellus assets for net proceeds of $2.8 billion. As of March 31, 2017, Anadarko had $5.8 billion of cash plus $5.0 billion of borrowing capacity under its RCFs. Anadarko believes that its current available cash and changed the outlook from stableanticipated operating cash flows will be sufficient to negative. Later in February 2016, Moody’s Investors Service (Moody’s) loweredfund the Company’s projected 2017 and long-term debt credit rating from “Baa2”operational and capital programs. Current available cash provides the flexibility to “Ba1,” which is below investment grade. In March 2016, Fitch Ratings affirmed Anadarko’s “BBB” long-term debt credit rating and changed the outlook from stable to negative.
As a result of Moody’s downgrade of Anadarko’s credit rating to a level that is below investment grade, the Company’s credit thresholds with certain derivative counterparties were reduced and in some cases eliminated, which required the Company to increase the amount of collateral posted with derivative counterparties when the Company’s net trading position is a liability in excess of the contractual threshold. No counterparties have requested termination or full settlement of derivative positions. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.3 billion (net of collateral) at each of June 30, 2016, and December 31, 2015. The amount of cash posted as collateral pursuant to the contractual requirements applicable to derivative instruments with financial institutions was $599 million at June 30, 2016, and $58 million at December 31, 2015.
The Moody’s credit rating downgrade required Anadarko to post collateralaccelerate activity in the formDelaware and DJ basins or acquire bolt-on positions in these core areas. The Company continuously monitors its liquidity position and evaluates available funding alternatives in light of letters of credit or cash as financial assurance of its performance under certain contractual arrangements such as pipeline transportation contractscurrent and oil and gas sales contracts. The amount of letters of credit or cash provided as assurance of the Company’s performance under these types of contractual arrangements with respect to credit-risk-related contingent features was $274 million at June 30, 2016, and zero at December 31, 2015.
Also in February 2016, Moody’s downgraded Anadarko’s commercial paper program credit rating, which essentially eliminated the Company’s access to the commercial paper market. As a result, the Company has not issued commercial paper notes since the downgrade, but instead has used its 364-day senior unsecured revolving credit facility (364-Day Facility) for short-term working capital requirements, as needed.expected conditions.


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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 entering into commodity derivatives. Sales 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.
Anadarko generatedCash provided by operating activities was $1.1 billion of cash from operating activities duringfor the sixthree months ended June 30, 2016, which included the $881 million tax refund relatedMarch 31, 2017, $1.2 billion higher compared to the income tax benefit associated withsame period of 2016. This increase was primarily a result of higher sales revenues in 2017 due to the Company’s 2015 tax net operating loss carryback,impact of higher commodity prices and increased oil sales volumes as well as the $159.5 million payment of the Clean Water Act (CWA) penalty and the payment of $182$79 million related to severance costs and retirement benefits in connection with the workforce reduction program. Cash usedprogram in operating activities for the same period of 2015 was $3.3 billion, which included the $5.2 billion Tronox settlement payment. Excluding the impact of the tax refund and payments for the CWA penalty, severance costs and retirement benefits, and the Tronox settlement, operating cash flows for the six months ended June 30, 2016, decreased by $1.4 billion primarily due to decreased sales revenues as a result of lower commodity prices.2016.


Investing Activities

Capital Expenditures  The following presents the Company’s capital expenditures for the sixthree months ended June 30:March 31:
millions 2016 2015 2017 2016
Cash Flows from Investing Activities        
Additions to properties and equipment and dry hole costs $1,879
 $3,501
Additions to properties and equipment (1)
 $1,194
 $1,022
Adjustments for capital expenditures        
Changes in capital accruals (249) (310) 58
 (130)
Other (6) 32
 3
 4
Total capital expenditures (1)(2)
 $1,624
 $3,223
 $1,255
 $896
 ________________________________________________________________________________________
(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)
Includes WES capital expenditures of $260$286 million for the sixthree months ended June 30, 2016,March 31, 2017, and $278$140 million for the sixthree months ended June 30, 2015.March 31, 2016. Capital expenditures exclude the FPSO capital lease asset.

The Company’s capital expenditures decreasedincreased by $1.6 billion$359 million for the sixthree months ended June 30, 2016, as reduced developmentMarch 31, 2017, primarily due to $258 million related to increased U.S. onshore acreage acquisitions and exploration activity resultedcosts in the following:
decreased development costsGulf of $1.2 billion primarily in the Rockies and the Southern and Appalachia Region
decreased exploration costs of $214 million primarily in Colombia and Mozambique
decreased gathering, processing, and other costsMexico coupled with increased spending of $154 million primarily duerelated to lower expenditures for plants and gatheringthe development of the Company’s midstream assets in the RockiesDelaware and DJ basins.

Property Exchange On March 17, 2017, WES acquired a third party’s 50% 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. After the acquisition, the DBJV system is 100% owned by WES and consolidated by Anadarko. 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.

Carried-Interest ArrangementsIn the third quarter of 2014, the Company entered into a carried-interest arrangement that requires 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 third-party funding is expected to cover Anadarko’s future capital costs in the development through 2020. At June 30, 2016, $141March 31, 2017, $151 million of the $442 million carry obligation had been funded.
In the second quarter of 2013, the Company entered into a carried-interest arrangement that requires a third party to fund $860 million of Anadarko’s capital costs in exchange for a 12.75% working interest in the Heidelberg development, located in the Gulf of Mexico. At June 30, 2016, $853 million of the $860 million carry obligation had been funded.

Divestitures  During the sixthree months ended June 30, 2016,March 31, 2017, Anadarko received pretax salesnet proceeds related to property divestiture transactions of $900 million$2.9 billion from divestitures, primarily related to the divestituressale of certainthe Company’s U.S. onshore assets in the Rockies, East Texas/Louisiana,Eagleford and West Texas.Marcellus oil and gas assets. See Note 3—Acquisitions, Divestitures, and Assets Held for Sale in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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Investments  During the six months ended June 30, 2016, the Company made capital contributions of $46 million for equity investments, which are included in other, net under Investing Activities in the Consolidated Statements of Cash Flows. These contributions were primarily associated with joint ventures for pipelines.

Financing Activities
millions except percentagesJune 30, 
 2016		 December 31, 2015March 31, 
 2017		 December 31, 
 2016
Anadarko$12,206
 $12,204
WES3,092
 3,091
WGP28
 28
Total debt$15,673
 $15,668
$15,326
 $15,323
Total equity14,600
 15,457
15,079
 15,497
Debt to total capitalization ratio51.8% 50.3%50.4% 49.7%

Senior Notes  The following summarizes the Company’s debt activity related to senior notes for the six months ended June 30, 2016:
millionsFace Value Description
Issuances$800
 4.850% Senior Notes due 2021
 1,100
 5.550% Senior Notes due 2026
 1,100
 6.600% Senior Notes due 2046
Repayments(1,250) 6.375% Senior Notes due 2017
 (1,750) 5.950% Senior Notes due 2016
 (17) Tangible equity units (TEUs) - senior amortizing notes

During the second quarter of 2016, the Company used proceeds from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.250 billion of its $2.0 billion 6.375% Senior Notes due September 2017 pursuant to a tender offer and to redeem its $1.750 billion 5.950% Senior Notes due September 2016. The Company recognized a loss of $124 million for the early retirement and redemption of these senior notes, which included $114 million of premiums paid.
In July 2016, WES completed a public offering of $500 million aggregate principal amount of 4.650% Senior Notes due July 2026. Net proceeds were used to repay a portion of the amount outstanding under its five-year $1.2 billion senior unsecured revolving credit facility maturing in February 2019 (WES RCF).

Debt Activity  
Revolving Credit FacilitiesAnadarko RCFs  Anadarko has a $3.0 billion five-year senior unsecured revolving credit facility maturing in January 2021 (Five-Year Facility) and the 364-DayFive-Year Facility that matures in January 2017.2021 and a $2.0 billion 364-Day Facility. In January 2017, the Company extended the maturity date of the 364-Day Facility until January 2018. At March 31, 2017, the Company had no outstanding borrowings under the Five-Year Facility or the 364-Day Facility.

WES and WGP RCFs  WES has a $1.2 billion RCF whichthat matures in February 2020 and is expandable to $1.5 billion. InAt March 2016, 31, 2017, WES had no outstanding borrowings under its RCF, had outstanding letters of credit of $5 million, and had available borrowing capacity of $1.195 billion.
WGP entered intohas a three-year $250 million senior secured revolving credit facility maturingRCF that matures in March 2019 (WGP RCF), whichand is expandable to $500 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions.
The following summarizes the Company’s debt activity related to revolving credit facilities for the six months ended June 30, 2016:
millions2016 Description
Borrowings$1,750
 364-Day Facility
 530
 WES RCF
 28
 WGP RCF
Repayments(1,750) 364-Day Facility
 (290) WES RCF

Anadarko Credit FacilitiesDuring the six months ended June 30, 2016, borrowings under the 364-Day Facility were primarily used for general short-term working capital needs. At June 30, 2016, the Company had no outstanding borrowings under the Five-Year Facility or the 364-Day Facility.


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WES and WGP Credit FacilitiesDuring the six months ended June 30, 2016, WES borrowings were primarily used for general corporate purposes, including the funding of a portion of its acquisition of Springfield Pipeline LLC and capital expenditures. At June 30, 2016, WES had outstanding borrowings under its RCF of $540 million at an interest rate of 1.77%, had outstanding letters of credit of $5 million, and had available borrowing capacity of $655 million.
During the six months ended June 30, 2016, WGP borrowings were used to fund the purchase of WES common units. At June 30, 2016,March 31, 2017, WGP had outstanding borrowings under its RCF of $28 million at an interest rate of 2.72%2.99% and had available borrowing capacity of $222 million.

For additional information on the revolving credit facilities, such as years of maturity, interest rates, and covenants,Company’s RCFs, see Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Commercial Paper Program  The Company has a commercial paper program, which allows for a maximum of $3.0 billion of unsecured commercial paper notes and is supported by the Company’s Five-Year Facility. As a result of Moody’s downgrade of Anadarko’s commercial paper program credit rating, the Company’s access to the commercial paper market was essentially eliminated. The Company repaid $250 million of commercial paper notes during the first quarter of 2016, and at June 30, 2016, there were no outstanding borrowings under the commercial paper program. See Note 8—Debt and Interest Expensein the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information.

Debt Maturities  Anadarko may from time to time seek to retire or purchase its outstanding debt through cash purchases and/or exchanges for other debt or equity securities in open market purchases, privately negotiated transactions, or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions, and other factors. The amounts involved may be material.
At June 30, 2016,March 31, 2017, Anadarko’s scheduled debt maturities during 20162017 consisted of $17$34 million of senior amortizing notes associated with the TEUs. Anadarko’s Zero-Coupon Senior Notes due 2036 (Zero Coupons)Zero Coupons can be put to the Company in October of each year, in whole or in part, for the then-accreted value, which will be $839$883 million at the next put date in October 2016. The Company classified the Zero Coupons as long-term debt on the Company’s Consolidated Balance Sheet at June 30, 2016, as Anadarko has the ability and intent to refinance these obligations using long-term debt, should the put be exercised. At June 30, 2016, Anadarko’s scheduled debt maturities during 2017 consisted of $750 million of 6.375% Senior Notes due September 2017 and $34 million of senior amortizing notes associated with the TEUs.2017.
For additional information on the Company’s debt instruments, such as transactions during the period, years of maturity, and interest rates, seeNote 8—Debt in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Equity Transactions  WES can issue common units to the public under its $500 million continuous offering program, which allows for an aggregate of $500 million of WES common units. The remaining amount available to be issued under this program was $442 million at March 31, 2017.
During the first quarter of 2016, WES issued 14 million Series A Preferred units to private investors for net proceeds of $440 million. In April 2016, WES issued an additional eight million Series A Preferred units to private investors, pursuant to the full exercise of an option granted in connection with the initial issuance, and Interest Expenseraised net proceeds of $248 million.
For additional information on WES Series A Preferred units, see Note 14—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Derivative Instruments  The Company’sFor information on derivative instruments, are subject to individually negotiated credit provisions that may require collateral ofincluding cash or letters of credit depending on the derivatives portfolio valuation versus negotiated credit thresholds. These credit thresholds may also require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered, such as if the Company’s credit rating from major credit rating agencies declines to a level that is below investment grade. 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. The amount of cash collateral provided by the Company on its interest-rate derivatives with an other-than-insignificant financing element pursuant to the contractual requirements applicable to derivative instruments with financial institutions was $592 million at June 30, 2016, and $58 million at December 31, 2015. Additionally, an interest-rate swap agreement was settled in March 2016, resulting in a cash payment of $193 million. At June 30, 2016, Anadarko expects additional net cash outlays of $52 million in 2016 related to interest-rate derivative settlements.
For additional information,flow treatment, see Note 6—7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q and Effects of Moody’s Credit Rating Downgrade above.


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Conveyance of Future Hard Minerals Royalty RevenuesDuring the first quarter of 2016, the Company conveyed a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party for $413 million, net of transaction costs. For additional information, see Note 10—Conveyance of Future Hard Minerals Royalty Revenues in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Common Stock Dividends  Anadarko paid dividends of $51 million to its common stockholders during the six months ended June 30, 2016, and $277of $28 million during the sixthree months ended June 30, 2015.March 31, 2017, and $25 million during the three months ended March 31, 2016. In response to the current commodity-price environment, the BoardCompany decreased the Company’s quarterly dividend from $0.27 per share to $0.05 per share in February 2016. Anadarko has paid a dividend to its common stockholders on a quarterly basis since becoming a public company in 1986.
The amount of future dividends paid to Anadarko common stockholders will beis determined by the Board on a quarterly basis and is based on the Company’s earnings, financial conditions, 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.

Equity Transactions  Anadarko sold 12.5 million of its WGP common units to the public for net proceeds of $476 million, which were used for general corporate purposes. WES has a continuous offering program, which allows the issuance of up to an aggregate of $500 million of WES common units. The remaining amount available to be issued under this program was $442 million at June 30, 2016. During the first quarter of 2016, WES issued 14 million Series A Preferred units to private investors for net proceeds of $440 million. During the second quarter of 2016, WES issued an additional eight million Series A Preferred units to private investors, pursuant to the full exercise of an option granted in connection with the initial issuance, for net proceeds of $247 million.

Distributions to Noncontrolling Interest Owners  WES distributedDistributions to its unitholders other than Anadarko and WGP an aggregate of $127 million duringnoncontrolling interest owners primarily relate to the six months ended June 30, 2016, and $111 million during the six months ended June 30, 2015. WES has made quarterly distributions to its unitholders since its initial public offering (IPO) in the second quarter of 2008, and has increased its distribution from $0.30 per common unitfollowing for the third quarter of 2008 to $0.830 per common unit for the second quarter of 2016 (to be paid in August 2016).
For the three months ended June 30, 2016, the WES Series A Preferred unitholders will receive a quarterly distribution of $0.68 per unit for the Series A Preferred units issued in March 2016, and a quarterly distribution of $0.68 per unit for the Series A Preferred units issued in April 2016, prorated for the 77-day period the units were outstanding during the second quarter of 2016, or an aggregate $14 million (to be paid in August 2016). For the three months ended March 31, 2016, the WES Series A Preferred unitholders received a quarterly distribution of $0.68 per unit, prorated for the 18-day period the units were outstanding during the first quarter, or an aggregate $2 million (paid in May 2016).31:
WGP distributed to its unitholders other than Anadarko an aggregate of $23 million during the six months ended June 30, 2016, and $17 million during the six months ended June 30, 2015. 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 $0.43375 per unit for the second quarter of 2016 (to be paid in August 2016).
millions 2017 2016
WES distributions to unitholders (excluding Anadarko and WGP) (1)
 $68
 $63
WES distributions to Series A Preferred unitholders (2)
 15
 —
WGP distributions to unitholders (excluding Anadarko) (3)
 19
 11

(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 $0.875 per common unit for the first quarter of 2017 (to be paid in May 2017).
(2)
WES has 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 (to be paid in May 2017).
(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 $0.49125 per unit for the first quarter of 2017 (to be paid in May 2017).

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.


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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 6—7—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 PurposesThe Company had derivative instruments in place to reduce the price risk associated with future production of 1525 MMBbls of oil 349and 284 Bcf of natural gas and 1 MMBbls of NGLs at June 30, 2016,March 31, 2017, with a net derivative asset position of $45 million.$4 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $116$111 million,, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $109 million.$110 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 PurposesAt June 30, 2016,March 31, 2017, the Company had a net derivative asset position of $7$9 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 RISKBorrowings, if any, under each of the 364-Day Facility, the Five-Year Facility, the WES RCF, and the WGP RCF are subject to variable interest rates. The balance of Anadarko’s long-term debt on the Company’s Consolidated Balance Sheets has fixed interest rates. The Company has $2.9 billion of LIBOR-based obligations based on the London Interbank Offered Rate (LIBOR) 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 LIBOR would not materially impact the Company’s interest cost, it would affect the fair value of outstanding fixed-rate debt.
At June 30, 2016,March 31, 2017, the Company had a net derivative liability position of $1.8$1.3 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 $75 million.$91 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 6—7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.


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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 June 30, 2016.March 31, 2017.

Changes in Internal Control over Financial Reporting

There were no changes in Anadarko’s internal control over financial reporting during the secondfirst quarter of 20162017 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1.  Legal Proceedings

GENERALThe 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 U.S. Environmental Protection Agency and the state of WyomingEPA 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 matter will result in a fine or penalty in excess of $100,000.
Anadarko E&P Onshore LLC, a wholly owned subsidiary of the Company, is currently in negotiations with the Pennsylvania Department of Environmental Protection concerning enforcement over a produced water release in Pennsylvania in 2015. 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 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.
See Note 11—10—Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q, which is incorporated herein by reference, for a discussion of material developments with respect tolegal matters previously reported inthat have arisen since the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, and material matters that have arisen since the filing of such report.2016.

Item 1A.  Risk Factors

There have been no material changes from the risk factors included under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2015.2016.

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 secondfirst quarter of 2016:2017:
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
April 1 - 30, 2016 7,745
 $49.91
 —
 $—
May 1 - 31, 2016 4,346
 $49.42
 —
 $—
June 1 - 30, 2016 6,354
 $53.44
 —
 $—
Total 18,445
 $51.01
 —
 $—
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
January 1 - 31, 2017 21,117 $71.08
 —
 $—
February 1 - 28, 2017 2,968 $69.47
 —
 $—
March 1 - 31, 2017 307,298 $62.52
 —
 $—
Total 331,383 $63.13
 —
 $—
 ____________________________________________________________
(1) 
During the secondfirst quarter of 2016,2017, all purchased shares related to stock received by the Company for the payment of withholding taxes due on employee share issuances under share-based compensation plans.

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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, filed as Exhibit 3.1 to Form 8-K filed on September 21, 2015
 10(i) Form of Award Letter for
First Amendment to 364-Day Revolving Credit Agreement, dated January 13, 2017, among Anadarko Petroleum Corporation, 2008 Director Compensation Plan Annual Deferred Shares (2016)JPMorgan Chase Bank, N.A., filed as Exhibit 10 (iii) to Form 10-Q filed on May 2, 2016
(ii)Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as Amendedadministrative agent, and Restated Effective as of May 10, 2016,the additional lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on May 16, 2016January 20, 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

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
  ANADARKO PETROLEUM CORPORATION
                               (Registrant) 
   
July 26, 2016May 2, 2017By:/s/ ROBERT G. GWIN
  
Robert G. Gwin
Executive Vice President, Finance and Chief Financial Officer

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