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, ~~2016~~2017

[ ] 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,~~13, 2017, is shown below:



Title of Class		Number of Shares Outstanding
Common Stock, par value $0.10 per share		~~510,457,469~~560,358,149

TABLE OF CONTENTS



PART I		Page
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three and Six Months Ended June 30, ~~2016~~2017 and ~~2015~~2016	23
	Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, ~~2016~~2017 and ~~2015~~2016	34
	Consolidated Balance Sheets at June 30, ~~2016,~~2017, and December 31, ~~2015~~2016	45
	Consolidated Statement of Equity for the Six Months Ended June 30, ~~2016~~2017	56
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, ~~2016~~2017 and ~~2015~~2016	67
	Notes to Consolidated Financial Statements	78
	Note 1 - Summary of Significant Accounting Policies	78
	Note 2 - Inventories	810
	Note 3 - Acquisitions, Divestitures, and Assets Held for Sale	811
	Note 4 - Impairments	912
	Note 5 - ~~Suspended~~ Exploratory Well Costs	1013
	Note 6 - ~~Derivative Instruments~~Current Liabilities	1013
	Note 7 - ~~Tangible Equity Units~~Derivative Instruments	1614
	Note 8 - Debt ~~and Interest Expense~~	1619
	Note 9 - Income Taxes	1921
	Note 10 - ~~Conveyance of Future Hard Minerals Royalty Revenues~~Contingencies	1922
	Note 11 - ~~Contingencies~~Restructuring Charges	2022
	Note 12 ~~- Restructuring Charges~~	21
	~~Note 13~~ - Pension Plans and Other Postretirement Benefits	2223
	Note 13 - Stockholders’ Equity	24
	Note 14 ~~- Stockholders’ Equity~~	23
	~~Note 15 - Accumulated Other Comprehensive Income (Loss)~~	23
	~~Note 16~~ - Noncontrolling Interests	24
	Note 1715 - Variable Interest Entities	24
	~~Note 18 - Supplemental Cash Flow Information~~	25
	Note 1916 - Supplemental Cash Flow Information	26
	Note 17 - Segment Information	2526
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2930
	Cautionary Statement About Forward-Looking Statements	29
	~~Outlook~~	30
	Management Overview	3132
	Financial Results	33
	Liquidity and Capital Resources	4243
	Recent Accounting Developments	46
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47
Item 4.	Controls and Procedures	48
PART II
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49
Item 6.	Exhibits	50

COMMONLY USED TERMS AND DEFINITIONS

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

~~Table~~364-Day Facility - Anadarko’s $2.0 billion 364-day senior unsecured RCF maturing in January 2018

APC RCF - Anadarko’s $3.0 billion senior unsecured RCF maturing in January 2021

ASU - Accounting Standards Update

Bcf - Billion cubic feet

BOE - Barrels of ~~Contents~~oil equivalent

CBM - Coalbed methane

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

FPSO - Floating production, storage, and offloading unit

G&A - General and administrative expenses

GAAP - U.S. Generally Accepted Accounting Principles

GOM Acquisition - The 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

NTO - Notice to Operators

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 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.~~

~~Table of Contents~~

~~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 June 30,						Six Months Ended June 30,
millions except per-share amounts	2017			2016			2017			2016
Revenues and Other
Oil sales	$	1,422		$	1,125		$	3,085		$	1,975
Natural-gas sales	319			320			821			686
Natural-gas liquids sales	214			235			503			413
Gathering, processing, and marketing sales	464			305			908			545
Gains (losses) on divestitures and other, net	297			(70		)	1,166			(30		)
Total	2,716			1,915			6,483			3,589
Costs and Expenses
Oil and gas operating	233			202			491			410
Oil and gas transportation	229			246			478			488
Exploration	535			76			1,620			202
Gathering, processing, and marketing	359			252			710			467
General and administrative	291			305			560			754
Depreciation, depletion, and amortization	1,037			984			2,152			2,133
Production, property, and other taxes	135			157			290			274
Impairments	10			18			383			34
Other operating expense	12			7			34			23
Total	2,841			2,247			6,718			4,785
Operating Income (Loss)	(125		)	(332		)	(235		)	(1,196		)
Other (Income) Expense
Interest expense	227			217			450			437
Loss on early extinguishment of debt	2			124			2			124
(Gains) losses on derivatives, net	32			307			(115		)	604
Other (income) expense, net	(14		)	(55		)	(22		)	(55		)
Total	247			593			315			1,110
Income (Loss) Before Income Taxes	(372		)	(925		)	(550		)	(2,306		)
Income tax expense (benefit)	(38		)	(314		)	59			(697		)
Net Income (Loss)	(334		)	(611		)	(609		)	(1,609		)
Net income (loss) attributable to noncontrolling interests	81			81			124			117
Net Income (Loss) Attributable to Common Stockholders	$	(415	)	$	(692	)	$	(733	)	$	(1,726	)

Per Common Share
Net income (loss) attributable to common stockholders—basic	$	(0.76	)	$	(1.36	)	$	(1.34	)	$	(3.39	)
Net income (loss) attributable to common stockholders—diluted	$	(0.76	)	$	(1.36	)	$	(1.34	)	$	(3.39	)
Average Number of Common Shares Outstanding—Basic	552			510			552			510
Average Number of Common Shares Outstanding—Diluted	552			510			552			510
Dividends (per Common Share)	$	0.05		$	0.05		$	0.10		$	0.10

See accompanying Notes to Consolidated Financial Statements.

Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED ~~BALANCE SHEETS~~STATEMENTS 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 June 30,						Six Months Ended June 30,
millions	2017			2016			2017			2016
Net Income (Loss)	$	(334	)	$	(611	)	$	(609	)	$	(1,609	)
Other Comprehensive Income (Loss)
Adjustments for derivative instruments
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	1			2			2			5
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	(1		)	(1		)	(1		)	(2		)
Total adjustments for derivative instruments, net of taxes	—			1			1			3
Adjustments for pension and other postretirement plans
Net gain (loss) incurred during period	19			(24		)	15			(190		)
Income taxes on net gain (loss) incurred during period	(6		)	9			(5		)	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	62			34			71			42
Income taxes on amortization of net actuarial (gain) loss to general and administrative expense	(23		)	(13		)	(26		)	(16		)
Amortization of net prior service (credit) cost to general and administrative expense	(6		)	(6		)	(12		)	(21		)
Income taxes on amortization of net prior service (credit) cost to general and administrative expense	2			3			4			8
Total adjustments for pension and other postretirement plans, net of taxes	48			3			47			(107		)
Total	48			4			48			(104		)
Comprehensive Income (Loss)	(286		)	(607		)	(561		)	(1,713		)
Comprehensive income (loss) attributable to noncontrolling interests	81			81			124			117
Comprehensive Income (Loss) Attributable to Common Stockholders	$	(367	)	$	(688	)	$	(685	)	$	(1,830	)

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

See accompanying Notes to Consolidated Financial Statements.

Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED ~~STATEMENT OF EQUITY~~BALANCE 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	June 30, 2017			December 31, 2016
ASSETS
Current Assets
Cash and cash equivalents ($189 and $359 related to VIEs)	$	6,008		$	3,184
Accounts receivable (net of allowance of $17 and $14)
Customers ($69 and $70 related to VIEs)	834			1,007
Others ($6 and $80 related to VIEs)	820			721
Other current assets	322			354
Total	7,984			5,266
Properties and Equipment
Cost	64,316			69,013
Less accumulated depreciation, depletion, and amortization	35,800			36,845
Net properties and equipment ($5,348 and $5,050 related to VIEs)	28,516			32,168
Other Assets ($597 and $609 related to VIEs)	2,134			2,226
Goodwill and Other Intangible Assets ($1,207 and $1,221 related to VIEs)	5,714			5,904
Total Assets	$	44,348		$	45,564

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable
Trade ($176 and $234 related to VIEs)	$	1,626		$	1,617
Other	273			303
Short-term debt	44			42
Current asset retirement obligations	277			129
Other current liabilities	934			1,237
Total	3,154			3,328
Long-term Debt	15,436			15,281
Other Long-term Liabilities
Deferred income taxes	4,232			4,324
Asset retirement obligations ($140 and $140 related to VIEs)	2,717			2,802
Other	4,153			4,332
Total	11,102			11,458

Equity
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 573.9 million and 572.0 million shares issued)	57			57
Paid-in capital	11,941			11,875
Retained earnings	887			1,704
Treasury stock (21.4 million and 20.8 million shares)	(1,070		)	(1,033		)
Accumulated other comprehensive income (loss)	(343		)	(391		)
Total Stockholders’ Equity	11,472			12,212
Noncontrolling interests	3,184			3,285
Total Equity	14,656			15,497
Total Liabilities and Equity	$	44,348		$	45,564

Parenthetical references reflect amounts as of June 30, 2017, and December 31, 2016.

See accompanying Notes to Consolidated Financial Statements.

Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED ~~STATEMENTS~~STATEMENT OF ~~CASH FLOWS~~EQUITY

(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)	—		—			(733		)	—			—			124			(609		)
Common stock issued ⁽¹⁾	—		85			—			—			—			—			85
Dividends—common stock	—		—			(56		)	—			—			—			(56		)
Repurchase of common stock	—		—			—			(37		)	—			—			(37		)
Subsidiary equity transactions	—		(16		)	—			—			—			(11		)	(27		)
Distributions to noncontrolling interest owners	—		—			—			—			—			(214		)	(214		)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	—		—			—			—			1			—			1
Adjustments for pension and other postretirement plans	—		—			—			—			47			—			47
Cumulative effect of accounting change	—		(3		)	(28		)	—			—			—			(31		)
Balance at June 30, 2017	$	57	$	11,941		$	887		$	(1,070	)	$	(343	)	$	3,184		$	14,656


⁽¹⁾	Represents share-based compensation expense.

See accompanying Notes to Consolidated Financial Statements.

Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
millions	2017			2016
Cash Flows from Operating Activities
Net income (loss)	$	(609	)	$	(1,609	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	2,152			2,133
Deferred income taxes	(172		)	(820		)
Dry hole expense and impairments of unproved properties	1,466			45
Impairments	383			34
(Gains) losses on divestitures, net	(1,009		)	102
Loss on early extinguishment of debt	2			124
Total (gains) losses on derivatives, net	(115		)	610
Operating portion of net cash received (paid) in settlement of derivative instruments	5			165
Other	157			203
Changes in assets and liabilities
(Increase) decrease in accounts receivable	7			922
Increase (decrease) in accounts payable and other current liabilities	(278		)	(553		)
Other items, net	(9		)	(264		)
Net cash provided by (used in) operating activities	1,980			1,092
Cash Flows from Investing Activities
Additions to properties and equipment	(2,296		)	(1,879		)
Divestitures of properties and equipment and other assets	3,460			900
Other, net	52			14
Net cash provided by (used in) investing activities	1,216			(965		)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	159			5,275
Repayments of debt	(31		)	(5,425		)
Financing portion of net cash received (paid) for derivative instruments	(125		)	(727		)
Increase (decrease) in outstanding checks	(32		)	(159		)
Dividends paid	(56		)	(51		)
Repurchase of common stock	(37		)	(31		)
Issuance of common stock	—			30
Sale of subsidiary units	—			1,163
Distributions to noncontrolling interest owners	(214		)	(159		)
Proceeds from conveyance of future hard minerals royalty revenues, net of transaction costs	—			413
Payments of future hard minerals royalty revenues conveyed	(25		)	—
Other financing activities	(11		)	—
Net cash provided by (used in) financing activities	(372		)	329
Effect of Exchange Rate Changes on Cash	—			(1		)
Net Increase (Decrease) in Cash and Cash Equivalents	2,824			455
Cash and Cash Equivalents at Beginning of Period	3,184			939
Cash and Cash Equivalents at End of Period	$	6,008		$	1,394

See accompanying Notes to Consolidated Financial Statements.

Table of Contents

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~~sale of oil, ~~condensate,~~ natural gas, and ~~natural gas liquids (NGLs),~~NGLs and in ~~the marketing of anticipated production of liquefied natural gas (LNG).~~advancing its Mozambique LNG project toward a final investment decision. 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 Statements~~accompanying unaudited consolidated financial statements have been prepared in ~~conformity~~accordance with ~~generally accepted accounting principles~~GAAP 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-year~~current-period presentation. These ~~Consolidated Financial Statements~~interim financial statements should be read in conjunction with the ~~Consolidated Financial Statements~~consolidated financial statements and accompanying notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2015.~~2016.

During the second quarter of 2017, the Company revised its reportable segments to reflect how management currently reviews financial information and makes operating decisions. The Company has reclassified prior period amounts to conform to the current period’s presentation. See Note 17—Segment Information for additional information on the change in reportable segments.

The ~~Consolidated Financial Statements~~consolidated financial statements include the accounts of Anadarko and subsidiaries in which Anadarko holds, directly or indirectly, more than 50% of the voting rights and ~~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~~that Anadarko has the ability to exercise significant influence over operating and financial policies and VIEs for which Anadarko is not the primary beneficiary are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for the Company’s proportionate share of earnings, losses, and distributions. Other investments are carried at original cost. Investments accounted for using the equity method and cost method are ~~reported as a component of~~included in other assets.

Recently ~~Issued~~Adopted Accounting Standards ~~The Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2015-03,~~ASU 2017-01, ~~Interest—Imputation~~Business Combinations (Topic 805): Clarifying the Definition of ~~Interest (Subtopic 835-30)—Simplifying~~a Business, assists in determining whether a transaction should be accounted for as an acquisition or disposal of assets or as a business. This ASU provides a screen that when substantially all of the ~~Presentation~~fair value of ~~Debt Issuance Costs~~the 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 related~~a substantive process that together significantly contribute to ~~revolving credit facilities,~~the ability to create an output to be ~~presented in the balance sheet as~~considered a ~~direct deduction from the carrying amount~~business. The Company’s adoption of ~~the related debt liability, rather than as an asset. The Company adopted these ASUs~~this 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 businesses. The ~~adoption resulted in a reclassification that reduced other current assets~~Company’s dispositions of the Eagleford and ~~short-term debt by $1 million~~Eaglebine oil and ~~reduced other assets~~gas properties during the first half of 2017 were not considered businesses under this ASU and ~~long-term debt by $82 million on the Company’s Consolidated Balance Sheet at December 31, 2015.~~therefore not allocated goodwill, see Note 3—Acquisitions, Divestitures, and Assets Held for Sale.

~~The FASB issued~~ ASU ~~2015-02,~~2016-16, ~~Consolidation~~Income Taxes (Topic ~~810)—Amendments~~740): 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 with~~2017, 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 subsidiaries~~first 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.

Table of Contents

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies (Continued)

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

New Accounting Standards Issued But Not Yet Adopted ASU 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period and presentation of the remaining components of net benefit cost in a separate line item outside operating items. Additionally, only the service cost component of net benefit cost will be eligible for capitalization. The ~~FASB issued~~Company will adopt this ASU ~~2016-02,~~on January 1, 2018, with retrospective presentation of the service cost component and the other components of net benefit cost in the income statement and prospective presentation for the capitalization of the service cost component of net benefit cost in assets. Upon adoption, non-service cost components of net periodic benefit costs of $225 million for the year ended 2016 and $69 million for the six months ended June 30, 2017 will be reclassified to other (income) expense, net, from G&A; oil and gas operating; gathering, processing, and marketing; and exploration expense. The Company does not expect any other material changes upon adoption of this ASU.

ASU 2016-18, ~~Leases~~Statement of Cash Flows (Topic ~~842).~~ 230): Restricted Cash,~~This ASU~~ requires an entity to explain the ~~lessees~~changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to ~~recognize~~provide a ~~lease liability~~reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and ~~a right-of-use asset for all leases, including operating leases, with a term greater~~restricted cash equivalents are presented in more than ~~12 months~~one line item on the balance ~~sheet and disclose key information about their leasing transactions.~~sheet. This ASU is effective for annual and interim periods beginning ~~in 2019.~~after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The Company ~~is evaluating the impact of~~will adopt this ASU on January 1, 2018, and does not expect the adoption ~~of this ASU~~to have a material impact 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 ~~FASB issued~~ Company will adopt this ASU on January 1, 2018, and does not expect the adoption to have a material impact on its Consolidated Statement of Cash Flows.

Table of Contents

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 ~~required~~developing accounting policies to ~~adopt~~address the ~~new standard in~~provisions of the ~~first quarter of 2018 using one of two retrospective application methods. The~~ASU. While the Company does not currently expect net earnings to be materially impacted, the Company is ~~continuing~~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 ~~this~~the ASU ~~and has not determined the impact this standard may have~~ on its accounting policies, internal controls, and consolidated financial statements and related disclosures ~~or decided upon~~and has not finalized any estimates of the potential impacts. The Company will adopt this new standard on January 1, 2018, using the 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 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, and a modified retrospective approach is required for all comparative periods presented. The Company plans to elect certain practical expedients when implementing the new lease standard, which means the Company will not have to reassess the accounting for contracts that commenced prior to adoption. The Company is continuing to analyze its portfolio of contracts to assess the application of this ASU to certain types of contracts and the impact that adoption will have on its consolidated financial statements. The Company is also evaluating its current lease administration systems and business processes.

2. Inventories

The following summarizes the major classes of inventories included in other current assets:


millions	June 30, 2016		December 31, 2015		June 30, 2017		December 31, 2016
Oil	$	111	$	116	$	120	$	169
Natural gas	28		36		15		38
NGLs	77		64		78		106
Total inventories	$	216	$	216	$	213	$	313

Table of Contents

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

3. Acquisitions, Divestitures, and Assets Held for Sale

~~For~~Acquisition On December 15, 2016, the Company closed the GOM Acquisition for $1.8 billion using a portion of the net proceeds from the 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. Fair-value measurements of the assets acquired and liabilities assumed at the acquisition date were finalized during the quarter ended June 30, 2017. 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 recognized a gain of $126 million as a result of this transaction. After the acquisition, the DBJV system is 100% owned by WES and consolidated by Anadarko.

Divestitures and Assets Held for Sale The following summarizes the proceeds received and gains (losses) recognized on divestitures and assets held for sale for the six months ended June 30:



millions	2017		2016
Proceeds received, net of closing adjustments	$	3,460	$	900
Gains (losses) on divestitures, net	1,009		(102		)

2017 During the six months ended June 30, 2017, the Company divested of the following U.S. onshore assets:

Eagleford assets, in South Texas, in the Exploration and Production reporting segment for net proceeds of $2.1 billion and a net gain of $729 million

Eaglebine assets, in Southeast Texas, in the Exploration and Production reporting segment for net proceeds of $534 million and a net gain of $281 million

Utah CBM assets, in the Exploration and Production and Midstream reporting segments for net proceeds of $70 million and a net loss of $52 million

Marcellus assets, in Pennsylvania, in the Exploration and Production and Midstream reporting segments for net proceeds of $758 million and net losses of $129 million in the fourth quarter of 2016 and $54 million for the six months ended June 30, 2017

At June 30, 2017, the Company’s Consolidated Balance Sheet included long-term assets of $185 million, which included $35 million of goodwill, and long-term liabilities of $14 million associated with Marcellus Exploration and Production assets held for sale. As of June 30, 2017, $196 million was held in escrow by the purchaser, pending regulatory approval.

2016 During the six months ended June 30, 2016, the ~~Company received $900 million in net proceeds from~~Company’s divestitures ~~and recognized net losses of $102 million from divestitures and assets held for sale.~~

~~Divestitures~~ ~~The following divestitures~~were primarily related to the following U.S. onshore assets ~~that were~~ included in the ~~oil~~Exploration and ~~gas exploration and production~~Production reporting segment:

~~The Company sold certain U.S. onshore~~Wamsutter assets, in ~~East Texas/Louisiana with a sales price of $107 million,~~Wyoming, for net proceeds of ~~$99~~$593 million and ~~recognized~~ a ~~gain~~net loss of ~~$13 million.~~$53 million

~~The Company sold certain U.S. onshore~~Steward assets, in West Texas, for net proceeds of $138 million, with no gain or loss ~~recognized.~~recognized

~~The Company sold certain U.S. onshore~~

East Chalk assets, in ~~the Rockies~~East Texas/Louisiana, for net proceeds of ~~$593~~$99 million and ~~recognized~~ a ~~loss~~net gain of ~~$53 million.~~$13 million

~~Assets Held for Sale~~ ~~Certain~~ U.S. onshore Ozona assets included in the ~~oil~~Exploration and ~~gas exploration~~Production and ~~production and midstream~~Midstream reporting segments satisfied criteria to be considered held for sale during the second quarter of 2016, at which time the Company remeasured them to their current fair value using a market approach and Level 2 fair-value measurement and recognized a loss of $50 million. The sale of these assets ~~is expected to close~~closed in the third quarter of 2016.

Gains and losses on assets held for sale are included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income. At June 30, 2016, the balances of assets and liabilities associated with assets held for sale were not material.

811

Table of Contents

ANADARKO PETROLEUM CORPORATION

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
millions Impairment
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 properties 1
—
2
—
Cost-method investment ⁽²⁾
1
32
2
32
Midstream
Long-lived assets held for use 11
2
21
5
Other
Long-lived assets held for use 5
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 properties 17
—
25
—
Cost-method investment ⁽²⁾
1
32
1
32
Midstream
Long-lived assets held for use 8
199
484
202
Total $ 30
$ 243
$ 2,813
$ 1,537



	Three Months Ended				Six Months Ended
millions	Impairment		Fair Value⁽¹⁾		Impairment		Fair Value⁽¹⁾
June 30, 2017
Exploration and production
U.S. onshore properties	$	2	$	3	$	2	$	3
Gulf of Mexico properties	7		—		211		231
Midstream	—		9		169		58
Other	1		—		1		—
Total	$	10	$	12	$	383	$	292


⁽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 six months ended June 30, ~~2015,~~2017, were primarily related to ~~the Company’s Greater Natural Buttes~~ oil and gas ~~and midstream~~ properties in the ~~Rockies, which were impaired~~Gulf of Mexico due to lower forecasted commodity ~~prices.~~

~~In addition~~prices 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 $555 million of impairments of unproved Gulf of Mexico properties during the six months ended June 30, 2017, primarily due to an impairment of $463 million 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—Exploratory Well Costs.

Potential for Future Impairments

Oil price sensitivity At June 30, 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 $2.1 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 $800 million.

Natural-gas price sensitivity At June 30, 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 $1.0 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 further~~significant declines in commodity prices, further changes to the Company’s drilling plans in response to lower prices, reduction of proved and probable reserve estimates, or increases in drilling or operating costs could result in ~~future~~other additional impairments.

Table of Contents

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

5. ~~Suspended~~ Exploratory Well Costs

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

In the first quarter of 2017, the Company expensed exploratory well costs of $435 million related to the Shenandoah project in the Gulf of Mexico. 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 commodity-price environment, the Company suspended further appraisal activities.

During the second quarter of 2017, the Company expensed exploratory well costs of $241 million related to the Grand Fuerte area in Colombia due to insufficient progress on contractual and fiscal reforms needed for a deepwater gas development. All leases remain contractually in good standing.

During the second quarter of 2017, the Company also expensed exploratory well costs of $119 million in Côte d’Ivoire due to unsuccessful drilling activities in the south channel of the Paon prospect and in Block CI-527.

The Company’s suspended exploratory well costs were $888 million at June 30, 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 exhibiting~~include wells that have sufficient ~~quantities of hydrocarbons~~reserves to justify ~~potential development~~completion as a producing well and ~~where management~~sufficient progress is ~~actively pursuing efforts to assess whether~~being 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 six months ended June 30, 2017, $392 million of suspended exploratory well costs previously capitalized for greater than one year at December 31, 2016, were charged to exploration expense.

6. Current Liabilities

Accounts Payable Accounts payable, trade included liabilities of $230 million at June 30, 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:



millions	June 30, 2017		December 31, 2016
Accrued income taxes	$	55	$	6
Interest payable	245		244
Production, property, and other taxes payable	215		239
Accrued employee benefits	183		355
Other	236		393
Total other current liabilities	$	934	$	1,237

Table of Contents

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)~~.

~~Table of Contents~~

A~~NADARKO 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~~: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)	857		250
Average price per MMBtu
Ceiling sold price (call)	$	3.64	$	3.54
Floor purchased price (put)	$	2.85	$	2.75
Floor sold price (put)	$	2.10	$	2.00

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.

Table of Contents

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~~ 8 Bcf at June 30, 2017, and 2 Bcf at December 31, ~~2015~~,2016, that were entered into to mitigate commodity-price risk related to fixed-price purchase and sales contracts and storage activity.

~~Table of Contents~~

A~~NADARKO 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).~~ LIBOR.

In ~~February 2016, in exchange for amended terms with certain counterparties,~~June 2017, the Company ~~modified the mandatory termination dates from 2021 to 2018 and, in some cases, the related fixed interest rates on~~amended certain interest-rate swaps with an aggregate notional principal amount of ~~$500~~$625 million, extending the mandatory termination dates from 2018 to 2020, 2022, and 2023 in exchange for cash payments of approximately $57 million. ~~Additionally,~~In July 2017, the Company amended an interest-rate swap ~~agreement was settled~~with a notional principal amount of $125 million, extending the mandatory termination date from 2018 to 2022 in ~~March 2016, resulting in~~exchange for a cash payment of ~~$193~~approximately $15 million.

At June 30, ~~2016~~,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~~2023 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 Notes 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, the accreted value of the Zero Coupons will be $839 million. See ~~Note 8—Debt and Interest Expense~~.future debt maturities. Depending on market conditions, liability-management actions, or other factors, the Company may enter into offsetting interest-rate swap positions or settle or amend certain or all of the currently outstanding interest-rate swaps. The Company had the following outstanding interest-rate swaps at June 30, 2017:



millions except percentages			Mandatory	Weighted-Average
Notional Principal Amount		Reference Period	Termination Date	Interest Rate
$	125	September 2016 – 2046	September 2018	6.782%
$	550	September 2016 – 2046	September 2020	6.418%
$	125	September 2016 – 2046	September 2022	6.835%
$	200	September 2017 – 2047	September 2018	6.049%
$	100	September 2017 – 2047	September 2020	6.891%
$	250	September 2017 – 2047	September 2021	6.570%
$	250	September 2017 – 2047	September 2023	6.761%

Derivative settlements and collateralization are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements and collateralization are classified as cash flows from financing activities. As a result of prior extensions of reference-period start dates without settlement of the related interest-rate derivative obligations, the interest-rate derivatives in the Company’s portfolio contain an other-than-insignificant financing element, and therefore, any settlements, collateralization, or ~~collateralization~~cash payments for amendments related to these extended interest-rate derivatives are classified as cash flows from financing activities.

~~The Company had~~ Net cash payments related to settlements and amendments of interest-rate swap agreements were $65 million during the ~~following outstanding interest-rate swaps at~~ six months ended June 30, ~~2016~~:2017, and $193 million during the six months ended June 30, 2016.

millions except percentages Mandatory Weighted-Average
Notional Principal Amount Reference Period Termination Date Interest Rate
$ 50
September 2016 – 2026 September 2016 5.910%
$ 50
September 2016 – 2046 September 2016 6.290%
$ 500
September 2016 – 2046 September 2018 6.559%
$ 300
September 2016 – 2046 September 2020 6.509%
$ 450
September 2017 – 2047 September 2018 6.445%
$ 100
September 2017 – 2047 September 2020 6.891%
$ 250
September 2017 – 2047 September 2021 6.570%

1215

Table of Contents

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,			June 30,		December 31,		June 30,			December 31,
Balance Sheet Classification	2016		2015		2016			2015			2017		2016		2017			2016
Commodity derivatives
Other current assets	$	111	$	462	$	(29	)	$	(177	)	$	88	$	10	$	(13	)	$	(3	)
Other assets	10		8		—			—			8		9		—			—
Accrued expenses	4		—		(30		)	(3		)
Other current liabilities											1		66		(9		)	(201		)
Other liabilities	2		—		(15		)	—			—		—		(3		)	(12		)
	127		470		(74		)	(180		)	97		85		(25		)	(216		)
Interest-rate derivatives
Other current assets	3		2		—			—			12		8		—			—
Other assets	15		54		—			—			37		23		—			—
Accrued expenses	—		—		(99		)	(54		)
Other current liabilities											—		—		(69		)	(48		)
Other liabilities	—		—		(1,749		)	(1,488		)	—		—		(1,338		)	(1,328		)
	18		56		(1,848		)	(1,542		)	49		31		(1,407		)	(1,376		)
Total derivatives	$	145	$	526	$	(1,922	)	$	(1,722	)	$	146	$	116	$	(1,432	)	$	(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 June 30,					Six Months Ended June 30,
Classification of (Gain) Loss Recognized	2016		2015			2016		2015			2017			2016		2017			2016
Commodity derivatives
Gathering, processing, and marketing sales ⁽¹⁾	$	4	$	1		$	6	$	1		$	—		$	4	$	—		$	6
(Gains) losses on derivatives, net	94		1			66		(52		)	(72		)	94		(207		)	66
Interest-rate derivatives
(Gains) losses on derivatives, net	213		(312		)	538		(107		)	104			213		92			538
Total (gains) losses on derivatives, net	$	311	$	(310	)	$	610	$	(158	)	$	32		$	311	$	(115	)	$	610


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

1316

Table of Contents

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 agencies~~S&P and Moody’s declines to a level that is below investment grade. ~~In February 2016, Moody’s Investors Service (Moody’s) downgraded~~As of June 30, 2017, the Company’s long-term debt~~credit rating from “Baa2” to “Ba1,” which is~~ was rated below investment ~~grade. The downgrade triggered credit-risk-related features with~~grade (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 pursuant~~due 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. No~~Moody’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 $177 million of collateral) at ~~each of~~ June 30, ~~2016,~~2017, and $1.4 billion (net of $117 million of collateral) at December 31, ~~2015.~~2016.

1417

Table of Contents

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, 2016	Level 1			Level 2			Level 3		Netting ⁽¹⁾			Collateral			Total
June 30, 2017
Assets
Commodity derivatives	$	1		$	126		$	—	$	(35	)	$	—		$	92		$	—		$	97		$	—	$	(14	)	$	—	$	83
Interest-rate derivatives	—			18			—		—			—			18			—			49			—		—			—		49
Total derivative assets	$	1		$	144		$	—	$	(35	)	$	—		$	110		$	—		$	146		$	—	$	(14	)	$	—	$	132
Liabilities
Commodity derivatives	$	(4	)	$	(70	)	$	—	$	35		$	5		$	(34	)	$	—		$	(25	)	$	—	$	14		$	—	$	(11	)
Interest-rate derivatives	—			(1,848		)	—		—			592			(1,256		)	—			(1,407		)	—		—			177		(1,230		)
Total derivative liabilities	$	(4	)	$	(1,918	)	$	—	$	35		$	597		$	(1,290	)	$	—		$	(1,432	)	$	—	$	14		$	177	$	(1,241	)

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.

1518

Table of Contents

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 Component~~Unless 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
millions WES
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, net 1
—
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.~~

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~8. Debt and Interest Expense (Continued)~~

~~Debt~~ ~~The Company’s~~ outstanding debt, ~~excluding the~~including capital lease ~~obligation and any borrowings under the WGP revolving credit facility, is senior unsecured. The following summarizes the Company’s outstanding debt~~obligations, after eliminating the effect of intercompany transactions:


millions	WES			WGP ⁽¹⁾		Anadarko ⁽²⁾			Anadarko Consolidated			WES			WGP ⁽¹⁾		Anadarko ⁽²⁾			Anadarko Consolidated
June 30, 2016
June 30, 2017
Total borrowings at face value	$	2,960		$	28	$	14,325		$	17,313		$	3,280		$	28	$	13,531		$	16,839
Net unamortized discounts, premiums, and debt issuance costs ⁽³⁾	(28		)	—		(1,632		)	(1,660		)	(27		)	—		(1,575		)	(1,602		)
Total borrowings	2,932			28		12,693			15,653
Capital lease obligation	—			—		20			20
Total borrowings ⁽⁴⁾												3,253			28		11,956			15,237
Capital lease obligations												—			—		243			243
Less short-term debt	—			—		32			32			—			—		44			44
Total long-term debt	$	2,932		$	28	$	12,681		$	15,641		$	3,253		$	28	$	12,155		$	15,436

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 borrowings	2,691			—		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 facilities~~RCFs 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 billion at June 30, ~~2016,~~2017, and ~~$15.7~~$17.1 billion at December 31, ~~2015.~~2016.

1719

Table of Contents

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Debt ~~and Interest Expense~~ (Continued)

Anadarko ~~Revolving Credit Facilities and Commercial Paper Program~~Borrowings Anadarko has a $3.0 billion ~~five-year~~ senior unsecured ~~revolving credit facility~~RCF maturing in January 2021 ~~(Five-Year Facility). In addition, in January 2016 the Company replaced its previous~~(APC RCF) and a $2.0 billion 364-day senior unsecured ~~revolving credit facility with a new $2.0 billion 364-day senior unsecured revolving credit facility~~RCF maturing in January 2018 (364-Day Facility)~~, on identical terms, that will mature in January 2017.~~. At June 30, ~~2016,~~2017, the Company had no outstanding borrowings under the ~~Five-Year Facility~~APC RCF or the 364-Day Facility and was in compliance with all related covenants.

~~In January 2015, the Company initiated a commercial paper program, which allows for a maximum of $3.0 billion of unsecured commercial paper notes~~Anadarko’s $114 million 7.05% Debentures due May 2018 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 downgraded~~Zero Coupons were classified as long-term debt on the Company’s ~~commercial paper program credit rating, which essentially eliminated the Company’s access to the commercial paper market. As a result,~~Consolidated Balance Sheet at June 30, 2017, as the Company has ~~not issued commercial paper notes since~~ the ~~downgrade. At June 30, 2016,~~ability and intent to refinance these obligations using long-term debt. The Zero Coupons can be put to the Company ~~had no outstanding borrowings under~~in October of each year, in whole or in part, for the ~~commercial paper program.~~then-accreted value, which will be $883 million at the next put date in October 2017.

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 June 30, 2017, WES ~~has a five-year~~was in compliance with all related covenants contained in its $1.2 billion senior unsecured ~~revolving credit facility~~RCF maturing in February ~~2019~~2020 (WES RCF), which is expandable to $1.5 billion. During the six months ended June 30, 2017, WES borrowed $160 million under its RCF, which was primarily used for general partnership purposes. At June 30, ~~2016,~~2017, WES had outstanding borrowings under its RCF of ~~$540~~$160 million at an interest rate of ~~1.77%~~2.53%, had outstanding letters of credit of $5 million, and had available borrowing capacity of ~~$655 million.~~ $1.035 billion.

At June 30, ~~2016, WES~~2017, WGP was in compliance with all related ~~covenants.~~

~~In March 2016, WGP entered into a three-year~~covenants contained in its $250 million three-year senior secured ~~revolving credit facility~~RCF 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,~~2017, WGP had outstanding borrowings under its RCF of $28 million at an interest rate of ~~2.72%,~~3.23% 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.

~~Interest Expense~~ ~~The following summarizes interest expense:~~

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

million.

1820

Table of Contents

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 June 30,						Six Months Ended June 30,
millions except percentages	2016			2015			2016			2015			2017			2016			2017			2016
Income tax expense (benefit)	$	(314	)	$	77		$	(697	)	$	(1,315	)
Current income tax expense (benefit)													$	(522	)	$	103		$	240		$	148
Deferred income tax expense (benefit)													484			(417		)	(181		)	(845		)
Total income tax expense (benefit)													$	(38	)	$	(314	)	$	59		$	(697	)
Income (loss) before income taxes	(925		)	185			(2,306		)	(4,443		)	(372		)	(925		)	(550		)	(2,306		)
Effective tax rate	34		%	42		%	30		%	30		%	10		%	34		%	(11		)%	30		%

The Company’s tax provision for interim periods is determined using an estimate of its annual current and deferred effective tax rates, adjusted for discrete items. Each quarter, the Company updates these rates and records a cumulative adjustment to current and deferred tax expense by applying the rates to the year-to-date pre-tax income excluding discrete items. The Company’s quarterly estimate of its annual current and deferred effective tax rates can vary significantly based on various forecasted items including future commodity prices, capital expenditures, expenses for which tax benefits are not recognized, and the geographic mix of pre-tax income and losses.

The Company reported a loss before income taxes for the three and six months ended June 30, ~~2016,~~2017 and ~~the six months ended June 30, 2015. As a result, items that ordinarily increase or~~2016. The 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,~~2017, was primarily attributable to the following decreases:

tax impact from foreign operations

income attributable to noncontrolling interests

federal manufacturing deduction

These decreases were partially offset by the following increases:

•state taxes, net of federal benefit

•non-deductible Algerian exceptional profits tax for Algerian income tax purposes ~~and~~

•net changes in uncertain tax positions

The decrease from the 35% U.S. federal statutory rate for the six months ended June 30, 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. In addition,~~operations

net changes in uncertain tax positions

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 and six months ended June 30, 2016, was primarily attributable to non-deductible Algerian exceptional profits tax for Algerian income tax purposes, the tax impact from foreign operations, non-deductible goodwill related to divestitures, and net changes in uncertain tax positions. These decreases were partially offset by increases to income attributable to noncontrolling interests. See Note 14—Noncontrolling Interests.

At June 30, ~~2016,~~2017, the Company’s Consolidated Balance Sheet included ~~a $192~~$361 million ~~tax~~of income taxes receivable ~~included~~presented 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
2017 50
2018 50
2019 52
2020 56
Later years 320
Total $ 553

1921

Table of Contents

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~11.~~10. Contingencies

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

~~Table of Contents~~

A~~NADARKO 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’s~~its workforce with ~~the Company’s~~its expected future operating and capital plans. Employee notifications related to the workforce reduction program were completed by June 30, 2016. ~~All~~The Company recognized restructuring charges ~~will be~~included in G&A in the Company’s Consolidated Statements of Income of $48 million during the three months ended June 30, 2016, and $251 million during the six months ended June 30, 2016. All material restructuring charges were recognized in 2016, with the exception of ~~approximately $10 million of~~settlement expense ~~for retirement benefits~~ expected to be recognized induring 2017 for lump-sum payments to terminated participants. During the ~~first quarter of 2017. The following summarizes the total expected restructuring charges and the amounts expensed during the three and~~ six months ended June 30, ~~2016, which~~2017, the Company recognized restructuring charges of $17 million, primarily related to settlement expense. Restructuring charges for the remainder of 2017 could vary depending on market conditions and participant elections but are ~~included in general and administrative expenses in the Company’s Consolidated Statements of Income:~~

millions Total 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 compensation 34
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:~~

millions 2016
Balance at January 1 $ —
Accruals 146
Payments (126 )
Balance at June 30 $ 20

not expected to be material.

2122

Table of Contents

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 Benefits					Pension Benefits						Other Benefits
millions	2016			2015			2016			2015		2017			2016			2017			2016
Three Months Ended June 30
Service cost	$	23		$	29		$	—		$	2	$	21		$	23		$	1		$	—
Interest cost	23			26			3			4		21			23			3			3
Expected return on plan assets	(24		)	(28		)	—			—
Expected (return) loss on plan assets												(21		)	(24		)	—			—
Amortization of net actuarial loss (gain)	10			13			—			—		7			10			—			—
Amortization of net prior service cost (credit)	—			—			(6		)	1		—			—			(6		)	(6		)
Settlement expense	24			—			—			—		55			24			—			—
Curtailment expense	—			—			3			—		—			—			—			3
Net periodic benefit cost	$	56		$	40		$	—		$	7	$	83		$	56		$	(2	)	$	—

Six Months Ended June 30
Service cost	$	49		$	59		$	1		$	5	$	42		$	49		$	1		$	1
Interest cost	49			51			6			8		42			49			6			6
Expected return on plan assets	(51		)	(55		)	—			—
Expected (return) loss on plan assets												(42		)	(51		)	—			—
Amortization of net actuarial loss (gain)	18			26			—			—		13			18			—			—
Amortization of net prior service cost (credit)	—			—			(12		)	1		—			—			(12		)	(12		)
Settlement expense	24			—			—			—		58			24			—			—
Termination benefits expense	44			—			—			—		4			44			—			—
Curtailment expense	8			—			—			—		—			8			—			—
Net periodic benefit cost	$	141		$	81		$	(5	)	$	14	$	117		$	141		$	(5	)	$	(5	)

~~The Company’s workforce reduction program~~During the six months ended June 30, 2017, the Company recognized $58 million of settlement expense. These settlements resulted in remeasurements of its pension ~~and other postretirement benefit obligations~~plans during ~~2016.~~2017. The remeasurements in 2017 resulted in ~~increases in the benefit obligation~~a net liability decrease of ~~$171~~$15 million for the pension benefit plans, ~~and $23 million for the other postretirement benefit plans,~~ with a corresponding ~~decrease~~increase in other comprehensive income.

~~At December 31, 2015, total expected contributions related to unfunded pension plans were $25 million~~ Settlement expense, termination benefits expense, and curtailment expense for ~~2016. The Company expects to contribute an additional $82 million in~~ 2016 ~~and $23 million in 2017 to unfunded pension plans primarily related~~relate to the workforce reduction program. See Note ~~12—~~11—Restructuring Charges.

The Company contributed $85 million during the six months ended June 30, 2017, and expects to contribute an additional $82 million to funded pension plans during 2017.

2223

Table of Contents

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 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 share~~EPS attributable to common stockholders:


	Three Months Ended June 30,					Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
millions except per-share amounts	2016			2015		2016			2015			2017			2016			2017			2016
Net income (loss)
Net income (loss) attributable to common stockholders	$	(692	)	$	61	$	(1,726	)	$	(3,207	)	$	(415	)	$	(692	)	$	(733	)	$	(1,726	)
Income (loss) effect of TEUs	(2		)	—		(3		)	—			(2		)	(2		)	(4		)	(3		)
Less distributions on participating securities	—			1		—			2
Basic	$	(694	)	$	60	$	(1,729	)	$	(3,209	)	$	(417	)	$	(694	)	$	(737	)	$	(1,729	)
Income (loss) effect of TEUs	(1		)	—		(1		)	—			(1		)	(1		)	(1		)	(1		)
Diluted	$	(695	)	$	60	$	(1,730	)	$	(3,209	)	$	(418	)	$	(695	)	$	(738	)	$	(1,730	)
Shares
Average number of common shares outstanding—basic	510			508		510			507			552			510			552			510
Dilutive effect of stock options	—			1		—			—
Average number of common shares outstanding—diluted	510			509		510			507			552			510			552			510
Excluded due to anti-dilutive effect	11			6		10			11			11			11			11			10
Net income (loss) per common share
Basic	$	(1.36	)	$	0.12	$	(3.39	)	$	(6.32	)	$	(0.76	)	$	(1.36	)	$	(1.34	)	$	(3.39	)
Diluted	$	(1.36	)	$	0.12	$	(3.39	)	$	(6.32	)	$	(0.76	)	$	(1.36	)	$	(1.34	)	$	(3.39	)

~~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 Income 3
13
16
Balance at June 30, 2016 $ (39 ) $ (448 ) $ (487 )

~~Table of Contents~~

A~~NADARKO 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. ~~During~~Pursuant to an agreement between WES and the ~~second quarter~~holders of ~~2016, WES issued an additional eight million~~the Series A Preferred units, ~~to private investors, pursuant to~~50% of the ~~full exercise of an option granted in connection with~~Series A Preferred units converted into WES common units on a one-for-one basis on March 1, 2017, and the ~~initial issuance, and raised net proceeds of $247 million.~~remaining Series A Preferred units converted on May 2, 2017.

WES Class C units issued to Anadarko will convert into WES common units on a one-for-one basis on the conversion date, which was extended in February 2017 from December 31, 2017, to March 1, 2020. The Class C units receive quarterly distributions in the form of additional Class C units until the ~~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 ~~534~~385 thousand Class C units to Anadarko during the six months ended June 30, ~~2016,~~2017, and ~~498~~946 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,~~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,~~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,~~2017, Anadarko also owned an ~~8.4%~~8.8% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining ~~60.1%~~59.8% limited partner interest in WES was owned by the public.

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,~~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,~~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,~~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.

~~Table of Contents~~

A~~NADARKO 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, ~~2016~~2017 and ~~2015,~~2016, and $8 million for each of the six months ended June 30, ~~2016~~2017 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~~that required a cash payment from WES to the Company due on March 31, 2020. ~~The~~In May 2017, WES reached an agreement with the Company to settle this obligation whereby WES made a cash payment to the Company of $37 million, equal to the net present value of ~~this~~the obligation ~~was $29 million~~ at ~~June 30, 2016, and $189 million at December~~March 31, ~~2015.~~2017.

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 $29 million for the six months ended June 30, ~~2016,~~2017, and ~~a capital contribution of zero~~$16 million for the six months ended June 30, ~~2015.~~2016.

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,						Six Months Ended June 30,
millions	2016			2015			2017			2016
Cash paid (received)
Interest, net of amounts capitalized⁽¹⁾	$	427		$	1,621		$	449		$	427
Income taxes, net of refunds⁽²⁾⁽¹⁾	(883		)	6			162			(883		)
Non-cash investing activities
Fair value of properties and equipment from non-cash transactions	$	3		$	126		$	553		$	3
Asset retirement cost additions	49			90			138			49
Accruals of property, plant, and equipment	505			901			696			505
Net liabilities assumed (divested) in acquisitions and divestitures	(36		)	(29		)	(100		)	(36		)
Non-cash investing and financing activities
Floating production, storage, and offloading vessel construction period obligation	$	11		$	43
FPSO construction period obligation ⁽²⁾							$	—		$	11
Deferred drilling lease liability							13			—


⁽¹⁾	Includes ~~$1.2 billion of interest related to the Tronox settlement payment in 2015.~~


⁽²⁾	~~Includes~~ $881 million from a tax refund in 2016 related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback.


⁽²⁾	Upon completion of the FPSO in the third quarter of 2016, the Company reported the construction period obligation as a capital lease obligation based on the fair value of the FPSO.

~~19.~~17. Segment Information

Anadarko’s business segments are separately managed due to distinct operational ~~differences~~differences. Anadarko has previously presented three reportable segments in its quarterly and ~~unique technology, distribution,~~annual filings: Oil and Gas Exploration and Production, Midstream, and Marketing. In the first half of 2017, Anadarko substantially completed a repositioning of its asset portfolio to focus on higher margin liquids production. This shift resulted in a substantial decrease in the number of U.S. operating areas. Following the portfolio repositioning, the chief operating decision maker reviews operating results for Exploration and Production and Midstream when making operating and capital allocation decisions. Accordingly, Anadarko will no longer identify marketing ~~requirements.~~activities as a separate reportable segment and will have two reporting segments: Exploration and Production and Midstream, which will include their respective marketing results. The ~~Company’s~~ ~~three~~Company has reclassified prior period amounts to conform to the current period’s presentation.

The Exploration and Production reporting ~~segments are oil and gas exploration and production, midstream, and marketing. The oil and gas exploration and production~~ segment explores for, produces, and ~~produces~~sells oil, ~~condensate,~~ natural gas, and NGLs and plans for the development and operation of the Company’s LNG project in Mozambique. The ~~midstream~~Midstream reporting 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~~Midstream reporting segment consists of two operating segments, WES and ~~other midstream,~~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.~~

2526

Table of Contents

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~19.~~17. 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,~~G&A, loss on early extinguishment of debt, ~~Tronox-related contingent loss,~~ and certain other nonoperating items included in other (income) expense, net.

The Company’s definition of Adjusted EBITDAX excludes gains (losses) on divestitures, net and exploration expense as they are not indicators of operating efficiency for a given reporting period. 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 June 30,						Six Months Ended June 30,
millions	2016			2015			2016			2015			2017			2016			2017			2016
Income (loss) before income taxes	$	(925	)	$	185		$	(2,306	)	$	(4,443	)	$	(372	)	$	(925	)	$	(550	)	$	(2,306	)
Interest expense													227			217			450			437
DD&A													1,037			984			2,152			2,133
Exploration expense													535			76			1,620			202
(Gains) losses on divestitures, net	104			91			102			425			(205		)	104			(1,009		)	102
Exploration expense	76			103			202			1,186
DD&A	984			1,214			2,133			2,470
Impairments	18			30			34			2,813			10			18			383			34
Interest expense	217			201			437			417
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	371			(229		)	775			14			45			371			(110		)	775
Restructuring charges	48			—			251			—			18			48			17			251
Other operating expense	—			—			1			4			—			—			—			1
Loss on early extinguishment of debt	124			—			124			—			2			124			2			124
Tronox-related contingent loss	—			—			—			5
Certain other nonoperating items	(56		)	—			(56		)	22			—			(56		)	—			(56		)
Less net income (loss) attributable to noncontrolling interests	81			47			117			79			81			81			124			117
Consolidated Adjusted EBITDAX	$	880		$	1,548		$	1,580		$	2,834		$	1,216		$	880		$	2,831		$	1,580

2627

Table of Contents

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, margin on sales of third-party commodity purchases, deficiency fees, 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			Exploration & Production			Midstream		Other and Intersegment Eliminations			Total
Three Months Ended June 30, 2017
Sales revenues														$	1,955		$	447	$	17		$	2,419
Intersegment revenues														—			156		(156		)	—
Other ⁽¹⁾														8			54		30			92
Total revenues and other ⁽²⁾														1,963			657		(109		)	2,511
Operating costs and expenses ⁽³⁾														805			345		91			1,241
Net cash from settlement of commodity derivatives														—			—		(13		)	(13		)
Other (income) expense, net ⁽³⁾														—			—		(14		)	(14		)
Net income (loss) attributable to noncontrolling interests ⁽¹⁾														—			—		81			81
Total expenses and other														805			345		145			1,295
Adjusted EBITDAX														$	1,158		$	312	$	(254	)	$	1,216

Three Months Ended June 30, 2016
Sales revenues	$	1,033	$	141	$	811		$	—		$	1,985		$	1,680		$	280	$	25		$	1,985
Intersegment revenues	567		340		(676		)	(231		)	—			—			218		(218		)	—
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⁾														(14		)	28		20			34
Total revenues and other ⁽²⁾														1,666			526		(173		)	2,019
Operating costs and expenses ⁽³⁾														861			234		26			1,121
Net cash from settlement of commodity derivatives	—		—		—			(60		)	(60		)	—			—		(60		)	(60		)
Other (income) expense, net ⁽³⁾	—		—		—			1			1
Net income (loss) attributable to noncontrolling interests	—		81		—			—			81
Other (income) expense, net														—			—		1			1
Net income (loss) attributable to noncontrolling interests ⁽¹⁾														—			—		81			81
Total expenses and other	790		300		177			(124		)	1,143			861			234		48			1,143
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		$	805		$	292	$	(217	)	$	880

Three Months Ended June 30, 2015
Sales revenues	$	1,356	$	191	$	1,090		$	—		$	2,637
Intersegment revenues	885		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 other	832		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 ~~expense~~expenses 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.~~

2728

Table of Contents

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~19.~~17. Segment Information (Continued)


millions	Oil and Gas Exploration & Production		Midstream		Marketing			Other and Intersegment Eliminations			Total			Exploration & Production			Midstream		Other and Intersegment Eliminations			Total
Six Months Ended June 30, 2016
Six Months Ended June 30, 2017
Sales revenues	$	1,744	$	266	$	1,609		$	—		$	3,619		$	4,409		$	850	$	58		$	5,317
Intersegment revenues	1,168		642		(1,339		)	(471		)	—			—			349		(349		)	—
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
Other ⁽¹⁾														10			87		60			157
Total revenues and other ⁽²⁾														4,419			1,286		(231		)	5,474
Operating costs and expenses ⁽³⁾														1,728			672		146			2,546
Net cash from settlement of commodity derivatives	—		—		—			(163		)	(163		)	—			—		(7		)	(7		)
Other (income) expense, net ⁽³⁾	—		—		—			1			1
Net income (loss) attributable to noncontrolling interests	—		117		—			—			117
Other (income) expense, net														—			—		(22		)	(22		)
Net income (loss) attributable to noncontrolling interests ⁽¹⁾														—			—		124			124
Total expenses and other	1,563		519		353			(316		)	2,119			1,728			672		241			2,641
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—		—		8			—			8			—			—		(2		)	(2		)
Adjusted EBITDAX	$	1,349	$	389	$	(75	)	$	(83	)	$	1,580		$	2,691		$	614	$	(474	)	$	2,831

Six Months Ended June 30, 2015
Six Months Ended June 30, 2016
Sales revenues	$	2,426	$	365	$	2,431		$	—		$	5,222		$	3,074		$	494	$	51		$	3,619
Intersegment revenues	2,002		605		(2,145		)	(462		)	—			—			444		(444		)	—
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
Other ⁽¹⁾														(15		)	41		46			72
Total revenues and other ⁽²⁾														3,059			979		(347		)	3,691
Operating costs and expenses ⁽³⁾														1,709			430		25			2,164
Net cash from settlement of commodity derivatives	—		—		—			(172		)	(172		)	—			—		(163		)	(163		)
Other (income) expense, net ⁽³⁾	—		—		—			40			40
Net income (loss) attributable to noncontrolling interests	—		79		—			—			79
Other (income) expense, net														—			—		1			1
Net income (loss) attributable to noncontrolling interests ⁽¹⁾														—			—		117			117
Total expenses and other	1,834		553		390			(228		)	2,549			1,709			430		(20		)	2,119
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—		—		1			—			1			—			—		8			8
Adjusted EBITDAX	$	2,594	$	417	$	(103	)	$	(74	)	$	2,834		$	1,350		$	549	$	(319	)	$	1,580

__________________________________________________________________


⁽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 ~~expense~~expenses 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.

~~Table of Contents~~

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 and other operational 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 ~~local~~foreign environmental laws and regulations

civil or political unrest or acts of terrorism in a region or country

the creditworthiness and performance of the Company’s counterparties, including financial institutions, operating partners, and other parties

~~Table of Contents~~

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 ~~condensate~~NGLs cargo shipping activities

physical, digital, internal, and external security breaches

supply and demand, technological, political, governmental, and commercial conditions associated with long-term development and production projects in domestic and international locations

the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigation by the National Transportation Safety Board (NTSB), related to our operations in Colorado, and continued or additional disruptions in operations that may occur as the Company complies with regulatory orders or other state or local changes in laws or regulations in Colorado

other factors discussed below and elsewhere in “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates” included in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~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.

~~OUTLOOK~~MANAGEMENT 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 ~~oil~~Delaware 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 gas~~DJ basins in the ~~United States. Low commodity prices have continued into 2016~~U.S. onshore and ~~may exist for an extended period.~~deepwater Gulf of Mexico. Anadarko’s deepwater Gulf of Mexico assets are expected to generate substantial cash flows over the next five years at current strip prices. The ~~Company’s revenues, operating results,~~Company plans to use the cash flows from ~~operations, capital spending, and future growth rates are highly dependent on~~ the ~~global commodity-price markets, which affect the value the Company receives~~Gulf of Mexico as well as from its ~~sales~~international producing assets to fund growth in the Company’s unconventional assets in the Delaware and DJ basins. Much of ~~oil, natural gas,~~the 2017 operational focus is preparing the Delaware basin for development with increased operatorship and ~~NGLs.~~

infrastructure to facilitate long-term growth and value. The Company ~~has continued its disciplined~~ended the second quarter of 2017 with 16 operated drilling rigs in the Delaware basin and ~~focused approach~~6 operated drilling rigs in ~~2016 by emphasizing value over growth, preserving~~the DJ basin, which compares to 14 operated drilling rigs in the Delaware basin and ~~building value through capital allocation, enhancing operational efficiencies, and continuing an active monetization program. In~~6 operated drilling rigs in the DJ basin at the end of the first quarter of ~~2016,~~2017. In the deepwater Gulf of Mexico, Anadarko has 3 floating rigs drilling with a focus on leveraging the Company’s expansive infrastructure position.

Following a home explosion in Colorado in April 2017, the Company ~~initiated~~has taken actions in an effort to alleviate public concern and reinforce confidence in the safety of its operations. The Company took precautionary measures to shut in all operated vertical wells in the DJ basin to conduct additional inspections and testing and also remove all one-inch return lines associated with these wells. Subsequently, in May 2017, the Colorado Oil & Gas Conservation Commission issued a ~~workforce reduction program~~two-phase Notice to ~~align~~Operators (NTO) requiring all operators to inventory and integrity test existing flowlines within 1,000 feet of a building unit and abandon all inactive flowlines in such areas. The Company expects to meet the ~~size and composition of Anadarko’s workforce~~NTO compliance deadline, is cooperating fully with the ~~Company’s expected future operating~~NTSB in its investigation, and ~~capital plans. Employee notifications related~~continues 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,~~work cooperatively with ~~the exception of approximately $10 million of expense for retirement benefits expected to be recognized in the first quarter of 2017.~~state regulators and others.

~~The Company~~Anadarko currently estimates a ~~2016~~2017 capital spending range of ~~$3.1~~$5.1 billion to ~~$3.3~~$5.4 billion, ~~including~~which represents a decrease of more than 5% from the initial 2017 estimate due to current market conditions requiring lower capital intensity given the volatility of margins realized in this operating environment. 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 ~~2016~~2017 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 ~~region~~upstream and ~~Alaska, 20% for the~~midstream and deepwater Gulf of Mexico ~~20% for Midstream~~development; 15% to future value areas, such as deepwater exploration and ~~other (including WES),~~Mozambique 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 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 the~~while maintaining appropriate liquidity and financial ~~flexibility. Anadarko expects that its 2016 capital expenditures will be within its~~flexibility with cash on the balance sheet, ownership of marketable securities in WGP, and access to credit facilities.

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.

~~Table of Contents~~

~~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 billion~~sales 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.

~~Table of Contents~~

Significant operating and financial activities for the second quarter of ~~2016~~2017 include the following:

~~Overall~~Total Company

Anadarko’s overall sales-volume product mix increased to 67% liquids in the second quarter of 2017, compared to 54% in the second quarter of 2016, which significantly improved margins.

Anadarko’s second-quarter oil sales volumes averaged ~~792 thousand barrels of oil equivalent per day (MBOE/d),~~331 MBbls/d, representing a ~~6% decrease~~12% increase from the second quarter of ~~2015,~~2016, primarily due to ~~a decrease in natural-gas~~increased volumes from the Gulf of Mexico and the startup of TEN offshore Ghana, partially offset by divestitures of U.S. onshore oil and ~~condensate sales volumes.~~

~~The Company recognized workforce reduction program expenses of $48 million~~gas assets in ~~the second quarter for a total 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 received during the quarter from asset divestitures~~2016 and ~~the sale of a portion of the Company’s WGP common units to the public.~~2017.

U.S. Onshore

~~Second-quarter liquids~~Oil sales volumes ~~averaged 291 thousand barrels per day (MBbls/d),~~in the Delaware basin increased 11 MBbls/d, representing a ~~5% decrease~~52% increase from the second quarter of ~~2015, primarily~~2016, due to ~~a natural production decline in~~continued drilling and completion activities.

Anadarko closed the ~~Eagleford shale~~divestitures of its Eaglebine and ~~reduced capital activity in~~Utah CBM assets during the ~~Wattenberg field.~~quarter for net proceeds of $604 million, prior to final closing adjustments.

~~Second-quarter natural-gas~~

Gulf of Mexico

Oil sales volumes averaged ~~353 MBOE/~~113 MBbls/d, representing a ~~6% decrease~~102% increase from the second 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,~~continued tieback activity at several facilities and ~~natural production declines 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.~~

~~Gulf of Mexico~~

~~Second-quarter sales volumes averaged 74 MBOE/d, representing an 11%~~ ~~decrease~~activity from the ~~second quarter of 2015, 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) in December 2015.~~

~~The Shenandoah-5 appraisal well (33% working interest) encountered more than 1,040 net feet of oil pay, extending the eastern limits of the field.~~GOM Acquisition.

International

Second-quarter sales volumes averaged 7493 MBbls/d, representing ~~an 11% decrease~~a 26% increase from the second quarter of ~~2015,~~2016, primarily as a result of the TEN development project (19% nonoperated participating interest) in Ghana ~~due to downtime related to a maintenance issue with~~achieving first oil in the ~~floating, production, storage, and offloading unit (FPSO) turret bearing.~~third quarter of 2016.

~~Financial~~

~~Anadarko’s net loss attributable to common stockholders for~~Interim mooring of the ~~second~~FPSO at the Jubilee field in Ghana commenced in the fourth 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 the third quarter of 2017. It is anticipated that a facility shutdown of between five and eight 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.

The Company is completing many of the core components of the legal and contractual framework for its LNG project in Mozambique. The progress helps position the Company to advance negotiations in securing long-term LNG offtake contracts as it continues toward a final investment decision.

Financial

The Company generated ~~$1.2 billion~~$857 million of cash flow from operations and ended the quarter with ~~$1.4~~$6.0 billion of ~~cash on hand.~~

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 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.~~cash.

~~Table of Contents~~

FINANCIAL RESULTS


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
millions except per-share amounts	2016			2015			2016			2015			2017			2016			2017			2016
Oil and condensate, natural-gas, and NGLs sales	$	1,680		$	2,332		$	3,074		$	4,624
Oil, natural-gas, and NGLs sales													$	1,955		$	1,680		$	4,409		$	3,074
Gathering, processing, and marketing sales	305			305			545			598			464			305			908			545
Gains (losses) on divestitures and other, net	(70		)	(1		)	(30		)	(265		)	297			(70		)	1,166			(30		)
Revenues and other	1,915			2,636			3,589			4,957			$	2,716		$	1,915		$	6,483		$	3,589
Costs and expenses	2,247			2,546			4,785			9,075			2,841			2,247			6,718			4,785
Other (income) expense	593			(95		)	1,110			325			247			593			315			1,110
Income tax expense (benefit)	(314		)	77			(697		)	(1,315		)	(38		)	(314		)	59			(697		)
Net income (loss) attributable to common stockholders	$	(692	)	$	61		$	(1,726	)	$	(3,207	)	$	(415	)	$	(692	)	$	(733	)	$	(1,726	)
Net income (loss) per common share attributable to common stockholders—diluted	$	(1.36	)	$	0.12		$	(3.39	)	$	(6.32	)	$	(0.76	)	$	(1.36	)	$	(1.34	)	$	(3.39	)
Average number of common shares outstanding—diluted	510			509			510			507			552			510			552			510

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,~~2017,” refer to the comparison of the three months ended June 30, ~~2016,~~2017, to the three months ended June 30, ~~2015,~~2016, and any increases or decreases “for the six months ended June 30, ~~2016,~~2017,” refer to the comparison of the six months ended June 30, ~~2016,~~2017, to the six months ended June 30, ~~2015.~~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 June 30,
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													$	1,125		$	320		$	235		$	1,680
Changes associated with prices													163			138			47			348
Changes associated with sales volumes	(114		)	(34		)	(7		)	(155		)	134			(139		)	(68		)	(73		)
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		)%
2017 sales revenues													$	1,422		$	319		$	214		$	1,955
Increase (decrease) vs. 2016													26		%	—		%	(9		)%	16		%

	Six Months Ended June 30,												Six Months Ended June 30,
millions except percentages	Oil and Condensate			Natural Gas			NGLs			Total			Oil			Natural Gas			NGLs			Total
2015 sales revenues	$	3,035		$	1,128		$	461		$	4,624
2016 sales revenues													$	1,975		$	686		$	413		$	3,074
Changes associated with prices													842			351			168			1,361
Changes associated with sales volumes	(178		)	(127		)	(30		)	(335		)	268			(216		)	(78		)	(26		)
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													$	3,085		$	821		$	503		$	4,409
Increase (decrease) vs. 2016													56		%	20		%	22		%	43		%

~~Changes~~The above table illustrates the effects of the increase in commodity prices and changes associated with sales volumes, ~~for~~which include increases related to newly acquired assets in the ~~three~~Gulf of Mexico (primarily oil) and ~~six months ended June 30, 2016, include~~ decreases associated with U.S. onshore asset ~~divestitures.~~

~~Table of Contents~~

divestitures (primarily natural gas).

The following provides Anadarko’s sales volumes for the three and six months ended June 30:

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~~



	Three Months Ended June 30,				Six Months Ended June 30,
	2017	Inc (Dec) vs. 2016		2016	2017	Inc (Dec) vs. 2016		2016
Barrels of Oil Equivalent
(MMBOE except percentages)
United States	49	(25	)%	65	111	(16	)%	132
International	8	26		7	18	21		15
Total barrels of oil equivalent	57	(20	)	72	129	(12	)	147

Barrels of Oil Equivalent per Day
(MBOE/d except percentages)
United States	538	(25	)%	718	614	(16	)%	728
International	93	26		74	99	21		81
Total barrels of oil equivalent per day	631	(20	)	792	713	(12	)	809

Sales volumes represent actual production volumes adjusted for changes in commodity inventories ~~and~~as well as natural-gas production volumes provided to satisfy a commitment ~~established in conjunction with~~under 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



	Three Months Ended June 30,						Six Months Ended June 30,
	2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016
Oil sales revenues (millions)	$	1,422	26	%	$	1,125	$	3,085	56	%	$	1,975

United States
Sales volumes—MMBbls	22		7	%	20		46		11	%	41
MBbls/d	243		7		227		256		12		229
Price per barrel	$	46.68	16		$	40.25	$	48.01	41		$	34.07

International
Sales volumes—MMBbls	8		27	%	6		17		21	%	14
MBbls/d	88		27		69		93		22		76
Price per barrel	$	48.61	4		$	46.75	$	51.10	28		$	39.84

Total
Sales volumes—MMBbls	30		12	%	26		63		14	%	55
MBbls/d	331		12		296		349		14		305
Price per barrel	$	47.19	13		$	41.77	$	48.84	38		$	35.51

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 June 30, 2017 vs. 2016	$	297	$	163	$	134
Six months ended June 30, 2017 vs. 2016	1,110		842		268

Oil Prices

The average oil price received increased for the three 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 barrels~~six months ended June 30, 2017, primarily due to the expectation of decreasing global oversupply as a result of OPEC’s agreement to reduce production through the first quarter of 2018.

~~Anadarko’s~~Oil Sales Volumes

2017 vs. 2016 The Company’s oil ~~and condensate~~ sales volumes ~~decreased~~increased by 2235 MBbls/d for the three months ended June 30, ~~2016,~~2017, and 2144 MBbls/d for the six months ended June 30, ~~2016.~~2017, primarily due to the following:

U.S. Onshore

Sales volumes for the Delaware basin increased by 11 MBbls/d for the three and six months ended June 30, 2017, primarily due to continued drilling and completion activities.

Sales volumes for the DJ basin decreased by 17 MBbls/d for the three and six months ended June 30, 2017, primarily due to reduced capital activity in 2016 during the low commodity-price cycle and downtime related to the Company’s response efforts in Colorado in the ~~Rockies~~ second quarter of 2017.

Sales volumes decreased by 932 MBbls/d for the three months ended June 30, ~~2016,~~2017, and 1326 MBbls/d for the six months ended June 30, ~~2016,~~2017, primarily due to ~~reduced capital activity~~the sale of the U.S. onshore Eagleford assets in the ~~Wattenberg field.~~ first half of 2017.

Gulf of Mexico

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 volumes decreased~~increased by 957 MBbls/d for the three months ended June 30, ~~2016,~~2017, and 1262 MBbls/d for the six months ended June 30, ~~2016,~~2017, primarily ~~in Ghana~~ due to ~~downtime to address new production~~continued tieback activity at several facilities and ~~offtake procedures resulting from a maintenance issue with~~ 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 complete~~GOM Acquisition in ~~the first half of 2017. In the meantime, shuttle tankers continue to successfully conduct offtakes.~~ December 2016.

International

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 Region decreased~~Ghana increased by 619 MBbls/d for the three months ended June 30, ~~2016,~~2017, and 415 MBbls/d for the six months ended June 30, ~~2016,~~2017, primarily due to ~~a natural production decline~~liftings from the TEN development project, which came online late in the ~~Eagleford shale, partially offset by higher sales volumes due to continued development in the Delaware basin.~~

Sales volumes in the Gulf of Mexico were relatively flat for the three months ended June 30, 2016, and increased by 5 MBbls/d for the six months ended June 30, 2016, primarily from the Lucius development, which achieved first oil in the firstthird quarter of ~~2015.~~

~~Anadarko’s average oil price received decreased for the three and six months ended June 30, 2016, primarily due to continued global oversupply and concerns of slowing oil demand growth.~~

~~Table of Contents~~

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 June 30,							Six Months Ended June 30,
	2017			Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016
Natural-gas sales revenues (millions)	$	319		—	%	$	320	$	821	20	%	$	686

United States			��
Sales volumes—Bcf	113			(43	)%	199		280		(31	)%	409
MMcf/d	1,238			(43	)	2,188		1,547		(31	)	2,245
Price per Mcf	$	2.84		76		$	1.61	$	2.93	74		$	1.68

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 June 30, 2017 vs. 2016	$	(1	)	$	138	$	(139	)
Six months ended June 30, 2017 vs. 2016	135			351		(216		)

Natural-Gas Prices

The average natural-gas price Anadarko received increased for the three and six months ended June 30, 2017, primarily due to the industry’s year-over-year production declines resulting in reduced gas storage, while LNG and natural-gas exports to Mexico continued to grow.

Natural-Gas Sales Volumes

2017 vs. 2016The Company’s natural-gas sales volumes decreased by ~~166~~950 MMcf/d for the three months ended June 30, ~~2016,~~2017, and ~~300~~698 MMcf/d for the six months ended June 30, ~~2016.~~

~~Sales volumes in the Rockies~~ ~~decreased~~ ~~by 150 MMcf/d for the three months ended June 30, 2016, and 161 MMcf/d for the six months ended June 30, 2016,~~2017, primarily due to the ~~September 2015~~ sale of ~~certain coalbed methane properties~~the U.S onshore Elm Grove and ~~a natural production decline at Greater Natural Buttes, partially offset by higher 2016 sales volumes~~East Texas assets in the ~~Wattenberg field as a result~~second half of ~~improved well performance.~~

~~Sales volumes~~2016 and the U.S. onshore Marcellus and Eagleford assets in the ~~Gulf~~first half of Mexico decreased by 40 MMcf/d for the three months ended June 30, 2016, and 89 MMcf/d for the six months ended June 30, 2016, primarily as a result of the last producing well going off line at IHUB in December 2015.

Sales volumes in the Southern and Appalachia Region increased by 24 MMcf/d for the three months ended June 30, 2016, primarily due to the injection of volumes into storage in 2015, third-party infrastructure downtime in the Marcellus shale in 2015, and continued development in the Delaware basin. The increase 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, 2017.~~decreased~~ ~~by 50 MMcf/d, primarily due to the decreases discussed above, partially offset by higher 2016 sales volumes in the Delaware basin due to continued development.~~

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 June 30,						Six Months Ended June 30,
													2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016
Natural-gas liquids sales revenues (millions)													$	214	(9	)%	$	235	$	503	22	%	$	413

United States
Sales volumes—MMBbls													8		(30	)%	12		18		(20	)%	23
MBbls/d													89		(30	)	126		100		(20	)	125
Price per barrel													$	24.82	28		$	19.42	$	25.79	50		$	17.24

International
Sales volumes—MMBbls													—		3	%	1		1		9	%	1
MBbls/d													5		3		5		6		9		5
Price per barrel													$	30.48	26		$	24.13	$	34.36	47		$	23.43
	2016		Inc (Dec) vs. 2015		2015		2016		Inc (Dec) vs. 2015		2015
Total
Sales volumes—MMBbls	13		(3	)%	12		24		(7	)%	25		8		(29	)%	13		19		(19	)%	24
MBbls/d	131		(3	)	136		130		(7	)	140		94		(29	)	131		106		(18	)	130
Price per barrel	$	19.60	6		$	18.50	$	17.49	(4	)	$	18.24	$	25.14	28		$	19.60	$	26.27	50		$	17.49
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 June 30, 2017 vs. 2016	$	(21	)	$	47	$	(68	)
Six months ended June 30, 2017 vs. 2016	90			168		(78		)

NGLs Prices

The average NGLs price received increased for the three and six months ended June 30, 2017, primarily due to increased propane prices stemming from higher export demand.

NGLs Sales Volumes

2017 vs. 2016 The Company’s NGLs sales volumes decreased by 537 MBbls/d for the three months ended June 30, ~~2016,~~2017, and ~~by 10~~24 MBbls/d for the six months ended June 30, ~~2016,~~2017, primarily due to the following:

U.S. Onshore

Sales volumes for the DJ basin increased ~~ethane rejection~~by 6 MBbls/d for the three months ended June 30, 2017, and 7 MBbls/d for the six months ended June 30, 2017, primarily due to improved well performance partially offset by downtime due to the Company’s response efforts in Colorado in the ~~United States~~second quarter of 2017.

Sales volumes decreased by 43 MBbls/d for the three months ended June 30, 2017, and 38 MBbls/d for the six months ended June 30, 2017, primarily due to the sale of the U.S. onshore East Texas assets in the second half of 2016. and the U.S. onshore Eagleford assets in the first half of 2017.

~~Table of Contents~~

Gathering, Processing, and Marketing


	Three Months Ended June 30,						Six Months Ended June 30,						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		2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016
Gathering, processing, and marketing sales	$	305	—	%	$	305	$	545	(9	)%	$	598	$	464	52	%	$	305	$	908	67	%	$	545
Gathering, processing, and marketing expense	252		(1	)	255		467		(8	)	509		359		42		252		710		52		467
Total gathering, processing, and marketing, net	$	53	6		$	50	$	78	(12	)	$	89	$	105	98		$	53	$	198	154		$	78

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 flat~~increased by $52 million for the three months ended June 30, ~~2016,~~2017, and ~~decreased~~ by ~~$11~~$120 million for the six months ended June 30, ~~2016,~~2017, primarily related to an increase in throughput volumes at the DBM complex in the Delaware basin due to ~~plant~~ downtime inthroughout the first quarter of 2016, the gradual ramp up throughout the second quarter of 2016, and ~~the 2015 divestitures of certain midstream assets, partially offset by higher marketing margins.~~increased processing capacity into 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 June 30,						Six Months Ended June 30,
millions except percentages	2017		Inc (Dec) vs. 2016	2016			2017		Inc (Dec) vs. 2016	2016
Gains (losses) on divestitures, net	$	205	NM	$	(104	)	$	1,009	NM	$	(102	)
Other	92		171	34			157		118	72
Total gains (losses) on divestitures and other, net	$	297	NM	$	(70	)	$	1,166	NM	$	(30	)

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 during~~During the three ~~months ended June 30, 2015,~~ and ~~$117 million during the~~ six months ended June 30, ~~2015, related to the settlement of a royalty lawsuit associated with a property~~ 2017 and 2016, Anadarko divested certain non-core U.S. onshore assets. See Note 3—Acquisitions, Divestitures, and Assets Held for Salein the ~~Gulf~~Notes to Consolidated Financial Statements under Item 1 of ~~Mexico.~~this Form 10-Q for additional information.

~~Table of Contents~~

Costs and Expenses

The following provides Anadarko’s total costs and expenses for three and six months ended June 30:

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



	Three Months Ended June 30,				Six Months Ended June 30,
millions	2017		2016		2017		2016
Oil and gas operating	$	233	$	202	$	491	$	410
Oil and gas transportation	229		246		478		488
Exploration	535		76		1,620		202
Gathering, processing, and marketing	359		252		710		467
General and administrative	291		305		560		754
Depreciation, depletion, and amortization	1,037		984		2,152		2,133
Production, property, and other taxes	135		157		290		274
Impairments	10		18		383		34
Other operating expense	12		7		34		23
Total	$	2,841	$	2,247	$	6,718	$	4,785

~~BOE—barrel of oil equivalent~~

Oil and Gas Operating Expense



	Three Months Ended June 30,						Six Months Ended June 30,
	2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016
Oil and gas operating (millions)	$	233	15	%	$	202	$	491	20	%	$	410
Oil and gas operating—per BOE	4.07		45		2.80		3.81		37		2.78

Oil and gas operating expense ~~decreased~~increased by ~~$24~~$81 million for the six months ended June 30, 2017, primarily due to the following:

higher overall operating costs of $89 million and non-operating costs of $20 million primarily related to the GOM Acquisition

higher non-operating costs of $9 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 that came online late in the third quarter of 2016

lower expenses of $45 million as a result of U.S. onshore asset divestitures

The related costs per BOE increased by $1.03 for the six months ended June 30, 2017, primarily due to increased costs as discussed above and shifting to a higher-return, oil-levered portfolio.

Exploration Expense



	Three Months Ended June 30,					Six Months Ended June 30,
millions	2017		2016			2017		2016
Exploration Expense
Dry hole expense	$	367	$	(5	)	$	843	$	6
Impairments of unproved properties	87		15			623		39
Geological and geophysical, exploration overhead, and other expense	81		66			154		157
Total exploration expense	535		76			1,620		202

Total exploration expense increased by $459 million for the three months ended June 30, ~~2016,~~2017, and $1.4 billion for the six months ended June 30, 2017, primarily ~~as a result of divestitures in 2015. Oil~~related to the following:

Dry Hole Expense

Dry hole expense increased by $372 million for the three months ended June 30, 2017, and ~~gas operating expense decreased by $112~~$837 million for the six months ended June 30, ~~2016, due~~2017. The Company expensed the following exploratory well costs:

$435 million related to ~~lower expenses of $56 million as a result of divestitures~~the Shenandoah project in ~~2015; lower workover costs of $31 million in Ghana,~~ the Gulf of Mexico in the first quarter of 2017

$241 million related to wells in the Grand Fuerte area in Colombia in the second quarter of 2017

$119 million related to certain wells in Côte d’Ivoire in the second quarter of 2017

$48 million primarily related to unsuccessful drilling activities associated with other Gulf of Mexico and international properties in the ~~Rockies; and lower nonoperated costs~~first half of ~~$18 million across all areas. The related costs per BOE decreased~~2017

See Note 5—Exploratory Well Costs in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information.

Impairments of Unproved Properties

Impairments of unproved properties increased by ~~$0.13 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~~$584 million for the six months ended June 30, 2016, 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 lower costs as a result of decreased sales volumes.

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

~~For the three months ended June 30, 2016, total exploration expense decreased by $27 million.~~

~~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 million~~2017, primarily due to ~~seismic activities in Colombia in 2016.~~

~~Exploration overhead and other decreased by $22 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.~~following:

~~Dry hole expense decreased by $36 million. The Company recognized $42 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.~~

~~Table of Contents~~

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

•

The Company recognized $555 million of impairments of unproved Gulf of Mexico properties during the six months ended June 30, 2017, of which $463 million related to the Shenandoah project. The unproved property balance related to the Shenandoah project originated from the purchase price allocated to the Gulf of Mexico exploration projects from the acquisition of Kerr-McGee Corporation in 2006. See Note 5—Exploratory Well Costs in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

General and ~~administrative expense (G&A) included $48 million of charges associated with the workforce reduction program for the three months ended June 30, 2016, and $251~~Administrative Expense



	Three Months Ended June 30,						Six Months Ended June 30,
millions except percentages	2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016
General and administrative	$	291	(5	)%	$	305	$	560	(26	)%	$	754

G&A decreased by $194 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,~~2017, primarily due to ~~lower employee-related expenses primarily~~$234 million associated with ~~decreased benefit, bonus plan, and salary expenses.~~the 2016 workforce reduction 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 the three months ended June 30, 2016, and by $337 million for~~

Impairments

During 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~~2017, impairments

~~lower 2016 sales volumes~~ included $211 million associated with ~~U.S. onshore properties~~

~~lower costs and sales volumes as a result~~Gulf 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 decreases 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~~Mexico oil and gas properties ~~and $449 million for related midstream properties in the Rockies, which were impaired~~ due to lower forecasted commodity ~~prices.~~

~~Other operating expense decreased by $46~~prices and $169 million ~~for the six months ended June 30, 2016,~~ primarily related to 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.

~~Table of Contents~~

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

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 instruments~~reduced 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~~producer’s bankruptcy. For further discussion related to impairments, including the potential 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.

~~For additional information,~~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.

~~Table of Contents~~

~~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 Interests~~4—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 and six months ended June 30:



	Three Months Ended June 30,						Six Months Ended June 30,
millions	2017			2016			2017			2016
Interest expense	$	227		$	217		$	450		$	437
Loss on early extinguishment of debt	2			124			2			124
(Gains) losses on derivatives, net ⁽¹⁾	32			307			(115		)	604
Other (income) expense, net	(14		)	(55		)	(22		)	(55		)
Total	$	247		$	593		$	315		$	1,110


⁽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 June 30,						Six Months Ended June 30,
millions except percentages	2017			2016			2017			2016
Income tax expense (benefit)	$	(38	)	$	(314	)	$	59		$	(697	)
Income (loss) before income taxes	(372		)	(925		)	(550		)	(2,306		)
Effective tax rate	10		%	34		%	(11		)%	30		%

The Company reported a loss before income taxes for the three and six months ended June 30, 2017 and 2016. 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 ~~Contents~~the 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. For additional information on income taxes, see Note 9—Income Taxes

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

LIQUIDITY AND CAPITAL RESOURCES


	Six Months Ended June 30,						Six Months Ended June 30,
millions	2016			2015			2017			2016
Net cash provided by (used in) operating activities	$	1,092		$	(3,261	)	$	1,980		$	1,092
Net cash provided by (used in) investing activities	(965		)	(2,785		)	1,216			(965		)
Net cash provided by (used in) financing activities	329			849			(372		)	329

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.

~~Effects~~During 2017, Anadarko received net proceeds of ~~Moody’s Credit Rating Downgrade~~ ~~In February 2016, Standard and Poor’s affirmed Anadarko’s “BBB” long-term debt credit rating and changed~~$3.5 billion from divestitures, primarily related to the ~~outlook from stable to negative. Later in February 2016, Moody’s Investors Service (Moody’s) lowered~~sale of the Company’s ~~long-term debt credit rating from “Baa2” to “Ba1,” which is below investment grade. In March 2016, Fitch Ratings affirmed Anadarko’s “BBB” long-term debt credit rating~~U.S. onshore Eagleford, Marcellus, Eaglebine, and ~~changed the outlook from stable to negative.~~

Utah CBM assets. 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~~2017, Anadarko had $6.0 billion of cash ~~posted as collateral pursuant~~plus $5.0 billion of borrowing capacity under its RCFs. Anadarko believes that its current available cash and anticipated operating cash flows will be sufficient 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 collateral in the form of letters of credit or cash as financial assurance of its performance under certain contractual arrangements such as pipeline transportation contracts and oil and gas sales contracts. The amount of letters of credit or cash provided as assurance offund the Company’s ~~performance under these types~~projected 2017 and long-term operational and capital programs. The Company continuously monitors its liquidity position and evaluates available funding alternatives in light of ~~contractual arrangements with respect to credit-risk-related contingent features was $274 million at June 30, 2016,~~current 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.

~~Table of Contents~~

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 generated $1.1 billion of cash from~~Cash provided by operating activities ~~during~~was $2.0 billion for the six months ended June 30, 2017, $0.9 billion higher compared to the same period of 2016. This increase was primarily a result of higher sales revenues in 2017 due to the impact of higher commodity prices as well as the $159.5 million payment of the Clean Water Act penalty in 2016 ~~which included~~and $182 million related to severance costs and retirement benefits paid in 2016 in connection with the workforce reduction program. These increases were partially offset by an $881 million tax refund received in 2016 related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback, the $159.5 million payment of the Clean Water Act (CWA) penalty, and the payment of $182 million related to severance costs and retirement benefits in connection with the workforce reduction program. Cash used 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.carryback.

Investing Activities

Capital Expenditures The following presents the Company’s capital expenditures for the six months ended June 30:


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⁾							$	2,296	$	1,879
Adjustments for capital expenditures
Changes in capital accruals	(249		)	(310		)	147		(249		)
Other	(6		)	32			22		(6		)
Total capital expenditures ⁽¹⁾⁽²⁾	$	1,624		$	3,223		$	2,465	$	1,624

________________________________________________________________________________________


⁽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 $437 million for the six months ended June 30, 2017, and $260 million for the six months ended June 30, ~~2016, and $278 million for~~2016. Capital expenditures exclude the ~~six months ended June 30, 2015.~~FPSO capital lease asset.

The Company’s capital expenditures ~~decreased~~increased by ~~$1.6 billion~~$841 million for the six months ended June 30, ~~2016, as reduced development~~2017, primarily due to increases of $395 million driven by U.S. onshore acreage acquisitions and exploration ~~activity resulted~~drilling in the ~~following:~~

Gulf of Mexico, $248 million related to U.S. onshore drilling activity primarily in the Delaware and DJ basins, and $280 million related to the development of the Company’s midstream assets in the Delaware and DJ basins. These increases were partially offset by decreased development costs of ~~$1.2 billion~~$175 million primarily related to the TEN development project in Ghana, which achieved first oil in the ~~Rockies and the Southern and Appalachia Region~~third quarter of 2016.

~~decreased exploration costs of $214 million primarily in Colombia and Mozambique~~

~~decreased gathering, processing, and other costs of $154 million primarily due to lower expenditures for plants and gathering~~Property Exchange On March 17, 2017, WES acquired a third party’s 50% nonoperated interest in the ~~Rockies~~DBJV system in exchange for WES’s 33.75% interest in nonoperated Marcellus midstream assets and $155 million in cash. WES funded the cash consideration with cash on hand and recognized a gain of $126 million as a result of this transaction. After the acquisition, the DBJV system is 100% owned by WES and consolidated by Anadarko. 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, $141 million~~As part of the ~~$442 million~~sale of the Eaglebine assets, the carry ~~obligation had been funded.~~

Inwas canceled 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.2017.

Divestitures During the six months ended June 30, ~~2016,~~2017, Anadarko received ~~pretax sales~~net proceeds ~~related to property divestiture transactions~~ of ~~$900 million~~$3.5 billion from divestitures, primarily related to the ~~divestitures~~sale of ~~certain~~the Company’s U.S. onshore ~~assets in the Rockies, East Texas/Louisiana,~~Eagleford, Marcellus, Eaglebine, and ~~West Texas.~~Utah CBM 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.

Financing Activities



millions except percentages	June 30, 2017			December 31, 2016
Anadarko	$	12,199		$	12,204
WES	3,253			3,091
WGP	28			28
Total debt	$	15,480		$	15,323
Total equity	14,656			15,497
Debt to total capitalization ratio	51.4		%	49.7		%

~~Table of Contents~~

Debt Activity

Anadarko RCFs Anadarko has a $3.0 billion RCF that matures in January 2021 and a $2.0 billion 364-Day Facility that matures in January 2018. At June 30, 2017, the Company had no outstanding borrowings under the APC RCF or the 364-Day Facility.

~~Investments~~WES and WGP RCFs WES has a $1.2 billion RCF that matures in February 2020 and is expandable to $1.5 billion. During the six months ended June 30, ~~2016, the Company made capital contributions of $46~~2017, WES borrowed $160 million under its RCF, which was primarily used 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 percentages June 30,
2016 December 31, 2015
Total debt $ 15,673
$ 15,668
Total equity 14,600
15,457
Debt to total capitalization ratio 51.8 % 50.3 %

~~Senior Notes~~ ~~The following summarizes the Company’s debt activity related to senior notes for the six months ended~~general partnership purposes. At June 30, ~~2016:~~

millions Face 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 $114WES had $160 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 borrowings under its ~~five-year $1.2 billion senior unsecured revolving~~RCF at an interest rate of 2.53%, had outstanding letters of credit ~~facility maturing in February 2019 (WES RCF).~~of $5 million, and had available borrowing capacity of $1.035 billion.

~~Revolving Credit Facilities~~ ~~Anadarko~~WGP has a ~~$3.0 billion five-year senior unsecured revolving credit facility maturing in January 2021 (Five-Year Facility) and the 364-Day Facility~~$250 million RCF that matures in ~~January 2017.~~

~~WES has a $1.2 billion RCF, which is expandable to $1.5 billion. In March 2016, WGP entered into a three-year $250 million senior secured revolving credit facility maturing in~~ March 2019 ~~(WGP RCF), which~~and 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:~~

millions 2016 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.~~

~~Table of Contents~~

~~WES and WGP Credit Facilities~~During 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,~~2017, WGP had outstanding borrowings under its RCF of $28 million at an interest rate of ~~2.72%~~3.23% 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,~~2017, Anadarko’s remaining scheduled debt maturities during ~~2016~~2017 consisted of $17 million of senior amortizing notes associated with the TEUs. At June 30, 2017, Anadarko’s ~~Zero-Coupon~~scheduled debt maturities during 2018 consisted of $17 million of senior amortizing notes associated with the TEUs and $114 million of 7.05% Debentures due May 2018, while WES has $350 million of 2.60% Senior Notes due ~~2036 (Zero Coupons)~~August 2018. 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~~$883 million at the next put date in October ~~2016. The Company classified the~~2017. Anadarko’s $114 million 7.05% Debentures due May 2018 and Zero Coupons were classified as long-term ~~debt~~ on the Company’s Consolidated Balance Sheet at June 30, ~~2016,~~2017, as ~~Anadarko~~the Company 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.

debt. For additional information on the Company’s debt instruments, ~~such as transactions during the period, years of maturity, and interest rates,~~ seeNote 8—Debt ~~and Interest Expense~~ 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.

Derivative Instruments ~~The Company’s~~For information on derivative instruments, ~~are subject to individually negotiated credit provisions that may require collateral of~~including 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.~~

~~Table of Contents~~

~~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. 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 $277~~of $56 million during the six months ended June 30, ~~2015.~~2017, and $51 million during the six months ended June 30, 2016. In response to the ~~current~~ commodity-price environment, the ~~Board~~Company 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 be~~is determined by the Board on a quarterly basis and is based on the Company’s earnings, financial ~~conditions,~~condition, capital requirements, the effect a dividend payment would have on the Company’s compliance with relevant financial covenants, and other factors deemed relevant by the Board.

~~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 distributed~~Distributions to ~~its unitholders other than Anadarko and WGP an aggregate of $127 million during~~noncontrolling interest owners primarily relate to the following for 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 unit for the third quarter of 2008 to $0.830 per common unit for the second quarter of 2016 (to be paid in August 2016).30:

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).

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⁾	$	146	$	127
WES distributions to Series A Preferred unitholders ⁽²⁾	22		2
WGP distributions to unitholders (excluding Anadarko) ⁽³⁾	38		23


⁽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 $0.890 per common unit for the second quarter of 2017 (to be paid in August 2017).


⁽²⁾	WES made quarterly distributions of $0.68 per unit, prorated based on issuance date, to its Series A Preferred unitholders since the unit issuances in March and April 2016. As of June 30, 2017, all Series A Preferred units have converted into WES common units, see Note 14—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10‑Q.


⁽³⁾	WGP has made quarterly distributions to its unitholders since its IPO in December 2012 and has increased its distribution from $0.17875 per common unit for the first quarter of 2013 to $0.52750 per unit for the second quarter of 2017 (to be paid in August 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.

~~Table of Contents~~

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 1517 MMBbls of oil ~~349~~and 249 Bcf of natural gas ~~and 1 MMBbls of NGLs~~ at June 30, ~~2016~~,2017, with a net derivative asset position of ~~$45 million~~.$68 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by ~~$116~~$78 million,, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by ~~$109 million~~.$85 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~~,2017, the Company had a net derivative asset position of $7$4 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,~~APC RCF, 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~~,2017, the Company had a net derivative liability position of ~~$1.8~~$1.4 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~~.$88 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.

~~Table of Contents~~

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~~.2017.

Changes in Internal Control over Financial Reporting

There were no changes in Anadarko’s internal control over financial reporting during the second quarter of ~~2016~~2017 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

~~Table of Contents~~

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

~~GENERAL~~The Company is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the ordinary course of business, including personal injury and death claims; title disputes; tax disputes; royalty claims; contract claims; contamination claims relating to oil and gas exploration, development, production, transportation, and processing; and environmental claims, including claims involving assets owned by acquired companies and claims involving assets previously sold to third parties and no longer a part of the Company’s current operations. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, tribal, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that the resolution of pending proceedings will not have a material adverse effect on the Company’s financial condition, results of operations, or cash flows.

WGR Operating, LP, a wholly owned subsidiary of the Company, is currently in negotiations with the ~~U.S. Environmental Protection Agency and the state of Wyoming~~EPA with respect to alleged noncompliance with the leak detection and repair requirements of the Clean Air Act at its Granger, Wyoming facilities. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this 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.

Kerr-McGee Gathering, LLC, a wholly owned subsidiary of the Company, is currently in negotiations with the EPA and the Department of Justice with respect to alleged noncompliance with the leak detection and repair requirements of the Clean Air Act at its Fort Lupton complex. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.

The Company is currently in negotiations with the EPA with respect to alleged violations of the Resource Conservation and Recovery Act at certain facilities in the Gulf of Mexico. 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 to~~legal matters ~~previously reported in~~that 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 second 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
April 1 - 30, 2017	239,044	$	62.19	—	$	—
May 1 - 31, 2017	4,821	$	59.26	—	$	—
June 1 - 30, 2017	11,631	$	49.37	—	$	—
Total	255,496	$	61.55	—	$	—

____________________________________________________________


⁽¹⁾	During the second 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.

~~Table of Contents~~

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 Anadarko Petroleum Corporation 2008 Director Compensation Plan Annual Deferred Shares (2016), filed as Exhibit 10 (iii) to Form 10-Q filed on May 2, 2016~~
		~~(ii)~~	~~Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as Amended and Restated Effective as of May 10, 2016, filed as Exhibit 10.1 to Form 8-K filed on May 16, 2016~~
*	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

~~Table of Contents~~

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, 2016~~24, 2017	By:	/s/ ROBERT G. GWIN
		Robert G. Gwin Executive Vice President, Finance and Chief Financial Officer



	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	$	—



	Carrying Value
millions	WES			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, net	1			—		27			28			Amortization of discounts, premiums, and debt issuance costs
Balance at June 30, 2016	$	2,932		$	28	$	12,693		$	15,653



millions	Total 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 compensation	34		6		29
Total	$	407	$	48	$	251



millions	2016
Balance at January 1	$	—
Accruals	146
Payments	(126		)
Balance at June 30	$	20



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 Income	3			13			16
Balance at June 30, 2016	$	(39	)	$	(448	)	$	(487	)



millions	Face 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