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 ~~March 31,~~June 30, 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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☒ 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 ~~April 19,~~July 13, 2017, is shown below:



Title of Class		Number of Shares Outstanding
Common Stock, par value $0.10 per share		~~560,339,140~~560,358,149

TABLE OF CONTENTS



PART I		Page
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three and Six Months Ended ~~March 31,~~June 30, 2017 and 2016	3
	Consolidated Statements of Comprehensive Income for the Three and Six Months Ended ~~March 31,~~June 30, 2017 and 2016	4
	Consolidated Balance Sheets at ~~March 31,~~June 30, 2017, and December 31, 2016	5
	Consolidated Statement of Equity for the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2017	6
	Consolidated Statements of Cash Flows for the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2017 and 2016	7
	Notes to Consolidated Financial Statements	8
	Note 1 - Summary of Significant Accounting Policies	8
	Note 2 - Inventories	1110
	Note 3 - Acquisitions, Divestitures, and Assets Held for Sale	11
	Note 4 - Impairments	12
	Note 5 - ~~Suspended~~ Exploratory Well Costs	13
	Note 6 - Current Liabilities	13
	Note 7 - Derivative Instruments	14
	Note 8 - Debt	19
	Note 9 - Income Taxes	2021
	Note 10 - Contingencies	2122
	Note 11 - Restructuring Charges	2122
	Note 12 - Pension Plans and Other Postretirement Benefits	2123
	Note 13 - Stockholders’ Equity	2224
	Note 14 - Noncontrolling Interests	2224
	Note 15 - Variable Interest Entities	2325
	Note 16 - Supplemental Cash Flow Information	2426
	Note 17 - Segment Information	2526
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2730
	Cautionary Statement About Forward-Looking Statements	2730
	Management Overview	2932
	Financial Results	3033
	Liquidity and Capital Resources	3943
	Recent Accounting Developments	4246
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4347
Item 4.	Controls and Procedures	4448
PART II
Item 1.	Legal Proceedings	4549
Item 1A.	Risk Factors	4549
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4549
Item 6.	Exhibits	4650

COMMONLY USED TERMS AND DEFINITIONS

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

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

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

ASU - Accounting Standards Update

Bcf - Billion cubic feet

BOE - Barrels of 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

~~Five-Year Facility~~ ~~- Anadarko’s $3.0 billion five-year senior unsecured RCF maturing in January 2021~~

FPSO - Floating production, storage, and offloading unit

G&A - General and administrative expenses

GAAP - U.S. Generally Accepted Accounting Principles

GOM Acquisition - ~~Acquisition~~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 ~~five-year~~ senior unsecured RCF maturing in February 2020

WGP - Western Gas Equity Partners, LP, a limited partnership and publicly-traded consolidated subsidiary of Anadarko

WGP RCF - WGP’s $250 million three-year senior secured RCF maturing in March 2019

Zero Coupons - Anadarko’s Zero-Coupon Senior Notes due 2036

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
millions except per-share amounts	2017			2016			2017			2016			2017			2016
Revenues and Other
Oil sales	$	1,663		$	850		$	1,422		$	1,125		$	3,085		$	1,975
Natural-gas sales	502			366			319			320			821			686
Natural-gas liquids sales	289			178			214			235			503			413
Gathering, processing, and marketing sales	444			240			464			305			908			545
Gains (losses) on divestitures and other, net	869			40			297			(70		)	1,166			(30		)
Total	3,767			1,674			2,716			1,915			6,483			3,589
Costs and Expenses
Oil and gas operating	258			208			233			202			491			410
Oil and gas transportation	249			242			229			246			478			488
Exploration	1,085			126			535			76			1,620			202
Gathering, processing, and marketing	351			215			359			252			710			467
General and administrative	269			449			291			305			560			754
Depreciation, depletion, and amortization	1,115			1,149			1,037			984			2,152			2,133
Production, property, and other taxes	155			117			135			157			290			274
Impairments	373			16			10			18			383			34
Other operating expense	22			16			12			7			34			23
Total	3,877			2,538			2,841			2,247			6,718			4,785
Operating Income (Loss)	(110		)	(864		)	(125		)	(332		)	(235		)	(1,196		)
Other (Income) Expense
Interest expense	223			220			227			217			450			437
Loss on early extinguishment of debt							2			124			2			124
(Gains) losses on derivatives, net	(147		)	297			32			307			(115		)	604
Other (income) expense, net	(8		)	—			(14		)	(55		)	(22		)	(55		)
Total	68			517			247			593			315			1,110
Income (Loss) Before Income Taxes	(178		)	(1,381		)	(372		)	(925		)	(550		)	(2,306		)
Income tax expense (benefit)	97			(383		)	(38		)	(314		)	59			(697		)
Net Income (Loss)	(275		)	(998		)	(334		)	(611		)	(609		)	(1,609		)
Net income (loss) attributable to noncontrolling interests	43			36			81			81			124			117
Net Income (Loss) Attributable to Common Stockholders	$	(318	)	$	(1,034	)	$	(415	)	$	(692	)	$	(733	)	$	(1,726	)

Per Common Share
Net income (loss) attributable to common stockholders—basic	$	(0.58	)	$	(2.03	)	$	(0.76	)	$	(1.36	)	$	(1.34	)	$	(3.39	)
Net income (loss) attributable to common stockholders—diluted	$	(0.58	)	$	(2.03	)	$	(0.76	)	$	(1.36	)	$	(1.34	)	$	(3.39	)
Average Number of Common Shares Outstanding—Basic	551			509			552			510			552			510
Average Number of Common Shares Outstanding—Diluted	551			509			552			510			552			510
Dividends (per Common Share)	$	0.05		$	0.05		$	0.05		$	0.05		$	0.10		$	0.10

See accompanying Notes to Consolidated Financial Statements.

Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
millions	2017			2016			2017			2016			2017			2016
Net Income (Loss)	$	(275	)	$	(998	)	$	(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			3			1			2			2			5
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	—			(1		)	(1		)	(1		)	(1		)	(2		)
Total adjustments for derivative instruments, net of taxes	1			2			—			1			1			3
Adjustments for pension and other postretirement plans
Net gain (loss) incurred during period	(4		)	(166		)	19			(24		)	15			(190		)
Income taxes on net gain (loss) incurred during period	1			61			(6		)	9			(5		)	70
Prior service credit (cost) incurred during period	—			(1		)	—			—			—			(1		)
Income taxes on prior service credit (cost) incurred during period	—			1			—			—			—			1
Amortization of net actuarial (gain) loss to general and administrative expense	9			8			62			34			71			42
Income taxes on amortization of net actuarial (gain) loss to general and administrative expense	(3		)	(3		)	(23		)	(13		)	(26		)	(16		)
Amortization of net prior service (credit) cost to general and administrative expense	(6		)	(15		)	(6		)	(6		)	(12		)	(21		)
Income taxes on amortization of net prior service (credit) cost to general and administrative expense	2			5			2			3			4			8
Total adjustments for pension and other postretirement plans, net of taxes	(1		)	(110		)	48			3			47			(107		)
Total	—			(108		)	48			4			48			(104		)
Comprehensive Income (Loss)	(275		)	(1,106		)	(286		)	(607		)	(561		)	(1,713		)
Comprehensive income (loss) attributable to noncontrolling interests	43			36			81			81			124			117
Comprehensive Income (Loss) Attributable to Common Stockholders	$	(318	)	$	(1,142	)	$	(367	)	$	(688	)	$	(685	)	$	(1,830	)

See accompanying Notes to Consolidated Financial Statements.

Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)


millions	March 31, 2017			December 31, 2016			June 30, 2017			December 31, 2016
ASSETS
Current Assets
Cash and cash equivalents ($123 and $359 related to VIEs)	$	5,831		$	3,184
Accounts receivable (net of allowance of $16 and $14)
Customers ($81 and $70 related to VIEs)	973			1,007
Others ($12 and $80 related to VIEs)	604			721
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	299			354			322			354
Total	7,707			5,266			7,984			5,266
Properties and Equipment
Cost	64,485			69,013			64,316			69,013
Less accumulated depreciation, depletion, and amortization	35,420			36,845			35,800			36,845
Net properties and equipment ($5,264 and $5,050 related to VIEs)	29,065			32,168
Other Assets ($608 and $609 related to VIEs)	2,182			2,226
Goodwill and Other Intangible Assets ($1,214 and $1,221 related to VIEs)	5,739			5,904
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	$	44,693		$	45,564		$	44,348		$	45,564

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable
Trade ($166 and $234 related to VIEs)	$	1,637		$	1,617
Trade ($176 and $234 related to VIEs)							$	1,626		$	1,617
Other	342			303			273			303
Short-term debt	42			42			44			42
Current asset retirement obligations	258			129			277			129
Other current liabilities	1,483			1,237			934			1,237
Total	3,762			3,328			3,154			3,328
Long-term Debt	15,284			15,281			15,436			15,281
Other Long-term Liabilities
Deferred income taxes	3,664			4,324			4,232			4,324
Asset retirement obligations ($142 and $140 related to VIEs)	2,684			2,802
Asset retirement obligations ($140 and $140 related to VIEs)							2,717			2,802
Other	4,220			4,332			4,153			4,332
Total	10,568			11,458			11,102			11,458

Equity
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 573.0 million and 572.0 million shares issued)	57			57
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	11,914			11,875			11,941			11,875
Retained earnings	1,330			1,704			887			1,704
Treasury stock (21.1 million and 20.8 million shares)	(1,054		)	(1,033		)
Treasury stock (21.4 million and 20.8 million shares)							(1,070		)	(1,033		)
Accumulated other comprehensive income (loss)	(391		)	(391		)	(343		)	(391		)
Total Stockholders’ Equity	11,856			12,212			11,472			12,212
Noncontrolling interests	3,223			3,285			3,184			3,285
Total Equity	15,079			15,497			14,656			15,497
Total Liabilities and Equity	$	44,693		$	45,564		$	44,348		$	45,564

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

See accompanying Notes to Consolidated Financial Statements.

Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)


	Total Stockholders’ Equity																				Total Stockholders’ Equity
millions	Common Stock		Paid-in Capital			Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Non- controlling Interests			Total Equity			Common Stock		Paid-in Capital			Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Non- controlling Interests			Total Equity
Balance at December 31, 2016	$	57	$	11,875		$	1,704		$	(1,033	)	$	(391	)	$	3,285		$	15,497		$	57	$	11,875		$	1,704		$	(1,033	)	$	(391	)	$	3,285		$	15,497
Net income (loss)	—		—			(318		)	—			—			43			(275		)	—		—			(733		)	—			—			124			(609		)
Common stock issued ⁽¹⁾	—		42			—			—			—			—			42			—		85			—			—			—			—			85
Dividends—common stock	—		—			(28		)	—			—			—			(28		)	—		—			(56		)	—			—			—			(56		)
Repurchase of common stock	—		—			—			(21		)	—			—			(21		)	—		—			—			(37		)	—			—			(37		)
Subsidiary equity transactions																					—		(16		)	—			—			—			(11		)	(27		)
Distributions to noncontrolling interest owners	—		—			—			—			—			(105		)	(105		)	—		—			—			—			—			(214		)	(214		)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	—		—			—			—			1			—			1			—		—			—			—			1			—			1
Adjustments for pension and other postretirement plans	—		—			—			—			(1		)	—			(1		)	—		—			—			—			47			—			47
Cumulative effect of accounting change	—		(3		)	(28		)	—			—			—			(31		)	—		(3		)	(28		)	—			—			—			(31		)
Balance at March 31, 2017	$	57	$	11,914		$	1,330		$	(1,054	)	$	(391	)	$	3,223		$	15,079
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)


	Three Months Ended March 31,						Six Months Ended June 30,
millions	2017			2016			2017			2016
Cash Flows from Operating Activities
Net income (loss)	$	(275	)	$	(998	)	$	(609	)	$	(1,609	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	1,115			1,149			2,152			2,133
Deferred income taxes	(660		)	(413		)	(172		)	(820		)
Dry hole expense and impairments of unproved properties	1,012			35			1,466			45
Impairments	373			16			383			34
(Gains) losses on divestitures, net	(804		)	(2		)	(1,009		)	102
Loss on early extinguishment of debt							2			124
Total (gains) losses on derivatives, net	(147		)	299			(115		)	610
Operating portion of net cash received (paid) in settlement of derivative instruments	(8		)	105			5			165
Other	83			115			157			203
Changes in assets and liabilities
(Increase) decrease in accounts receivable	68			46			7			922
Increase (decrease) in accounts payable and other current liabilities	395			(326		)	(278		)	(553		)
Other items, net	(29		)	(163		)	(9		)	(264		)
Net cash provided by (used in) operating activities	1,123			(137		)	1,980			1,092
Cash Flows from Investing Activities
Additions to properties and equipment	(1,194		)	(1,022		)	(2,296		)	(1,879		)
Divestitures of properties and equipment and other assets	2,851			35			3,460			900
Other, net	65			14			52			14
Net cash provided by (used in) investing activities	1,722			(973		)	1,216			(965		)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	—			4,682			159			5,275
Repayments of debt	(10		)	(1,608		)	(31		)	(5,425		)
Financing portion of net cash received (paid) for derivative instruments	(37		)	(555		)	(125		)	(727		)
Increase (decrease) in outstanding checks	28			(150		)	(32		)	(159		)
Dividends paid	(28		)	(25		)	(56		)	(51		)
Repurchase of common stock	(21		)	(30		)	(37		)	(31		)
Issuance of common stock	—			30			—			30
Sale of subsidiary units	—			440			—			1,163
Distributions to noncontrolling interest owners	(105		)	(78		)	(214		)	(159		)
Proceeds from conveyance of future hard minerals royalty revenues, net of transaction costs	—			413			—			413
Payments of future hard minerals royalty revenues conveyed	(25		)	—			(25		)	—
Other financing activities							(11		)	—
Net cash provided by (used in) financing activities	(198		)	3,119			(372		)	329
Effect of Exchange Rate Changes on Cash	—			(1		)	—			(1		)
Net Increase (Decrease) in Cash and Cash Equivalents	2,647			2,008			2,824			455
Cash and Cash Equivalents at Beginning of Period	3,184			939			3,184			939
Cash and Cash Equivalents at End of Period	$	5,831		$	2,947		$	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

General Anadarko Petroleum Corporation is engaged in the exploration, development, production, and ~~marketing~~sale of oil, natural gas, and NGLs and in ~~the marketing of anticipated production of 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, natural gas, and NGLs as well as gathering and disposal of produced water. The Company also participates in the hard-minerals business through royalty arrangements.

Basis of Presentation The accompanying unaudited consolidated financial statements have been prepared in accordance with 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 opinion of management, necessary for the fair presentation of the Company’s consolidated financial statements. Certain prior-period amounts have been reclassified to conform to the current-period presentation. These interim financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.

During the second quarter of 2017, the Company revised its 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 include the accounts of Anadarko and subsidiaries in which Anadarko holds, directly or indirectly, more than 50% of the voting rights and VIEs for which Anadarko is the primary beneficiary. 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 included in other assets.

Recently Adopted Accounting Standards ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, assists in determining whether a transaction should be accounted for as an acquisition or disposal of assets or as a business. This ASU provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the set will not be considered a business. If the screen is not met, a set must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. The Company’s adoption of this ASU on January 1, 2017, using a prospective approach, could have a material impact on consolidated financial statements as goodwill will not be allocated to divestitures or recorded on acquisitions that are not considered ~~to be a business.~~businesses. The Company’s ~~disposition~~dispositions of the Eagleford and Eaglebine oil and gas properties induring the first ~~quarter~~half of 2017 ~~was~~were not considered ~~a business~~businesses under this ASU and therefore not allocated goodwill, see Note 3—Acquisitions, Divestitures, and Assets Held for Sale.

ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory, requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs and eliminates the exception for an intra-entity transfer of an asset other than inventory. The Company adopted this ASU on January 1, 2017, using a modified retrospective approach, and recognized a cumulative adjustment to retained earnings of $31 million during the first quarter of 2017.

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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. ~~The Company adopted~~As a result of adopting this ASU on January 1, ~~2017. As a result of adoption,~~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 ~~three~~six months ended ~~March 31,~~June 30, 2017, the Company recognized a ~~$15~~$13 million tax deficiency as an increase to the provision for income taxes. Cash flows related to excess tax benefits ~~have been~~are classified on a prospective basis as operating activities in the statement of cash flows rather than cash inflows from financing activities and cash outflows from operating activities as previously recognized. Prior periods of the statement of cash flows were not adjusted as there was no material impact. In addition, the Company elected to begin accounting for share-based compensation award forfeitures when they occur instead of estimating the number of forfeitures expected. This change in accounting policy for share-based compensation award forfeitures did not have a material impact on the Company’s consolidated financial statements.

New Accounting Standards Issued But Not Yet Adopted ASU 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period and presentation of the remaining components of net benefit cost in a separate line item outside operating items. Additionally, only the service cost component of net benefit cost will be eligible for capitalization. The Company will adopt this ASU on January 1, 2018, with retrospective presentation of the service cost component and the other components of net benefit cost in the income statement and prospective presentation for the capitalization of the service cost component of net benefit cost in assets. Upon adoption, non-service cost components of net periodic benefit costs of $225 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 ~~is evaluating the impact of the~~does not expect any other material changes upon adoption of this ~~ASU on its consolidated financial statements.~~ASU.

ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The Company ~~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 Company 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 Statement of Cash Flows.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies (Continued)

ASU 2014-09, Revenue from Contracts with Customers (Topic 606), supersedes current revenue recognition requirements and industry-specific guidance. The codification requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing, and uncertainty of revenue and cash flows from contracts with customers. The Company has completed an initial review of contracts in each of its revenue streams and is developing accounting policies to address the provisions of the ASU. While the Company does not currently expect net earnings to be materially impacted, the Company is currently analyzing whether total revenues and total expenses may increase as a result of recognizing both revenue for noncash consideration for services provided by our midstream business and revenue and associated cost of product for the subsequent sale of commodities received as such noncash consideration. Anadarko continues to evaluate the impact of this and other provisions of the ASU on its accounting policies, internal controls, and consolidated financial statements and related disclosures and has not finalized any estimates of the potential impacts. The Company will adopt ~~the~~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.~~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 ~~currently analyzing~~continuing to analyze its portfolio of contracts to assess the ~~impact future adoption~~application of this ASU ~~may~~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, 2017		December 31, 2016
Oil	$	120	$	169
Natural gas	15		38
NGLs	78		106
Total inventories	$	213	$	313

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(Unaudited)

~~2. Inventories~~

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

millions March 31,
2017 December 31,
2016
Oil $ 130
$ 169
Natural gas 19
38
NGLs 94
106
Total inventories $ 243
$ 313

3. Acquisitions, Divestitures, and Assets Held for Sale

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. ~~The fair-value~~Fair-value measurements of the assets acquired and liabilities assumed at the acquisition date were ~~still preliminary as of March 31, 2017, pending customary closing adjustments.~~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 ~~funded the cash consideration with cash on hand and~~ recognized a gain of ~~$125~~$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 ~~three~~six months ended ~~March 31:~~June 30:


millions	2017		2016		2017		2016
Proceeds received, net of closing adjustments	$	2,851	$	35	$	3,460	$	900
Gains (losses) on divestitures, net	804		2		1,009		(102		)

2017 During the ~~three~~six months ended ~~March 31,~~June 30, 2017, the Company divested ~~certain~~of the following U.S. onshore assets:

Eagleford assets, ~~located~~in South Texas, in the ~~Eagleford area of South Texas~~Exploration and Production reporting segment for net proceeds of $2.1 billion and a net gain of ~~$726 million. These~~$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’s divestitures were primarily related to the following U.S. onshore assets included in the ~~oil~~Exploration and ~~gas exploration~~Production reporting segment:

Wamsutter assets, in Wyoming, for net proceeds of $593 million and ~~production reporting segment.~~a net loss of $53 million

~~Certain Marcellus~~ Steward assets, in West Texas, for net proceeds of $138 million, with no gain or loss recognized

East Chalk assets, in East Texas/Louisiana, for net proceeds of $99 million and a net gain of $13 million

U.S. onshore Ozona assets ~~located in Pennsylvania~~ 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 ~~fourth~~second quarter of 2016, at which time the Company remeasured ~~these assets~~them to their current fair value using a market approach and Level 2 fair-value ~~inputs~~measurement and recognized a loss of ~~$129~~$50 million. The sale of these assets closed ~~during~~in the ~~first~~third quarter of 2017 for net proceeds of $763 million and an additional loss of $44 million. Remaining proceeds of $196 million are currently held in escrow by the purchaser, pending regulatory approval. At March 31, 2017, the Company’s Consolidated Balance Sheet included long-term assets of $215 million, which includes $35 million of goodwill, and long-term liabilities of $15 million, primarily associated with Marcellus assets held in escrow subject to regulatory approval.2016.

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(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				Three Months Ended				Six Months Ended
millions	Impairment		Fair Value⁽¹⁾		Impairment		Fair Value⁽¹⁾		Impairment		Fair Value⁽¹⁾
March 31, 2017
Oil and gas exploration and production
June 30, 2017
Exploration and production
U.S. onshore properties					$	2	$	3	$	2	$	3
Gulf of Mexico properties	$	204	$	231	7		—		211		231
Midstream	169		49		—		9		169		58
Other					1		—		1		—
Total	$	373	$	280	$	10	$	12	$	383	$	292


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

Impairments during the ~~three~~six months ended ~~March 31,~~June 30, 2017, were primarily related to oil and gas properties in the Gulf of Mexico due to lower forecasted commodity prices and a U.S. onshore midstream property due to a reduced throughput fee as a result of a producer’s bankruptcy.

Impairments of Unproved Properties Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. The Company recognized ~~$532~~$555 million of impairments of unproved Gulf of Mexico properties during the ~~three~~six months ended ~~March 31,~~June 30, 2017, primarily due to an impairment of ~~which $467~~$463 million ~~related~~ to the Shenandoah project. The unproved property balance related to the Shenandoah project originated from the purchase price allocated to Gulf of Mexico exploration projects from the acquisition of Kerr-McGee Corporation in 2006. For additional details on the Shenandoah project, see Note 5—~~Suspended~~ Exploratory Well Costs.

Potential for Future Impairments

Oil price sensitivity At ~~March 31,~~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 ~~$2.7~~$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 ~~$1.0 billion.~~$800 million.

Natural-gas price sensitivityAt ~~March 31,~~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 ~~$1.3~~$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 significant declines in commodity prices, further changes to the Company’s drilling plans in response to lower prices, reduction of proved and probable reserve estimates, or increases in drilling or operating costs could result in other additional impairments.

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(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 ~~$1.1 billion~~$888 million at ~~March 31,~~June 30, 2017, and $1.2 billion at December 31, 2016. Projects with suspended exploratory well costs include wells that have sufficient reserves to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time.

During the ~~three~~six months ended ~~March 31,~~June 30, 2017, ~~the Company expensed~~$392 million of suspended exploratory well costs ~~of $435 million related to the Shenandoah project in the Gulf of Mexico, including $267 million~~ previously capitalized for ~~a period~~ greater than one year. The Shenandoah-6 appraisal well and subsequent sidetrack, which completed appraisal activities in April 2017, did not encounter the oil-water contact in the eastern portion of the field. Given the results of this well and the present commodity-price environment, the Company has currently suspended further appraisal activities. Accordingly, the Company determined that the Shenandoah project no longer satisfies the accounting requirements for the continued capitalization of the exploratory well costs.year at December 31, 2016, were charged to exploration expense.

6. Current Liabilities

Accounts Payable Accounts payable, trade included liabilities of ~~$290~~$230 million at ~~March 31,~~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	March 31, 2017		December 31, 2016		June 30, 2017		December 31, 2016
Accrued income taxes	$	671	$	6	$	55	$	6
Interest payable	161		244		245		244
Production, property, and other taxes payable	253		239		215		239
Accrued employee benefits	185		355		183		355
Other	213		393		236		393
Total other current liabilities	$	1,483	$	1,237	$	934	$	1,237

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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.

Oil and Natural-Gas Production/Processing Derivative Activities The oil prices listed below are a combination of 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 ~~March 31,~~June 30, 2017:


	2017 Settlement		2018 Settlement		2017 Settlement		2018 Settlement
Oil
Three-Way Collars (MBbls/d)	91		—		91		—
Average price per barrel
Ceiling sold price (call)	$	59.80	$	—	$	59.80	$	—
Floor purchased price (put)	$	50.00	$	—	$	50.00	$	—
Floor sold price (put)	$	40.00	$	—	$	40.00	$	—
Natural Gas
Three-Way Collars (thousand MMBtu/d)	682		250		857		250
Average price per MMBtu
Ceiling sold price (call)	$	3.60	$	3.54	$	3.64	$	3.54
Floor purchased price (put)	$	2.75	$	2.75	$	2.85	$	2.75
Floor sold price (put)	$	2.00	$	2.00	$	2.10	$	2.00
Fixed-Price Contracts (thousand MMBtu/d)	19		—
Average price per MMBtu	$	2.82	$	—

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

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

Interest-Rate Derivatives Anadarko has outstanding interest-rate swap contracts to manage interest-rate risk associated with anticipated debt issuances. The Company has locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month LIBOR.

In June 2017, the Company amended certain interest-rate swaps with an aggregate notional principal amount of $625 million, extending the mandatory termination dates from 2018 to 2020, 2022, and 2023 in exchange for cash payments of approximately $57 million. In July 2017, the Company amended an interest-rate swap with a notional principal amount of $125 million, extending the mandatory termination date from 2018 to 2022 in exchange for a cash payment of approximately $15 million.

At ~~March 31,~~June 30, 2017, the Company had outstanding interest-rate swaps with a notional amount of $1.6 billion due prior to or in September ~~2021~~2023 that manage interest-rate risk associated with the potential refinancing of the Company’s $900 million Senior Notes due 2019 and the Zero Coupons due 2036, should the Zero Coupons be put to the Company prior to the swap termination dates. At the next put date in October 2017, the accreted value of the Zero Coupons will be $883 million. See ~~Note 8—Debt~~.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. ~~Cash~~Net cash payments related to settlements and amendments of interest-rate swap agreements were ~~$24~~$65 million during the ~~three~~six months ended ~~March 31,~~June 30, 2017, and $193 million during the ~~three~~six months ended ~~March 31,~~June 30, 2016.

~~The Company had the following outstanding interest-rate swaps at March 31, 2017:~~

millions except percentages Mandatory Weighted-Average
Notional Principal Amount Reference Period Termination Date Interest Rate
$ 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%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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	March 31,		December 31,		March 31,			December 31,			June 30,		December 31,		June 30,			December 31,
Balance Sheet Classification	2017		2016		2017			2016			2017		2016		2017			2016
Commodity derivatives
Other current assets	$	51	$	10	$	(31	)	$	(3	)	$	88	$	10	$	(13	)	$	(3	)
Other assets	12		9		—			—			8		9		—			—
Other current liabilities	15		66		(35		)	(201		)	1		66		(9		)	(201		)
Other liabilities	—		—		—			(12		)	—		—		(3		)	(12		)
	78		85		(66		)	(216		)	97		85		(25		)	(216		)
Interest-rate derivatives
Other current assets	8		8		—			—			12		8		—			—
Other assets	23		23		—			—			37		23		—			—
Other current liabilities	—		—		(69		)	(48		)	—		—		(69		)	(48		)
Other liabilities	—		—		(1,271		)	(1,328		)	—		—		(1,338		)	(1,328		)
	31		31		(1,340		)	(1,376		)	49		31		(1,407		)	(1,376		)
Total derivatives	$	109	$	116	$	(1,406	)	$	(1,592	)	$	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 March 31,						Three Months Ended June 30,					Six Months Ended June 30,
Classification of (Gain) Loss Recognized	2017			2016			2017			2016		2017			2016
Commodity derivatives
Gathering, processing, and marketing sales ⁽¹⁾	$	—		$	2		$	—		$	4	$	—		$	6
(Gains) losses on derivatives, net	(135		)	(28		)	(72		)	94		(207		)	66
Interest-rate derivatives
(Gains) losses on derivatives, net	(12		)	325			104			213		92			538
Total (gains) losses on derivatives, net	$	(147	)	$	299		$	32		$	311	$	(115	)	$	610


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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.

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 S&P and Moody’s declines to a level that is below investment grade. As of ~~March 31,~~June 30, 2017, the Company’s long-term debt was rated below investment grade (Ba1) by Moody’s and investment grade (BBB) by both S&P and Fitch Ratings. Although certain counterparties required the Company to post collateral due to the 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 $1.2 billion (net of ~~$130~~$177 million of collateral) at ~~March 31,~~June 30, 2017, and $1.4 billion (net of $117 million of collateral) at December 31, 2016.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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			Level 1			Level 2			Level 3		Netting ⁽¹⁾			Collateral		Total
March 31, 2017
June 30, 2017
Assets
Commodity derivatives	$	—		$	78		$	—	$	(45	)	$	—	$	33		$	—		$	97		$	—	$	(14	)	$	—	$	83
Interest-rate derivatives	—			31			—		—			—		31			—			49			—		—			—		49
Total derivative assets	$	—		$	109		$	—	$	(45	)	$	—	$	64		$	—		$	146		$	—	$	(14	)	$	—	$	132
Liabilities
Commodity derivatives	$	(1	)	$	(65	)	$	—	$	45		$	2	$	(19	)	$	—		$	(25	)	$	—	$	14		$	—	$	(11	)
Interest-rate derivatives	—			(1,340		)	—		—			130		(1,210		)	—			(1,407		)	—		—			177		(1,230		)
Total derivative liabilities	$	(1	)	$	(1,405	)	$	—	$	45		$	132	$	(1,229	)	$	—		$	(1,432	)	$	—	$	14		$	177	$	(1,241	)

December 31, 2016
Assets
Commodity derivatives	$	2		$	83		$	—	$	(69	)	$	—	$	16		$	2		$	83		$	—	$	(69	)	$	—	$	16
Interest-rate derivatives	—			31			—		—			—		31			—			31			—		—			—		31
Total derivative assets	$	2		$	114		$	—	$	(69	)	$	—	$	47		$	2		$	114		$	—	$	(69	)	$	—	$	47
Liabilities
Commodity derivatives	$	(3	)	$	(213	)	$	—	$	69		$	6	$	(141	)	$	(3	)	$	(213	)	$	—	$	69		$	6	$	(141	)
Interest-rate derivatives	—			(1,376		)	—		—			117		(1,259		)	—			(1,376		)	—		—			117		(1,259		)
Total derivative liabilities	$	(3	)	$	(1,589	)	$	—	$	69		$	123	$	(1,400	)	$	(3	)	$	(1,589	)	$	—	$	69		$	123	$	(1,400	)

__________________________________________________________________


⁽¹⁾	Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Debt

Debt The following summarizes the Company’s outstanding debt, including capital lease obligations, after eliminating the effect of intercompany transactions:


millions	WES			WGP ⁽¹⁾		Anadarko ⁽²⁾			Anadarko Consolidated			WES			WGP ⁽¹⁾		Anadarko ⁽²⁾			Anadarko Consolidated
March 31, 2017
June 30, 2017
Total borrowings at face value	$	3,120		$	28	$	13,550		$	16,698		$	3,280		$	28	$	13,531		$	16,839
Net unamortized discounts, premiums, and debt issuance costs ⁽³⁾	(28		)	—		(1,587		)	(1,615		)	(27		)	—		(1,575		)	(1,602		)
Total borrowings ⁽⁴⁾	3,092			28		11,963			15,083			3,253			28		11,956			15,237
Capital lease obligations	—			—		243			243			—			—		243			243
Less short-term debt	—			—		42			42			—			—		44			44
Total long-term debt	$	3,092		$	28	$	12,164		$	15,284		$	3,253		$	28	$	12,155		$	15,436

December 31, 2016
Total borrowings at face value	$	3,120		$	28	$	13,558		$	16,706		$	3,120		$	28	$	13,558		$	16,706
Net unamortized discounts, premiums, and debt issuance costs ⁽³⁾	(29		)	—		(1,599		)	(1,628		)	(29		)	—		(1,599		)	(1,628		)
Total borrowings ⁽⁴⁾	3,091			28		11,959			15,078			3,091			28		11,959			15,078
Capital lease obligations	—			—		245			245			—			—		245			245
Less short-term debt	—			—		42			42			—			—		42			42
Total long-term debt	$	3,091		$	28	$	12,162		$	15,281		$	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 RCFs are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.


⁽⁴⁾	The Company’s outstanding borrowings, except for borrowings under the WGP RCF, are senior unsecured.

Fair Value The Company uses a market approach to determine the fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was ~~$17.0~~$17.2 billion at ~~March 31,~~June 30, 2017, and $17.1 billion at December 31, 2016.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Debt (Continued)

Anadarko Borrowings Anadarko has a $3.0 billion ~~five-year~~ senior unsecured RCF maturing in January 2021 ~~(Five-Year Facility)~~(APC RCF) and a $2.0 billion 364-day senior unsecured RCF maturing in January 2018 (364-Day Facility). ~~In January 2017, the Company extended the maturity date of the 364-Day Facility until January 2018.~~ At ~~March 31,~~June 30, 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.

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, 2017, as the Company has the ability and intent to refinance these obligations using long-term debt. The Zero Coupons can be put to the Company in October of each year, in whole or in part, for the then-accreted value, which will be $883 million at the next put date in October 2017. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at March 31, 2017, as the Company has the ability and intent to refinance these obligations using long-term debt, should the put be exercised.

In January 2015, the Company initiated a commercial paper program, which allows for a maximum of $3.0 billion of unsecured commercial paper notes and is supported by the Five-Year Facility. The maturities of the commercial paper notes may vary, but may not exceed 397 days. Due to the Company’s below-investment-grade credit rating from Moody’s, the Company currently does not have access to the commercial paper market and had no outstanding borrowings under the commercial paper program at March 31, 2017.

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A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~8. Debt (Continued)~~

The Company also has notes payable related to its ownership of certain noncontrolling mandatorily redeemable interests that are not included in the Company’s reported debt balance and do not affect consolidated interest expense. See Note 8—Equity Method Investments in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.

WES and WGP Borrowings At ~~March 31,~~June 30, 2017, WES was in compliance with all related covenants contained in its $1.2 billion ~~five-year~~ senior unsecured RCF maturing in February 2020 (WES RCF), which is expandable to $1.5 billion. ~~At March 31,~~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, 2017, WES had no outstanding borrowings under its RCF of $160 million at an interest rate of 2.53%, had outstanding letters of credit of $5 million, and had available borrowing capacity of ~~$1.195~~$1.035 billion.

At ~~March 31,~~June 30, 2017, WGP was in compliance with all related covenants contained in its $250 million three-year senior secured 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. At ~~March 31,~~June 30, 2017, WGP had outstanding borrowings under its RCF of $28 million at an interest rate of ~~2.99%~~3.23% and had available borrowing capacity of $222 million.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

9. Income Taxes

The following summarizes income tax expense (benefit) and effective tax rates:


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
millions except percentages	2017			2016			2017			2016			2017			2016
Income tax expense (benefit)	$	97		$	(383	)
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	(178		)	(1,381		)	(372		)	(925		)	(550		)	(2,306		)
Effective tax rate	(54		)%	28		%	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 ~~March 31,~~June 30, 2017 and 2016. ~~As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect.~~ The decrease from the 35% U.S. federal statutory rate for the three months ended ~~March 31,~~June 30, 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

•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

net changes in uncertain tax positions


•	~~tax deficiency related to share-based compensation due to the adoption of ASU 2016-09, see~~ ~~Note 1—Summary of Significant Accounting Policies~~

These decreases were partially offset by the following increases:

•income attributable to noncontrolling interests

•federal manufacturing deduction

The decrease from the 35% U.S. federal statutory rate for the three and six months ended ~~March 31,~~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 ~~March 31,~~June 30, 2017, the Company’s Consolidated Balance Sheet included ~~$167~~$361 million of income taxes receivable presented in accounts receivable—others.

2021

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10. Contingencies

Litigation There are no material developments in previously reported contingencies nor are there any other material matters that have arisen since the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.

11. Restructuring Charges

In the first quarter of 2016, the Company initiated a workforce reduction program to align the size and composition of its workforce with its expected future operating and capital plans. Employee notifications related to the workforce reduction program were completed by June 30, 2016. The Company recognized ~~$203 million of~~ restructuring charges included in G&A in the Company’s Consolidated Statements of Income of $48 million during the three months ended ~~March 31,~~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 an estimated $29 million~~ of settlement expense expected to be recognized during 2017 for lump-sum payments to terminated ~~participants~~participants. During the six months ended June 30, 2017, the Company recognized restructuring charges of $17 million, primarily related to settlement expense. Restructuring charges for ~~which~~ the ~~amount~~remainder of 2017 could vary depending on market conditions and participant ~~elections.~~elections but are not expected to be material.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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	2017			2016			2017			2016			2017			2016			2017			2016
Three Months Ended March 31
Three Months Ended June 30
Service cost	$	21		$	26		$	—		$	1		$	21		$	23		$	1		$	—
Interest cost	21			26			3			3			21			23			3			3
Expected (return) loss on plan assets	(21		)	(27		)	—			—			(21		)	(24		)	—			—
Amortization of net actuarial loss (gain)	6			8			—			—			7			10			—			—
Amortization of net prior service cost (credit)	—			—			(6		)	(6		)	—			—			(6		)	(6		)
Settlement expense	3			—			—			—			55			24			—			—
Termination benefits expense ⁽¹⁾	4			44			—			—
Curtailment expense ⁽¹⁾	—			8			—			(3		)
Curtailment expense													—			—			—			3
Net periodic benefit cost	$	34		$	85		$	(3	)	$	(5	)	$	83		$	56		$	(2	)	$	—

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

⁽¹⁾

~~Termination benefits expense and curtailment expense for the three months ended March 31, 2016, relate to the workforce reduction program initiated in the first quarter of 2016.~~

During the six months ended June 30, 2017, the Company recognized $58 million of settlement expense. These settlements resulted in remeasurements of its pension plans during 2017. The remeasurements in 2017 resulted in a net liability decrease of $15 million for the pension benefit plans, with a corresponding increase in other comprehensive income. Settlement expense, termination benefits expense, and curtailment expense for 2016 relate to the workforce reduction program. See Note 11—Restructuring Charges.

The Company contributed ~~$60~~$85 million during the ~~three~~six months ended ~~March 31,~~June 30, 2017, and expects to contribute an additional ~~$107~~$82 million to funded pension plans during 2017.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 ~~Tangible Equity Units (TEUs)~~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 EPS attributable to common stockholders:


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
millions except per-share amounts	2017			2016			2017			2016			2017			2016
Net income (loss)
Net income (loss) attributable to common stockholders	$	(318	)	$	(1,034	)	$	(415	)	$	(692	)	$	(733	)	$	(1,726	)
Income (loss) effect of TEUs	(2		)	(1		)	(2		)	(2		)	(4		)	(3		)
Basic	$	(320	)	$	(1,035	)	$	(417	)	$	(694	)	$	(737	)	$	(1,729	)
Income (loss) effect of TEUs							(1		)	(1		)	(1		)	(1		)
Diluted	$	(320	)	$	(1,035	)	$	(418	)	$	(695	)	$	(738	)	$	(1,730	)
Shares
Average number of common shares outstanding—basic	551			509			552			510			552			510
Average number of common shares outstanding—diluted	551			509			552			510			552			510
Excluded due to anti-dilutive effect	11			10			11			11			11			10
Net income (loss) per common share
Basic	$	(0.58	)	$	(2.03	)	$	(0.76	)	$	(1.36	)	$	(1.34	)	$	(3.39	)
Diluted	$	(0.58	)	$	(2.03	)	$	(0.76	)	$	(1.36	)	$	(1.34	)	$	(3.39	)

14. Noncontrolling Interests

WES is a limited partnership formed by Anadarko to acquire, own, develop, and operate midstream assets. During 2016, WES issued 22 million Series A Preferred units to private investors for net proceeds of $687 million and issued 1.3 million common units to the Company. Proceeds from these issuances were primarily used to acquire interests in Springfield Pipeline LLC from the Company. Pursuant to an agreement between WES and the holders of the Series A Preferred units, 50% of the Series A Preferred units converted into WES common units on a one-for-one basis on March 1, 2017, ~~with~~and the remaining Series A Preferred units ~~to be~~ converted inon May 2, 2017.

WES Class C units issued to Anadarko will convert into WES common units on a one-for-one basis on the conversion date, which was extended in February 2017 from December 31, 2017, to March 1, 2020. The Class C units receive quarterly distributions in the form of additional Class C units until the March 1, 2020 conversion date unless WES elects to convert the units to common units earlier or Anadarko elects to extend the conversion date. WES distributed ~~179~~385 thousand Class C units to Anadarko during the ~~three~~six months ended ~~March 31,~~June 30, 2017, and 946 thousand Class C units to Anadarko during 2016.

WGP is a limited partnership formed by Anadarko to own interests in WES. During 2016, Anadarko sold 12.5 million WGP common units to the public for net proceeds of $476 million.At ~~March 31,~~June 30, 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 ~~March 31,~~June 30, 2017, WGP’s ownership interest in WES consisted of a 29.9% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At ~~March 31,~~June 30, 2017, Anadarko also owned an ~~8.7%~~8.8% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining ~~59.9%~~59.8% limited partner interest in WES was owned by the public.

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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 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 ~~March 31,~~June 30, 2017, and December 31, 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 ~~March 31,~~June 30, 2017, and December 31, 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 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 Note 14—Noncontrolling Interests for additional information on WGP and WES financing activity.

Financial Support Provided to VIEs Concurrent with the closing of its May 2008 IPO, WES loaned the Company $260 million in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The related interest income for WES was $4 million for each of the three months ended ~~March 31,~~June 30, 2017 and 2016, and $8 million for each of the six months ended June 30, 2017 and 2016. The note receivable and related interest income are eliminated in consolidation.

In March 2015, WES acquired the Company’s interest in DBJV. The acquisition was financed using a deferred purchase price obligation ~~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 ~~due~~ to the Company isof $37 million, equal to ~~eight multiplied by~~ the average of WES’s share in DBJV Net Earnings (defined below) for 2018 and 2019 less WES’s share of capital expenditures incurred for DBJV from March 1, 2015 to February 29, 2020. Net Earnings is defined as all revenues less cost of product, operating expenses, and property taxes. The net present value of ~~this~~the obligation ~~was $37 million~~ at March 31, 2017, and $41 million at December 31, 2016. The reduction in the value of the deferred purchase price obligation was primarily due to revisions reflecting a decrease in WES’s estimate of future Net Earnings, partially offset by a decrease in WES’s estimate of capital expenditures to be incurred by DBJV.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 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 capital contribution from Anadarko of ~~$12~~$29 million for the ~~three~~six months ended ~~March 31,~~June 30, 2017, and $7$16 million for the ~~three~~six months ended ~~March 31,~~June 30, 2016.

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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:


	Three Months Ended March 31,						Six Months Ended June 30,
millions	2017			2016			2017			2016
Cash paid (received)
Interest, net of amounts capitalized	$	308		$	299		$	449		$	427
Income taxes, net of refunds(1)	1			(8		)	162			(883		)
Non-cash investing activities
Fair value of properties and equipment from non-cash transactions	$	549		$	—		$	553		$	3
Asset retirement cost additions	61			27			138			49
Accruals of property, plant, and equipment	608			623			696			505
Net liabilities assumed (divested) in acquisitions and divestitures	(82		)	—			(100		)	(36		)
Non-cash investing and financing activities
FPSO construction period obligation ⁽¹⁾⁽²⁾	$	—		$	2		$	—		$	11
Deferred drilling lease liability	7			—			13			—


⁽¹⁾	Includes $881 million from a tax refund in 2016 related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback.


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

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

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, 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, natural-gas, and NGLs 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~~

Table of ~~Anadarko’s oil, natural-gas, and NGLs production as well as third-party purchased volumes.~~Contents

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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; impairments; 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 G&A, ~~did not relate to the Company’s normal operations.~~loss on early extinguishment of debt, and certain other nonoperating items included in other (income) expense, net.

The Company’s definition of Adjusted EBITDAX excludes gains (losses) on divestitures, net and exploration expense as they are not indicators of operating efficiency for a given reporting period. 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 Adjusted EBITDAX provides information useful in assessing the Company’s operating and financial performance across periods. Adjusted EBITDAX as defined by Anadarko may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures, such as operating income. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes:


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
millions	2017			2016			2017			2016			2017			2016
Income (loss) before income taxes	$	(178	)	$	(1,381	)	$	(372	)	$	(925	)	$	(550	)	$	(2,306	)
Interest expense	223			220			227			217			450			437
DD&A	1,115			1,149			1,037			984			2,152			2,133
Exploration expense	1,085			126			535			76			1,620			202
(Gains) losses on divestitures, net	(804		)	(2		)	(205		)	104			(1,009		)	102
Impairments	373			16			10			18			383			34
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	(155		)	404			45			371			(110		)	775
Restructuring charges	(1		)	203			18			48			17			251
Other operating expense	—			1			—			—			—			1
Loss on early extinguishment of debt							2			124			2			124
Certain other nonoperating items							—			(56		)	—			(56		)
Less net income (loss) attributable to noncontrolling interests	43			36			81			81			124			117
Consolidated Adjusted EBITDAX	$	1,615		$	700		$	1,216		$	880		$	2,831		$	1,580

2527

Table of Contents

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, net cash from settlement of commodity derivatives, and net income (loss) attributable to noncontrolling interests. The following summarizes selected financial information for Anadarko’s reporting segments:


millions	Oil and Gas Exploration & Production			Midstream		Marketing			Other and Intersegment Eliminations			Total			Exploration & Production			Midstream		Other and Intersegment Eliminations			Total
Three Months Ended March 31, 2017
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															—			—		(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	$	1,524		$	225	$	1,149		$	—		$	2,898		$	1,680		$	280	$	25		$	1,985
Intersegment revenues	871			361		(1,024		)	(208		)	—			—			218		(218		)	—
Other ⁽¹⁾	2			33		6			24			65			(14		)	28		20			34
Total revenues and other ⁽²⁾	2,397			619		131			(184		)	2,963			1,666			526		(173		)	2,019
Operating costs and expenses ⁽³⁾	866			317		165			(43		)	1,305			861			234		26			1,121
Net cash from settlement of commodity derivatives	—			—		—			6			6			—			—		(60		)	(60		)
Other (income) expense, net	—			—		—			(8		)	(8		)	—			—		1			1
Net income (loss) attributable to noncontrolling interests ⁽¹⁾	—			—		—			43			43			—			—		81			81
Total expenses and other	866			317		165			(2		)	1,346			861			234		48			1,143
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		(2		)	—			(2		)	—			—		4			4
Adjusted EBITDAX	$	1,531		$	302	$	(36	)	$	(182	)	$	1,615		$	805		$	292	$	(217	)	$	880

Three Months Ended March 31, 2016
Sales revenues	$	711		$	125	$	798		$	—		$	1,634
Intersegment revenues	601			302		(663		)	(240		)	—
Other ⁽¹⁾	(1		)	13		1			25			38
Total revenues and other ⁽²⁾	1,311			440		136			(215		)	1,672
Operating costs and expenses ⁽³⁾	773			183		176			(89		)	1,043
Net cash from settlement of commodity derivatives	—			—		—			(103		)	(103		)
Net income (loss) attributable to noncontrolling interests(1)	—			—		—			36			36
Total expenses and other	773			183		176			(156		)	976
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		4			—			4
Adjusted EBITDAX	$	538		$	257	$	(36	)	$	(59	)	$	700

__________________________________________________________________


⁽¹⁾	Presentation has been adjusted to align with the current analysis of segment performance. Net income (loss) attributable to noncontrolling interests, previously reported within the Midstream segment, is now presented within Other and Intersegment Eliminations. Other revenues, previously reported within Other and Intersegment Eliminations, is now presented within the applicable segments.


⁽²⁾	Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.


⁽³⁾	Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX.

Table of Contents

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

17. Segment Information (Continued)



millions	Exploration & Production			Midstream		Other and Intersegment Eliminations			Total
Six Months Ended June 30, 2017
Sales revenues	$	4,409		$	850	$	58		$	5,317
Intersegment revenues	—			349		(349		)	—
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	—			—		(7		)	(7		)
Other (income) expense, net	—			—		(22		)	(22		)
Net income (loss) attributable to noncontrolling interests ⁽¹⁾	—			—		124			124
Total expenses and other	1,728			672		241			2,641
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		(2		)	(2		)
Adjusted EBITDAX	$	2,691		$	614	$	(474	)	$	2,831

Six Months Ended June 30, 2016
Sales revenues	$	3,074		$	494	$	51		$	3,619
Intersegment revenues	—			444		(444		)	—
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	—			—		(163		)	(163		)
Other (income) expense, net	—			—		1			1
Net income (loss) attributable to noncontrolling interests ⁽¹⁾	—			—		117			117
Total expenses and other	1,709			430		(20		)	2,119
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		8			8
Adjusted EBITDAX	$	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.


⁽³⁾	Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX.

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

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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

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

the Company’s assumptions about energy markets

production and sales volume levels

levels of oil, natural-gas, and NGLs reserves

operating results

competitive conditions

technology

availability of capital resources, levels of capital expenditures, and other contractual obligations

supply and demand for, the price of, and the commercialization and transporting of oil, natural gas, NGLs, and other products or services

volatility in the commodity-futures market

weather

inflation

availability of goods and services, including unexpected changes in costs

drilling and other operational risks

processing volumes and pipeline throughput

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, including regulations related to climate change; environmental risks; and liability under international, provincial, federal, regional, state, tribal, local, and foreign environmental laws and regulations

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

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

volatility in the securities, capital, or credit markets and related risks such as general credit, liquidity, and interest-rate risk

the Company’s ability to successfully monetize select assets, 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 and NGLs cargo shipping activities

physical, digital, internal, and external security breaches

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

the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigation by the 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, 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, 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, 2016.

MANAGEMENT OVERVIEW

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 Delaware and DJ basins in the U.S. onshore and deepwater Gulf of Mexico. ~~The GOM Acquisition expanded~~ Anadarko’s ~~operated infrastructure and substantial tie-back inventory and doubled its net production from the~~deepwater Gulf of Mexico ~~to approximately 160 MBOE/d, more than 80% of which is comprised of oil. The acquired~~ assets are expected to generate substantial cash ~~flow~~flows over the next five years at current strip prices. The Company plans to use the cash flows from the Gulf of Mexico as well as from ~~our~~its international ~~cash generating~~producing assets to fund growth in the Company’s unconventional assets in the Delaware and DJ basins. Much of the 2017 operational focus is preparing the Delaware basin for development with increased operatorship and infrastructure to facilitate long-term growth and value. The Company ended the ~~first~~second quarter of 2017 with 1416 operated drilling rigs in the Delaware basin and 6 operated drilling rigs in the DJ basin, which compares to 914 operated drilling rigs in the Delaware basin and 56 operated drilling rigs in the DJ basin at ~~year-end 2016.~~the end of the first quarter of 2017. In the deepwater Gulf of Mexico, Anadarko has ~~three~~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 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 two-phase Notice to Operators (NTO) requiring all operators to inventory and integrity test existing flowlines within 1,000 feet of a building unit and abandon all inactive flowlines in such areas. The Company expects to meet the NTO compliance deadline, is cooperating fully with the NTSB in its investigation, and continues to work cooperatively with state regulators and others.

Anadarko currently estimates a 2017 ~~initial~~ capital spending range of ~~$5.4~~$5.1 billion to ~~$5.7~~$5.4 billion, which represents ~~an increase~~a decrease of more than ~~63%~~5% from ~~2016.~~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 $900 million to $1.0 billion for WES. The Company has currently allocated approximately 80% of its 2017 capital spending budget to the U.S. onshore upstream and midstream and deepwater Gulf of ~~Mexico;~~Mexico development; 15% to future value areas, such as deepwater exploration and ~~global~~Mozambique LNG; 2% to international cash generation assets, such as oil projects in Algeria and Ghana; and 3% to corporate activities. The Company’s 2017 ~~initial~~ capital program was designed to leverage its streamlined portfolio and sharpened focus on higher-margin oil production.

The Company will continue to evaluate the oil and natural-gas price environments and may adjust its capital spending plans while maintaining appropriate liquidity and financial ~~flexibility.~~flexibility with cash on the balance sheet, ownership of marketable securities in WGP, and access to credit facilities.

~~As an oil and natural-gas exploration and production company,~~ Anadarko’s revenues, operating results, cash flows from operations, capital spending, and future growth rates are highly influenced by commodity prices, which affect the value the Company receives from its sales of oil, natural gas, and NGLs.

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

Total Company

Anadarko’s overall sales-volume product mix increased to ~~61%~~67% liquids in the ~~first~~second quarter of 2017, compared to ~~53%~~54% in the ~~first~~second quarter of 2016, which significantly improved margins.

Anadarko’s ~~first-quarter~~second-quarter oil sales volumes averaged ~~367~~331 MBbls/d, representing a ~~16%~~ 12% increase from the ~~first~~second quarter of 2016, primarily due to increased volumes from the ~~GOM Acquisition~~Gulf of Mexico and the startup of TEN offshore Ghana, partially offset by divestitures of U.S. onshore oil and gas assets in 2016 and 2017.

U.S. Onshore

Oil sales volumes in the Delaware basin increased 1011 MBbls/d, representing a ~~46%~~52% increase from the ~~first~~second quarter of 2016, due to ~~increased~~continued drilling ~~activity.~~

~~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.~~completion activities.

Anadarko closed the ~~divestiture~~divestitures of its ~~Eagleford~~Eaglebine and ~~Marcellus~~Utah CBM assets during the quarter for net proceeds of ~~$2.8 billion,~~$604 million, prior to final closing adjustments.

Gulf of Mexico

Oil sales volumes averaged ~~125~~113 MBbls/d, representing a ~~116%~~102% increase from the ~~first~~second quarter of 2016, primarily due to ~~the GOM Acquisition and~~ continued tieback activity at several ~~facilities.~~

facilities and activity from the GOM Acquisition.

International

~~First-quarter~~Second-quarter sales volumes averaged ~~104~~93 MBbls/d, representing a ~~17%~~26% increase from the ~~first~~second quarter of 2016, primarily as a result of the TEN development project (19% nonoperated participating interest) in Ghana achieving first oil in the third quarter of 2016.

Interim mooring of the FPSO at the Jubilee field in Ghana commenced in the fourth quarter of 2016 and was completed during the first quarter of 2017. Final decisions and approvals will be sought for the long-term turret system solution in ~~mid-2017.~~the third quarter of 2017. It is anticipated that a facility shutdown of ~~up to 12~~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.

~~During~~The Company is completing many of the ~~quarter, the Company made progress towards finalizing major~~core components of the legal and contractual framework for ~~the~~its LNG project in ~~Mozambique, which will support investment, beginning with the resettlement project, and also~~Mozambique. The progress helps position the Company to ~~secure~~advance negotiations in securing long-term LNG offtake ~~contracts.~~contracts as it continues toward a final investment decision.

Financial

The Company generated ~~$1.1 billion~~$857 million of cash flow from operations and ended the quarter with ~~$5.8~~$6.0 billion of cash.

~~In January 2017, the Company extended the maturity date of the 364-Day Facility until January 2018.~~

FINANCIAL RESULTS


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
millions except per-share amounts	2017			2016			2017			2016			2017			2016
Oil, natural-gas, and NGLs sales	$	2,454		$	1,394		$	1,955		$	1,680		$	4,409		$	3,074
Gathering, processing, and marketing sales	444			240			464			305			908			545
Gains (losses) on divestitures and other, net	869			40			297			(70		)	1,166			(30		)
Revenues and other	$	3,767		$	1,674		$	2,716		$	1,915		$	6,483		$	3,589
Costs and expenses	3,877			2,538			2,841			2,247			6,718			4,785
Other (income) expense	68			517			247			593			315			1,110
Income tax expense (benefit)	97			(383		)	(38		)	(314		)	59			(697		)
Net income (loss) attributable to common stockholders	$	(318	)	$	(1,034	)	$	(415	)	$	(692	)	$	(733	)	$	(1,726	)
Net income (loss) per common share attributable to common stockholders—diluted	$	(0.58	)	$	(2.03	)	$	(0.76	)	$	(1.36	)	$	(1.34	)	$	(3.39	)
Average number of common shares outstanding—diluted	551			509			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 ~~March 31,~~June 30, 2017,” refer to the comparison of the three months ended ~~March 31,~~June 30, 2017, to the three months ended ~~March 31,~~June 30, 2016, and any increases or decreases “for the six months ended June 30, 2017,” refer to the comparison of the six months ended June 30, 2017, to the six months ended June 30, 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 March 31,												Three Months Ended June 30,
millions except percentages	Oil			Natural Gas			NGLs			Total			Oil			Natural Gas			NGLs			Total
2016 sales revenues	$	850		$	366		$	178		$	1,394		$	1,125		$	320		$	235		$	1,680
Changes associated with prices	684			210			126			1,020			163			138			47			348
Changes associated with sales volumes	129			(74		)	(15		)	40			134			(139		)	(68		)	(73		)
2017 sales revenues	$	1,663		$	502		$	289		$	2,454		$	1,422		$	319		$	214		$	1,955
Increase (decrease) vs. 2016	96		%	37		%	62		%	76		%	26		%	—		%	(9		)%	16		%

													Six Months Ended June 30,
millions except percentages													Oil			Natural Gas			NGLs			Total
2016 sales revenues													$	1,975		$	686		$	413		$	3,074
Changes associated with prices													842			351			168			1,361
Changes associated with sales volumes													268			(216		)	(78		)	(26		)
2017 sales revenues													$	3,085		$	821		$	503		$	4,409
Increase (decrease) vs. 2016													56		%	20		%	22		%	43		%

The above table illustrates the effects of the increase in commodity prices and changes associated with sales volumes, which include increases related to newly acquired assets in the ~~GOM Acquisition~~Gulf of Mexico (primarily oil) and decreases associated with U.S. onshore asset divestitures (primarily natural gas).

The following provides Anadarko’s sales volumes for the three and six months ended ~~March 31:~~June 30:


					Three Months Ended June 30,				Six Months Ended June 30,
	2017	Inc (Dec) vs. 2016		2016	2017	Inc (Dec) vs. 2016		2016	2017	Inc (Dec) vs. 2016		2016
Barrels of Oil Equivalent
(MMBOE except percentages)
United States	62	(7	)%	67	49	(25	)%	65	111	(16	)%	132
International	10	16		8	8	26		7	18	21		15
Total barrels of oil equivalent	72	(5	)	75	57	(20	)	72	129	(12	)	147

Barrels of Oil Equivalent per Day
(MBOE/d except percentages)
United States	691	(6	)%	738	538	(25	)%	718	614	(16	)%	728
International	104	17		89	93	26		74	99	21		81
Total barrels of oil equivalent per day	795	(4	)	827	631	(20	)	792	713	(12	)	809

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

Oil Sales Revenues, Average Prices, and Volumes


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016
Oil sales revenues (millions)	$	1,663	96	%	$	850	$	1,422	26	%	$	1,125	$	3,085	56	%	$	1,975

United States
Sales volumes—MMBbls	24		15	%	21		22		7	%	20		46		11	%	41
MBbls/d	269		16		232		243		7		227		256		12		229
Price per barrel	$	49.23	76		$	28.04	$	46.68	16		$	40.25	$	48.01	41		$	34.07

International
Sales volumes—MMBbls	9		16	%	8		8		27	%	6		17		21	%	14
MBbls/d	98		18		83		88		27		69		93		22		76
Price per barrel	$	53.36	56		$	34.11	$	48.61	4		$	46.75	$	51.10	28		$	39.84

Total
Sales volumes—MMBbls	33		15	%	29		30		12	%	26		63		14	%	55
MBbls/d	367		16		315		331		12		296		349		14		305
Price per barrel	$	50.34	70		$	29.65	$	47.19	13		$	41.77	$	48.84	38		$	35.51

The following summarizes primary drivers for the change in oil sales revenues:


millions	Change in Revenues		Due to Change in Prices		Due to Change in Volumes		Change in Revenues		Due to Change in Prices		Due to Change in Volumes
Three months ended March 31, 2017 vs. 2016	$	813	$	684	$	129
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 six months ended ~~March 31,~~June 30, 2017, primarily due to the expectation of decreasing global oversupply as a result of OPEC’s agreement to reduce production ~~for~~through the first ~~six months~~quarter of ~~2017, which reduced the global oversupply.~~2018.

Oil Sales Volumes

2017 vs. 2016 The Company’s oil sales volumes increased by 5235 MBbls/d for the three months ended ~~March 31,~~June 30, 2017, and 44 MBbls/d for the six months ended June 30, 2017, primarily due to the following:

U.S. Onshore

Sales volumes for the Delaware basin increased by 1011 MBbls/d for the three and six months ended ~~March 31,~~June 30, 2017, primarily due to continued drilling ~~activity.~~and completion activities.

Sales volumes for the DJ basin decreased by 1617 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 second quarter of 2017.

Sales volumes decreased by 32 MBbls/d for the three months ended ~~March 31,~~June 30, 2017, ~~primarily due to reduced capital investment during the low commodity price cycle in 2016.~~

~~Sales volumes for Eagleford decreased by 15~~and 26 MBbls/d for the ~~three~~six months ended ~~March 31,~~June 30, 2017, primarily due to the sale of the U.S. onshore Eagleford assets in ~~March~~the first half of 2017.

Gulf of Mexico

Sales volumes increased by 6757 MBbls/d for the three months ended ~~March 31,~~June 30, 2017, and 62 MBbls/d for the six months ended June 30, 2017, primarily due to continued tieback activity at several facilities and the GOM Acquisition in December 2016.

International

Sales volumes for Ghana increased by 1019 MBbls/d for the three months ended ~~March 31,~~June 30, 2017, and 15 MBbls/d for the six months ended June 30, 2017, primarily due to liftings from the TEN development project, which came online late in the third quarter of 2016.

Natural-Gas Sales Volumes, Average Prices, and Revenues


	Three Months Ended March 31,						Three Months Ended June 30,							Six Months Ended June 30,
	2017		Inc (Dec) vs. 2016		2016		2017			Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016
Natural-gas sales revenues (millions)	$	502	37	%	$	366	$	319		—	%	$	320	$	821	20	%	$	686

United States									��
Sales volumes—Bcf	167		(20	)%	210		113			(43	)%	199		280		(31	)%	409
MMcf/d	1,859		(19	)	2,303		1,238			(43	)	2,188		1,547		(31	)	2,245
Price per Mcf	$	3.00	71		$	1.75	$	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			Change in Revenues			Due to Change in Prices		Due to Change in Volumes
Three months ended March 31, 2017 vs. 2016	$	136	$	210	$	(74	)
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 ~~March 31,~~June 30, 2017, primarily due to the industry’syear-over-year production ~~declines. This lower domestic production resulted~~declines resulting in ~~lower~~reduced gas in storage, ~~despite lower residential~~while LNG and ~~commercial demand due~~natural-gas exports to ~~warmer than normal temperatures in the first quarter of 2017.~~Mexico continued to grow.

Natural-Gas Sales Volumes

2017 vs. 2016 The Company’s natural-gas sales volumes decreased by ~~444~~950 MMcf/d for the three months ended ~~March 31,~~June 30, 2017, ~~primarily due to the following:~~

~~U.S. Onshore~~

~~Sales volumes for Eagleford decreased by 61~~and 698 MMcf/d for the ~~three~~six months ended ~~March 31,~~June 30, 2017, primarily due to the sale of the U.S onshore Elm Grove and East Texas assets in ~~March 2017.~~

~~Sales volumes for~~the second half of 2016 and the U.S. onshore Marcellus ~~decreased by 43 MMcf/d for the three months ended March 31, 2017, primarily due to natural production declines. The assets were sold on March 31, 2017.~~

~~Sales volumes decreased by 402 MMcf/d for the three months ended March 31, 2017, primarily due to the sale of certain Wyoming~~ and ~~East Texas/Louisiana~~Eagleford assets in ~~2016.~~the first half of 2017.

~~Gulf of Mexico~~

~~Sales volumes increased by 44 MMcf/d for the three months ended March 31, 2017, primarily due to the GOM Acquisition in December 2016.~~

Natural-Gas Liquids Sales Volumes, Average Prices, and Revenues


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016
Natural-gas liquids sales revenues (millions)	$	289	62	%	$	178	$	214	(9	)%	$	235	$	503	22	%	$	413

United States
Sales volumes—MMBbls	10		(10	)%	11		8		(30	)%	12		18		(20	)%	23
MBbls/d	112		(9	)	122		89		(30	)	126		100		(20	)	125
Price per barrel	$	26.57	77		$	14.98	$	24.82	28		$	19.42	$	25.79	50		$	17.24

International
Sales volumes—MMBbls	1		14	%	—		—		3	%	1		1		9	%	1
MBbls/d	6		15		6		5		3		5		6		9		5
Price per barrel	$	37.57	65		$	22.78	$	30.48	26		$	24.13	$	34.36	47		$	23.43

Total
Sales volumes—MMBbls	11		(9	)%	11		8		(29	)%	13		19		(19	)%	24
MBbls/d	118		(8	)	128		94		(29	)	131		106		(18	)	130
Price per barrel	$	27.17	77		$	15.32	$	25.14	28		$	19.60	$	26.27	50		$	17.49

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			Change in Revenues			Due to Change in Prices		Due to Change in Volumes
Three months ended March 31, 2017 vs. 2016	$	111	$	126	$	(15	)
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 ~~March 31,~~June 30, 2017, primarily due to increasedpropane ~~and butane~~ prices stemming from higher export demand.

NGLs Sales Volumes

2017 vs. 2016 The Company’s NGLs sales volumes decreased by 1037 MBbls/d for the three months ended ~~March 31,~~June 30, 2017, and 24 MBbls/d for the six months ended June 30, 2017, primarily due to the following:

U.S. Onshore

Sales volumes for the DJ basin increased by 96 MBbls/d for the three months ended ~~March 31,~~June 30, 2017, and 7 MBbls/d for the six months ended June 30, 2017, primarily due to improved well ~~performance.~~performance partially offset by downtime due to the Company’s response efforts in Colorado in the second quarter of 2017.

Sales volumes decreased by 2243 MBbls/d for the three months ended ~~March 31,~~June 30, 2017, and 38 MBbls/d for the six months ended June 30, 2017, primarily due to the sale of ~~certain Wyoming and~~the U.S. onshore East ~~Texas/Louisiana~~Texas assets in ~~2016.~~the second half of 2016 and the U.S. onshore Eagleford assets in the first half of 2017.

~~Gulf of Mexico~~

~~Sales volumes increased by 5 MBbls/d for the three months ended March 31, 2017, primarily due to the GOM Acquisition in December 2016.~~

Gathering, Processing, and Marketing


	Three Months Ended March 31,						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		2017		Inc (Dec) vs. 2016		2016
Gathering, processing, and marketing sales	$	444	85	%	$	240	$	464	52	%	$	305	$	908	67	%	$	545
Gathering, processing, and marketing expense	351		63		215		359		42		252		710		52		467
Total gathering, processing, and marketing, net	$	93	NM		$	25	$	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 increased by ~~$68~~$52 million for the three months ended ~~March 31,~~June 30, 2017, and by $120 million for the six months ended June 30, 2017, primarily related to an increase in throughput volumes at the DBM complex in the Delaware basin due to downtime throughout the first quarter of 2016, ~~and higher natural-gas and NGLs marketing margins during~~ the ~~first~~gradual ramp up throughout the second quarter of 2016, and increased processing capacity into 2017.

Gains (Losses) on Divestitures and Other, net


	Three Months Ended March 31,						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			2017		Inc (Dec) vs. 2016	2016
Gains (losses) on divestitures, net	$	804	NM		$	2	$	205	NM	$	(104	)	$	1,009	NM	$	(102	)
Other	65		71	%	38		92		171	34			157		118	72
Total gains (losses) on divestitures and other, net	$	869	NM		$	40	$	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.

~~For~~During the three and six months ended ~~March 31,~~June 30, 2017 and 2016, Anadarko divested certain non-core U.S. onshore ~~assets and recognized net gains of $804 million.~~

assets. See Note 3—Acquisitions, Divestitures, and Assets Held for Sale in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q for additional information.

Costs and Expenses

The following provides Anadarko’s total costs and expenses for three and six months ended ~~March 31:~~June 30:


					Three Months Ended June 30,				Six Months Ended June 30,
millions	2017		2016		2017		2016		2017		2016
Oil and gas operating	$	258	$	208	$	233	$	202	$	491	$	410
Oil and gas transportation	249		242		229		246		478		488
Exploration	1,085		126		535		76		1,620		202
Gathering, processing, and marketing	351		215		359		252		710		467
General and administrative	269		449		291		305		560		754
Depreciation, depletion, and amortization	1,115		1,149		1,037		984		2,152		2,133
Production, property, and other taxes	155		117		135		157		290		274
Impairments	373		16		10		18		383		34
Other operating expense	22		16		12		7		34		23
Total	$	3,877	$	2,538	$	2,841	$	2,247	$	6,718	$	4,785

Oil and Gas Operating ~~Expenses~~Expense


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016
Oil and gas operating (millions)	$	258	24	%	$	208	$	233	15	%	$	202	$	491	20	%	$	410
Oil and gas operating—per BOE	3.60		30		2.77		4.07		45		2.80		3.81		37		2.78

Oil and gas operating expense increased by ~~$50~~$81 million for the ~~three~~six months ended ~~March 31,~~June 30, 2017, primarily due to the following:

higher overall operating costs of ~~$54~~$89 million and non-operating costs of $20 million primarily related to the GOM Acquisition

higher ~~non-operated~~non-operating costs of ~~$32~~$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 ~~which~~that came online late in the third quarter of 2016

lower expenses of ~~$21~~$45 million as a result of U.S. onshore asset divestitures

The related costs per BOE increased by ~~$0.83~~$1.03 for the ~~three~~six months ended ~~March 31,~~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 March 31,				Three Months Ended June 30,					Six Months Ended June 30,
millions	2017		2016		2017		2016			2017		2016
Exploration Expense
Dry hole expense	$	476	$	11	$	367	$	(5	)	$	843	$	6
Impairments of unproved properties	537		24		87		15			623		39
Geological and geophysical expense	37		37
Exploration overhead and other	35		54
Geological and geophysical, exploration overhead, and other expense					81		66			154		157
Total exploration expense	$	1,085	$	126	535		76			1,620		202

~~For~~Total exploration expense increased by $459 million for the three months ended ~~March 31,~~June 30, 2017, ~~total exploration expense increased by $959 million~~and $1.4 billion for the six months ended June 30, 2017, primarily related to the following:

Dry Hole Expense

Dry hole expense increased by ~~$465~~$372 million for the three months ended June 30, 2017, and $837 million for the six months ended June 30, 2017. The Company expensed the following exploratory well costs:

$435 million related to the Shenandoah project in 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 first half of 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 $584 million for the six months ended June 30, 2017, primarily due to the following:


•	The Company ~~expensed suspended exploratory well costs of $435 million during the three months ended March 31, 2017, related to the Shenandoah project in the Gulf of Mexico. See~~ ~~Note 5—Suspended Exploratory Well Costs~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Part I, Item 1 of this Form 10-Q.~~

~~The Company expensed $41 million during the three months ended March 31, 2017, due to unsuccessful drilling activities primarily associated with the Gulf of Mexico and an international property.~~

~~Impairments of Unproved Properties~~

•

~~The Company~~ recognized ~~$532~~$555 million of impairments of unproved Gulf of Mexico properties during the ~~three~~six months ended ~~March 31,~~June 30, 2017, of which ~~$467~~$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—~~Suspended~~ Exploratory Well Costs in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

General and Administrative ~~Expenses~~Expense


	Three Months Ended March 31,						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		2017		Inc (Dec) vs. 2016		2016
General and administrative	$	269	(40	)%	$	449	$	291	(5	)%	$	305	$	560	(26	)%	$	754

~~For the three months ended March 31, 2017,~~ G&A decreased by ~~$180~~$194 million for the six months ended June 30, 2017, primarily due to ~~charges of $203~~$234 million ~~in the first quarter of 2016~~ associated with the 2016 workforce reduction program. See Note 11—Restructuring Charges in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Impairments

~~The Company recognized~~During the ~~following impairments:~~

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

~~Impairments during the three~~six months ended ~~March 31,~~June 30, 2017, ~~were primarily related to~~impairments included $211 million associated with Gulf of Mexico oil and gas properties ~~in the Gulf of Mexico~~ due to lower forecasted commodity prices and $169 million primarily related to a U.S. onshore midstream property due to a reduced throughput fee as a result of a producer’s bankruptcy.

For further discussion related to impairments, including the potential for future impairments, see Note 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 ~~March 31:~~June 30:


						Three Months Ended June 30,						Six Months Ended June 30,
millions	2017			2016		2017			2016			2017			2016
Interest expense	$	223		$	220	$	227		$	217		$	450		$	437
Loss on early extinguishment of debt						2			124			2			124
(Gains) losses on derivatives, net ⁽¹⁾	(147		)	297		32			307			(115		)	604
Other (income) expense, net	(8		)	—		(14		)	(55		)	(22		)	(55		)
Total	$	68		$	517	$	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)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
millions except percentages	2017			2016			2017			2016			2017			2016
Income tax expense (benefit)	$	97		$	(383	)	$	(38	)	$	(314	)	$	59		$	(697	)
Income (loss) before income taxes	(178		)	(1,381		)	(372		)	(925		)	(550		)	(2,306		)
Effective tax rate	(54		)%	28		%	10		%	34		%	(11		)%	30		%

The Company reported a loss before income taxes for the three and six months ended ~~March 31,~~June 30, 2017 and 2016. ~~As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect.~~ The Company’s effective tax rate is impacted each year by the relative pre-tax income (loss) earned by the Company’s operations in the U.S., Algeria, and the rest of 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. The Company’s effective tax rate decreased from 28% for three months ended March 31, 2016, to (54)% for the three months ended March 31, 2017, primarily due to the impact from the items discussed above.

For additional information on income taxes, see Note 9—Income Taxes in the Notes to Consolidated Financial

Statements under Item 1 of this Form 10-Q.

LIQUIDITY AND CAPITAL RESOURCES


	Three Months Ended March 31,						Six Months Ended June 30,
millions	2017			2016			2017			2016
Net cash provided by (used in) operating activities	$	1,123		$	(137	)	$	1,980		$	1,092
Net cash provided by (used in) investing activities	1,722			(973		)	1,216			(965		)
Net cash provided by (used in) financing activities	(198		)	3,119			(372		)	329

Overview The Company has a variety of funding sources available, including cash, an asset portfolio that provides ongoing cash-flow-generating capacity, opportunities for liquidity enhancement through divestitures and joint-venture arrangements that reduce future capital expenditures, the Company’s credit facilities, and access to both debt and equity capital markets. In addition, an effective registration statement is available to Anadarko covering the sale of WGP common units owned by the Company.

During ~~the first quarter of~~ 2017, Anadarko ~~closed on~~received net proceeds of $3.5 billion from divestitures, primarily related to the ~~divestitures~~sale of ~~its~~the Company’s U.S. onshore Eagleford, Marcellus, Eaglebine, and ~~Marcellus assets for net proceeds of $2.8 billion.~~Utah CBM assets. As of ~~March 31,~~June 30, 2017, Anadarko had ~~$5.8~~$6.0 billion of cash 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 fund the Company’s projected 2017 and long-term operational and capital programs. ~~Current available cash provides the flexibility to accelerate activity in the Delaware and DJ basins or acquire bolt-on positions in these core areas.~~ The Company continuously monitors its liquidity position and evaluates available funding alternatives in light of current and expected conditions.

Operating Activities

One of the primary sources of variability in the Company’s cash flows from operating activities is the fluctuation in commodity prices, the impact of which Anadarko partially mitigates by 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.

Cash provided by operating activities was ~~$1.1~~$2.0 billion for the ~~three~~six months ended ~~March 31,~~June 30, 2017, ~~$1.2~~$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 ~~and increased oil sales volumes~~ as well as the $159.5 million payment of the Clean Water Act penalty in 2016 and ~~$79~~$182 million related to severance costs and retirement benefits paid in 2016 in connection with the workforce reduction ~~program~~program. These increases were partially offset by an $881 million tax refund received in ~~2016.~~2016 related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback.

Investing Activities

Capital Expenditures The following presents the Company’s capital expenditures for the ~~three~~six months ended ~~March 31:~~June 30:


millions	2017		2016			2017		2016
Cash Flows from Investing Activities
Additions to properties and equipment ⁽¹⁾	$	1,194	$	1,022		$	2,296	$	1,879
Adjustments for capital expenditures
Changes in capital accruals	58		(130		)	147		(249		)
Other	3		4			22		(6		)
Total capital expenditures ⁽²⁾	$	1,255	$	896		$	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 ~~$286~~$437 million for the ~~three~~six months ended ~~March 31,~~June 30, 2017, and ~~$140~~$260 million for the ~~three~~six months ended ~~March 31,~~June 30, 2016. Capital expenditures exclude the FPSO capital lease asset.

The Company’s capital expenditures increased by ~~$359~~$841 million for the ~~three~~six months ended ~~March 31,~~June 30, 2017, primarily due to ~~$258~~increases of $395 million ~~related to increased~~driven by U.S. onshore acreage acquisitions and exploration ~~costs~~drilling in the Gulf of Mexico, ~~coupled with increased spending of $154~~$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 $175 million primarily related to the TEN development project in Ghana, which achieved first oil in the third quarter of 2016.

Property Exchange On March 17, 2017, WES acquired a third party’s 50% nonoperated interest in the DBJV system in exchange for WES’s 33.75% interest in nonoperated Marcellus midstream assets and $155 million in cash. WES funded the cash consideration with cash on ~~hand.~~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 Sale in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Carried-Interest Arrangements In the third quarter of 2014, the Company entered into a carried-interest arrangement that 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~~As part of the sale of the Eaglebine assets, the carry was canceled in the ~~development through 2020. At March 31, 2017, $151 million~~second quarter of ~~the $442 million carry obligation had been funded.~~2017.

Divestitures During the ~~three~~six months ended ~~March 31,~~June 30, 2017, Anadarko received net proceeds of ~~$2.9~~$3.5 billion from divestitures, primarily related to the sale of the Company’s U.S. onshore Eagleford, Marcellus, Eaglebine, and ~~Marcellus oil and gas~~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	March 31, 2017			December 31, 2016			June 30, 2017			December 31, 2016
Anadarko	$	12,206		$	12,204		$	12,199		$	12,204
WES	3,092			3,091			3,253			3,091
WGP	28			28			28			28
Total debt	$	15,326		$	15,323		$	15,480		$	15,323
Total equity	15,079			15,497			14,656			15,497
Debt to total capitalization ratio	50.4		%	49.7		%	51.4		%	49.7		%

Debt Activity

Anadarko RCFs Anadarko has a $3.0 billion ~~Five-Year Facility~~RCF that matures in January 2021 and a $2.0 billion 364-Day ~~Facility. In January 2017, the Company extended the maturity date of the 364-Day~~ Facility ~~until~~that matures in January 2018. At ~~March 31,~~June 30, 2017, the Company had no outstanding borrowings under the ~~Five-Year Facility~~APC RCF or the 364-Day Facility.

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, 2017, WES borrowed $160 million under its RCF, which was primarily used for general partnership purposes. At ~~March 31,~~June 30, 2017, WES had no$160 million of outstanding borrowings under its RCF at an interest rate of 2.53%, had outstanding letters of credit of $5 million, and had available borrowing capacity of ~~$1.195~~$1.035 billion.

WGP has a $250 million RCF that matures in March 2019 and is expandable to $500 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions. At ~~March 31,~~June 30, 2017, WGP had outstanding borrowings under its RCF of $28 million at an interest rate of ~~2.99%~~3.23% and had available borrowing capacity of $222 million.

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

Debt Maturities At ~~March 31,~~June 30, 2017, Anadarko’s remaining scheduled debt maturities during 2017 consisted of ~~$34~~$17 million of senior amortizing notes associated with the TEUs. At June 30, 2017, Anadarko’s scheduled debt maturities during 2018 consisted of $17 million of senior amortizing notes associated with the TEUs and $114 million of 7.05% Debentures due May 2018, while WES has $350 million of 2.60% Senior Notes due 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 $883 million at the next put date in October 2017.

Anadarko’s $114 million 7.05% Debentures due May 2018 and Zero Coupons were classified as long-term on the Company’s Consolidated Balance Sheet at June 30, 2017, as the Company has the ability and intent to refinance these obligations using long-term debt. For additional information on the Company’s debt instruments, see Note 8—Debt in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Equity Transactions WES can issue common units to the public under its $500 million continuous offering program, which allows for an aggregate of $500 million of WES common units. ~~The remaining amount available to be issued under this program was $442 million at March 31, 2017.~~

During the first quarter of 2016, WES issued 14 million Series A Preferred units to private investors for net proceeds of $440 million. In April 2016, WES issued an additional eight million Series A Preferred units to private investors, pursuant to the full exercise of an option granted in connection with the initial issuance, and raised net proceeds of $248 million.

~~For additional information on WES Series A Preferred units, see~~ ~~Note 14—Noncontrolling Interests~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Part I, Item 1 of this Form 10-Q.~~

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

Common Stock Dividends Anadarko paid dividends to its common stockholders of ~~$28~~$56 million during the ~~three~~six months ended ~~March 31,~~June 30, 2017, and ~~$25~~$51 million during the ~~three~~six months ended ~~March 31,~~June 30, 2016. In response to the commodity-price environment, the Company decreased the quarterly dividend from $0.27 per share to $0.05 per share in February 2016. Anadarko has paid a dividend to its common stockholders quarterly since becoming a public company in 1986.

The amount of future dividends paid to Anadarko common stockholders is determined by the Board on a quarterly basis and is based on the Company’s earnings, financial ~~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.

Distributions to Noncontrolling Interest Owners Distributions to noncontrolling interest owners primarily relate to the following for the ~~three~~six months ended ~~March 31:~~June 30:


millions	2017		2016		2017		2016
WES distributions to unitholders (excluding Anadarko and WGP) ⁽¹⁾	$	68	$	63	$	146	$	127
WES distributions to Series A Preferred unitholders ⁽²⁾	15		—		22		2
WGP distributions to unitholders (excluding Anadarko) ⁽³⁾	19		11		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 ~~$0.875~~$0.890 per common unit for the ~~first~~second quarter of 2017 (to be paid in ~~May~~August 2017).

⁽²⁾

WES ~~has~~ made quarterly distributions of $0.68 per unit, prorated based on issuance date, to its Series A Preferred unitholders since the unit issuances in March and April ~~2016 (to be paid~~2016. As of June 30, 2017, all Series A Preferred units have converted into WES common units, see Note 14—Noncontrolling Interests in ~~May 2017).~~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 ~~$0.49125~~$0.52750 per unit for the ~~first~~second quarter of 2017 (to be paid in ~~May~~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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

Derivative Instruments Held for Non-Trading Purposes The Company had derivative instruments in place to reduce the price risk associated with future production of 2517 MMBbls of oil and ~~284~~249 Bcf of natural gas at ~~March 31,~~June 30, 2017, with a net derivative asset position of $4$68 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by ~~$111~~$78 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by ~~$110~~$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 Purposes At ~~March 31,~~June 30, 2017, the Company had a net derivative asset position of $9$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 RISK Borrowings, 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 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 ~~March 31,~~June 30, 2017, the Company had a net derivative liability position of ~~$1.3~~$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 ~~$91~~$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 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (Exchange Act). The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and to ensure that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of ~~March 31,~~June 30, 2017.

Changes in Internal Control over Financial Reporting

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

WGR Operating, LP, a wholly owned subsidiary of the Company, is currently in negotiations with the 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 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 legal matters that have arisen since the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, 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, 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 ~~first~~second quarter of 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
January 1 - 31, 2017 21,117 $ 71.08
—
$ —
February 1 - 28, 2017 2,968 $ 69.47
—
$ —
March 1 - 31, 2017 307,298 $ 62.52
—
$ —
Total 331,383 $ 63.13
—
$ —



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 ~~first~~second quarter of 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.

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)~~	First Amendment to 364-Day Revolving Credit Agreement, dated January 13, 2017, among Anadarko Petroleum Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and the additional lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on January 20, 2017
*	31	(i)	Rule 13a-14(a)/15d-14(a) Certification—Chief Executive Officer
*	31	(ii)	Rule 13a-14(a)/15d-14(a) Certification—Chief Financial Officer
**	32		Section 1350 Certifications
*	101	.INS	XBRL Instance Document
*	101	.SCH	XBRL Schema Document
*	101	.CAL	XBRL Calculation Linkbase Document
*	101	.DEF	XBRL Definition Linkbase Document
*	101	.LAB	XBRL Label Linkbase Document
*	101	.PRE	XBRL Presentation Linkbase Document

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)

~~May 2,~~July 24, 2017	By:	/s/ ROBERT G. GWIN
		Robert G. Gwin Executive Vice President, Finance and Chief Financial Officer

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