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 September 30, ~~2016~~2017

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the transition period from to

Commission File No. 1-8968

ANADARKO PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)



Delaware		76-0146568
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)



1201 Lake Robbins Drive, The Woodlands, Texas		77380-1046
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code (832) 636-1000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒þ No ☐¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒þ No ☐¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, ~~or a~~ smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” ~~and~~ “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☒þ Accelerated filer ☐¨ Non-accelerated filer ☐¨ Smaller reporting company ☐¨Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐¨ No ☒þ

The number of shares outstanding of the Company’s common stock at October 20, ~~2016,~~2017, is shown below:



Title of Class		Number of Shares Outstanding
Common Stock, par value $0.10 per share		~~558,900,897~~547,157,557

TABLE OF CONTENTS



PART I		Page
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three and Nine Months Ended September 30, ~~2016~~2017 and ~~2015~~2016	23
	Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, ~~2016~~2017 and ~~2015~~2016	34
	Consolidated Balance Sheets at September 30, ~~2016,~~2017, and December 31, ~~2015~~2016	45
	Consolidated Statement of Equity for the Nine Months Ended September 30, ~~2016~~2017	56
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, ~~2016~~2017 and ~~2015~~2016	67
	Notes to Consolidated Financial Statements	78
	Note 1 - Summary of Significant Accounting Policies	78
	Note 2 - Inventories	810
	Note 3 - Acquisitions, Divestitures, and Assets Held for Sale	911
	Note 4 - Impairments	1012
	Note 5 - ~~Suspended~~ Exploratory Well Costs	1113
	Note 6 - ~~Derivative Instruments~~Current Liabilities	1214
	Note 7 - ~~Tangible Equity Units~~Derivative Instruments	1814
	Note 8 - Debt ~~and Interest Expense~~	1920
	Note 9 - Income Taxes	2322
	Note 10 - ~~Conveyance of Future Hard Minerals Royalty Revenues~~Contingencies	23
	Note 11 - Restructuring Charges	23
	Note 12 - Pension Plans and Other Postretirement Benefits	24
	Note 1113 - ~~Contingencies~~Stockholders’ Equity	25
	Note 1214 - ~~Restructuring Charges~~Noncontrolling Interests	26
	Note 1315 - ~~Pension Plans and Other Postretirement Benefits~~Variable Interest Entities	27
	Note 1416 - ~~Stockholders’ Equity~~Supplemental Cash Flow Information	28
	Note ~~15 - Accumulated Other Comprehensive Income (Loss)~~	29
	~~Note 16 - Noncontrolling Interests~~	29
	~~Note~~ 17 ~~- Variable Interest Entities~~	30
	~~Note 18 - Supplemental Cash Flow Information~~	31
	~~Note 19~~ - Segment Information	3128
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3532
	Cautionary Statement About Forward-Looking Statements	3532
	~~Outlook~~	36
	Management Overview	3834
	Financial Results	4035
	Liquidity and Capital Resources	5246
	Recent Accounting Developments	5649
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5750
Item 4.	Controls and Procedures	5851
PART II
Item 1.	Legal Proceedings	5952
Item 1A.	Risk Factors	5952
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	6053
Item 6.	Exhibits	6154

COMMONLY USED TERMS AND DEFINITIONS

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

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

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

ASR Agreement - Anadarko’s accelerated share-repurchase agreement with an investment bank to repurchase the Company’s common stock

ASU - Accounting Standards Update

Bcf - Billion cubic feet

BOE - Barrels of ~~Contents~~oil equivalent

CBM - Coalbed methane

DBJV - Delaware Basin JV Gathering LLC

DBJV system - A gathering system and related facilities located in the Delaware basin in Loving, Ward, Winkler, and Reeves Counties in West Texas

DBM complex - The processing plants, gas gathering system, and related facilities and equipment in West Texas that serve production from Reeves, Loving, and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico

DD&A - Depreciation, depletion, and amortization

EPA - U.S. Environmental Protection Agency

FPSO - Floating production, storage, and offloading unit

G&A - General and administrative expenses

GAAP - U.S. Generally Accepted Accounting Principles

GOM Acquisition - The acquisition of oil and natural-gas assets in the Gulf of Mexico that 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

NTSB - National Transportation Safety Board

NYMEX - New York Mercantile Exchange

NYSE - New York Stock Exchange

Oil - Includes crude oil and condensate

OPEC - Organization of the Petroleum Exporting Countries

RCF - Revolving credit facility

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 publicly traded limited partnership, which is a consolidated subsidiary of Anadarko

WES RCF - WES’s $1.2 billion senior unsecured RCF maturing in February 2020

WGP - Western Gas Equity Partners, LP, a publicly traded limited partnership, which is a 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 September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
millions except per-share amounts	2016			2015			2016			2015			2017			2016			2017			2016
Revenues and Other
Oil and condensate sales	$	1,239		$	1,229		$	3,214		$	4,264
Oil sales													$	1,567		$	1,239		$	4,652		$	3,214
Natural-gas sales	435			484			1,121			1,612			269			435			1,090			1,121
Natural-gas liquids sales	227			183			640			644			265			227			768			640
Gathering, processing, and marketing sales	350			334			895			932			509			350			1,417			895
Gains (losses) on divestitures and other, net	(358		)	(542		)	(388		)	(807		)	(114		)	(358		)	1,052			(388		)
Total	1,893			1,688			5,482			6,645			2,496			1,893			8,979			5,482
Costs and Expenses
Oil and gas operating	198			262			608			784			257			198			748			608
Oil and gas transportation	256			265			744			853			220			256			698			744
Exploration	304			1,074			506			2,260			751			304			2,371			506
Gathering, processing, and marketing	291			289			758			798			398			291			1,108			758
General and administrative	362			303			1,116			888			280			362			840			1,116
Depreciation, depletion, and amortization	1,069			1,111			3,202			3,581			1,083			1,069			3,235			3,202
Other taxes	148			127			422			460
Production, property, and other taxes													159			148			449			422
Impairments	27			758			61			3,571			—			27			383			61
Other operating expense	31			48			54			117			123			31			157			54
Total	2,686			4,237			7,471			13,312			3,271			2,686			9,989			7,471
Operating Income (Loss)	(793		)	(2,549		)	(1,989		)	(6,667		)	(775		)	(793		)	(1,010		)	(1,989		)
Other (Income) Expense
Interest expense	220			199			657			616			230			220			680			657
Loss on early extinguishment of debt	—			—			124			—			—			—			2			124
(Gains) losses on derivatives, net	25			282			629			123			82			25			(33		)	629
Other (income) expense, net	(31		)	47			(86		)	109			(21		)	(31		)	(43		)	(86		)
Tronox-related contingent loss	—			—			—			5
Total	214			528			1,324			853			291			214			606			1,324
Income (Loss) Before Income Taxes	(1,007		)	(3,077		)	(3,313		)	(7,520		)	(1,066		)	(1,007		)	(1,616		)	(3,313		)
Income tax expense (benefit)	(260		)	(917		)	(957		)	(2,232		)	(425		)	(260		)	(366		)	(957		)
Net Income (Loss)	(747		)	(2,160		)	(2,356		)	(5,288		)	(641		)	(747		)	(1,250		)	(2,356		)
Net income (loss) attributable to noncontrolling interests	83			75			200			154			58			83			182			200
Net Income (Loss) Attributable to Common Stockholders	$	(830	)	$	(2,235	)	$	(2,556	)	$	(5,442	)	$	(699	)	$	(830	)	$	(1,432	)	$	(2,556	)

Per Common Share
Net income (loss) attributable to common stockholders—basic	$	(1.61	)	$	(4.41	)	$	(5.00	)	$	(10.73	)	$	(1.27	)	$	(1.61	)	$	(2.60	)	$	(5.00	)
Net income (loss) attributable to common stockholders—diluted	$	(1.61	)	$	(4.41	)	$	(5.00	)	$	(10.73	)	$	(1.27	)	$	(1.61	)	$	(2.61	)	$	(5.00	)
Average Number of Common Shares Outstanding—Basic	517			508			512			508			553			517			552			512
Average Number of Common Shares Outstanding—Diluted	517			508			512			508			553			517			552			512
Dividends (per common share)	$	0.05		$	0.27		$	0.15		$	0.81		$	0.05		$	0.05		$	0.15		$	0.15

See accompanying Notes to Consolidated Financial Statements.

Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
millions	2016			2015			2016			2015			2017			2016			2017			2016
Net Income (Loss)	$	(747	)	$	(2,160	)	$	(2,356	)	$	(5,288	)	$	(641	)	$	(747	)	$	(1,250	)	$	(2,356	)
Other Comprehensive Income (Loss)
Adjustments for derivative instruments
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	2			2			7			7			1			2			3			7
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	(1		)	(1		)	(3		)	(3		)	—			(1		)	(1		)	(3		)
Total adjustments for derivative instruments, net of taxes	1			1			4			4			1			1			2			4
Adjustments for pension and other postretirement plans
Net gain (loss) incurred during period	(157		)	—			(347		)	—			(14		)	(157		)	1			(347		)
Income taxes on net gain (loss) incurred during period	58			—			128			—			5			58			—			128
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	114			13			156			39			29			114			100			156
Income taxes on amortization of net actuarial (gain) loss to general and administrative expense	(43		)	(5		)	(59		)	(14		)	(11		)	(43		)	(37		)	(59		)
Amortization of net prior service (credit) cost to general and administrative expense	(6		)	1			(27		)	2			(7		)	(6		)	(19		)	(27		)
Income taxes on amortization of net prior service (credit) cost to general and administrative expense	2			(1		)	10			(1		)	3			2			7			10
Total adjustments for pension and other postretirement plans, net of taxes	(32		)	8			(139		)	26			5			(32		)	52			(139		)
Total	(31		)	9			(135		)	30			6			(31		)	54			(135		)
Comprehensive Income (Loss)	(778		)	(2,151		)	(2,491		)	(5,258		)	(635		)	(778		)	(1,196		)	(2,491		)
Comprehensive income (loss) attributable to noncontrolling interests	83			75			200			154			58			83			182			200
Comprehensive Income (Loss) Attributable to Common Stockholders	$	(861	)	$	(2,226	)	$	(2,691	)	$	(5,412	)	$	(693	)	$	(861	)	$	(1,378	)	$	(2,691	)

See accompanying Notes to Consolidated Financial Statements.

Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)


millions	September 30, 2016			December 31, 2015			September 30, 2017			December 31, 2016
ASSETS
Current Assets
Cash and cash equivalents ($146 and $100 related to VIEs)	$	3,980		$	939
Accounts receivable (net of allowance of $12 and $11)
Customers ($56 and $81 related to VIEs)	848			652
Others ($68 and $84 related to VIEs)	743			1,817
Cash and cash equivalents ($153 and $359 related to VIEs)							$	5,251		$	3,184
Accounts receivable (net of allowance of $16 and $14)
Customers ($104 and $70 related to VIEs)							1,009			1,007
Others ($12 and $80 related to VIEs)							873			721
Other current assets	347			573			340			354
Total	5,918			3,981			7,473			5,266
Properties and Equipment
Cost	69,089			70,683			64,855			69,013
Less accumulated depreciation, depletion, and amortization	37,990			36,932			37,023			36,845
Net properties and equipment ($5,037 and $4,859 related to VIEs)	31,099			33,751
Other Assets ($614 and $644 related to VIEs)	2,203			2,268
Goodwill and Other Intangible Assets ($1,230 and $1,220 related to VIEs)	6,197			6,331
Net properties and equipment ($5,508 and $5,050 related to VIEs)							27,832			32,168
Other Assets ($589 and $609 related to VIEs)							2,152			2,226
Goodwill and Other Intangible Assets ($1,200 and $1,221 related to VIEs)							5,671			5,904
Total Assets	$	45,417		$	46,331		$	43,128		$	45,564

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable ($185 and $179 related to VIEs)	$	1,983		$	2,850
Accounts payable
Trade ($280 and $234 related to VIEs)							$	1,770		$	1,617
Other							225			303
Short-term debt - Anadarko⁽¹⁾							149			42
Current asset retirement obligations	232			309			336			129
Interest payable	145			247
Other taxes payable ($32 and $18 related to VIEs)	313			318
Accrued expenses	301			424
Short-term debt	788			32
Other current liabilities							1,203			1,237
Total	3,762			4,180			3,683			3,328
Long-term Debt	15,090			15,636
Long-term debt - Anadarko⁽¹⁾							12,052			12,162
Long-term debt - WES and WGP							3,372			3,119
Total							15,424			15,281
Other Long-term Liabilities
Deferred income taxes	4,343			5,400			3,378			4,324
Asset retirement obligations ($137 and $127 related to VIEs)	1,744			1,750
Asset retirement obligations ($144 and $140 related to VIEs)							2,747			2,802
Other	4,566			3,908			3,974			4,332
Total	10,653			11,058			10,099			11,458

Equity
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 571.7 million and 528.3 million shares issued)	57			52
Common stock, par value $0.10 per share (1.0 billion shares authorized, 574.0 million and 572.0 million shares issued)							57			57
Paid-in capital	11,842			9,265			11,972			11,875
Retained earnings	2,246			4,880			160			1,704
Treasury stock (20.7 million and 20.0 million shares)	(1,027		)	(995		)
Treasury stock (21.4 million and 20.8 million shares)							(1,070		)	(1,033		)
Accumulated other comprehensive income (loss)	(518		)	(383		)	(337		)	(391		)
Total Stockholders’ Equity	12,600			12,819			10,782			12,212
Noncontrolling interests	3,312			2,638			3,140			3,285
Total Equity	15,912			15,457			13,922			15,497
Total Liabilities and Equity	$	45,417		$	46,331		$	43,128		$	45,564

Parenthetical references reflect amounts as of September 30, ~~2016,~~2017, and December 31, ~~2015.~~2016.

VIE amounts relate to WGP and WES. See Note 15—Variable Interest Entities.


⁽¹⁾	Excludes WES and WGP.

See accompanying Notes to Consolidated Financial Statements.

Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)


	Total Stockholders’ Equity
	Common Stock		Paid-in Capital		Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Non- controlling Interests			Total Equity			Total Stockholders’ Equity
millions																				Common Stock		Paid-in Capital			Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Non- controlling Interests			Total Equity
Balance at December 31, 2015	$	52	$	9,265	$	4,880		$	(995	)	$	(383	)	$	2,638		$	15,457
Balance at December 31, 2016																				$	57	$	11,875		$	1,704		$	(1,033	)	$	(391	)	$	3,285		$	15,497
Net income (loss)	—		—		(2,556		)	—			—			200			(2,356		)	—		—			(1,432		)	—			—			182			(1,250		)
Common stock issued	5		2,307		—			—			—			—			2,312
Common stock issued ⁽¹⁾																				—		123			—			—			—			—			123
Dividends—common stock	—		—		(78		)	—			—			—			(78		)	—		—			(84		)	—			—			—			(84		)
Repurchase of common stock	—		—		—			(32		)	—			—			(32		)	—		—			—			(37		)	—			—			(37		)
Subsidiary equity transactions	—		270		—			—			—			734			1,004			—		(23		)	—			—			—			—			(23		)
Distributions to noncontrolling interest owners	—		—		—			—			—			(260		)	(260		)	—		—			—			—			—			(327		)	(327		)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	—		—		—			—			4			—			4			—		—			—			—			2			—			2
Adjustments for pension and other postretirement plans	—		—		—			—			(139		)	—			(139		)	—		—			—			—			52			—			52
Balance at September 30, 2016	$	57	$	11,842	$	2,246		$	(1,027	)	$	(518	)	$	3,312		$	15,912
Cumulative effect of accounting change																				—		(3		)	(28		)	—			—			—			(31		)
Balance at September 30, 2017																				$	57	$	11,972		$	160		$	(1,070	)	$	(337	)	$	3,140		$	13,922


⁽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)


	Nine Months Ended September 30,						Nine Months Ended September 30,
millions	2016			2015			2017			2016
Cash Flows from Operating Activities
Net income (loss)	$	(2,356	)	$	(5,288	)	$	(1,250	)	$	(2,356	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	3,202			3,581			3,235			3,202
Deferred income taxes	(1,121		)	(2,627		)	(1,026		)	(1,121		)
Dry hole expense and impairments of unproved properties	300			1,993			2,144			300
Impairments	61			3,571			383			61
(Gains) losses on divestitures, net	516			1,003			(815		)	516
Loss on early extinguishment of debt	124			—			2			124
Total (gains) losses on derivatives, net	634			123			(33		)	634
Operating portion of net cash received (paid) in settlement of derivative instruments	229			251			21			229
Other	256			219			225			256
Changes in assets and liabilities
Tronox-related contingent liability	—			(5,210		)
(Increase) decrease in accounts receivable	810			23			(32		)	810
Increase (decrease) in accounts payable and accrued expenses	(833		)	(573		)
Increase (decrease) in accounts payable and other current liabilities							(95		)	(637		)
Other items, net	55			800			(140		)	(141		)
Net cash provided by (used in) operating activities	1,877			(2,134		)	2,619			1,877
Cash Flows from Investing Activities
Additions to properties and equipment	(2,618		)	(4,861		)	(3,538		)	(2,618		)
Divestitures of properties and equipment and other assets	1,281			1,248			3,480			1,281
Other, net	81			(83		)	32			81
Net cash provided by (used in) investing activities	(1,256		)	(3,696		)	(26		)	(1,256		)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	5,840			4,810			249			5,840
Repayments of debt	(6,023		)	(4,024		)	(42		)	(6,023		)
Financing portion of net cash received (paid) for derivative instruments	(639		)	(44		)	(160		)	(639		)
Increase (decrease) in outstanding checks	(126		)	(103		)	(58		)	(126		)
Dividends paid	(78		)	(415		)	(84		)	(78		)
Repurchase of common stock	(32		)	(38		)	(37		)	(32		)
Issuance of common stock, including tax benefit on share-based compensation awards	2,188			21
Issuance of common stock							—			2,188
Sale of subsidiary units	1,163			187			—			1,163
Issuance of tangible equity units — equity component	—			348
Distributions to noncontrolling interest owners	(260		)	(208		)	(327		)	(260		)
Proceeds from conveyance of future hard minerals royalty revenues, net of transaction costs	413			—			—			413
Payments of future hard minerals royalty revenues conveyed	(25		)	—			(50		)	(25		)
Other financing activities							(18		)	—
Net cash provided by (used in) financing activities	2,421			534			(527		)	2,421
Effect of Exchange Rate Changes on Cash	(1		)	(1		)	1			(1		)
Net Increase (Decrease) in Cash and Cash Equivalents	3,041			(5,297		)	2,067			3,041
Cash and Cash Equivalents at Beginning of Period	939			7,369			3,184			939
Cash and Cash Equivalents at End of Period	$	3,980		$	2,072		$	5,251		$	3,980

See accompanying Notes to Consolidated Financial Statements.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

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

Basis of Presentation The ~~Consolidated Financial Statements~~accompanying unaudited consolidated financial statements have been prepared in ~~conformity~~accordance with ~~generally accepted accounting principles~~GAAP for interim financial information and the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain notes and other information have been condensed or omitted. The accompanying interim financial statements reflect all normal recurring adjustments that are, in the ~~United States.~~opinion of management, necessary for the fair presentation of the Company’s consolidated financial statements. Certain prior-period amounts have been reclassified to conform to the ~~current-year~~current-period presentation. These ~~Consolidated Financial Statements~~interim financial statements should be read in conjunction with the ~~Consolidated Financial Statements~~consolidated financial statements and accompanying notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2015.~~2016.

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

The ~~Consolidated Financial Statements~~consolidated financial statements include the accounts of Anadarko and subsidiaries in which Anadarko holds, directly or indirectly, more than 50% of the voting rights and ~~variable interest entities (VIEs)~~VIEs for which Anadarko is the primary beneficiary. The Company has determined that WGP and WES are VIEs. Anadarko is considered the primary beneficiary and consolidates WGP and WES. WGP and WES function with capital structures that are separate from Anadarko, consisting of their own debt instruments and publicly traded common units. All intercompany transactions have been eliminated. Undivided interests in oil and natural-gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in noncontrolled entities ~~over which~~that Anadarko has the ability to exercise significant influence over operating and financial policies and VIEs for which Anadarko is not the primary beneficiary are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for the Company’s proportionate share of earnings, losses, and distributions. Other investments are carried at original cost. Investments accounted for using the equity method and cost method are ~~reported as a component of~~included in other assets.

Recently Adopted Accounting Standards ~~The Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2015-03,~~ASU 2017-01, ~~Interest—Imputation~~Business Combinations (Topic 805): Clarifying the Definition of ~~Interest (Subtopic 835-30): Simplifying~~a Business, assists in determining whether a transaction should be accounted for as an acquisition or disposal of assets or as a business. This ASU provides a screen that when substantially all of the ~~Presentation~~fair value of ~~Debt Issuance Costs~~the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the assets will not be considered a business. If the screen is not met, the assets must include an input and ~~ASU 2015-15,~~ ~~Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. These ASUs require capitalized debt issuance costs, except for those related~~a substantive process that together significantly contribute to ~~revolving credit facilities,~~the ability to create an output to be ~~presented in the balance sheet as~~considered a ~~direct deduction from the carrying amount~~business. The Company’s adoption of the related debt liability, rather than as an asset. The Company adopted these ASUs on January 1, 2016, using a retrospective approach. The adoption resulted in a reclassification that reduced other current assets and short-term debt by $1 million and reduced other assets and long-term debt by $82 million on the Company’s Consolidated Balance Sheet at December 31, 2015.

~~The FASB issued ASU 2015-02,~~ ~~Consolidation (Topic 810): Amendments to the Consolidation Analysis.~~ ~~The Company adopted~~ this ASU on January 1, 2016. In accordance with the new ASU, Western Gas Equity Partners, LP (WGP) and Western Gas Partners, LP (WES), publicly traded consolidated subsidiaries of the Company, are considered VIEs for which the Company is the primary beneficiary. Prior to adoption of the ASU, WGP and WES were consolidated by the Company under the voting interest model. After adoption, WGP and WES were consolidated by the Company under the variable interest model. While this ASU requires additional financial statement disclosure, it has no2017, using a prospective approach, could have a material impact on ~~the Company’s~~ consolidated ~~results of operations, cash flows,~~financial statements as goodwill will not be allocated to divestitures or ~~financial position.~~recorded on acquisitions that are not considered businesses. See Note ~~17—Variable Interest Entities~~3—Acquisitions, Divestitures, and Assets Held for Sale.

~~New Accounting Standards Issued But Not Yet Adopted~~ ~~The FASB issued~~ ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,~~. This ASU~~ 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. ~~This~~The Company adopted this ASU ~~is effective for annual and interim periods beginning in 2018 and is required to be adopted~~on January 1, 2017, using a modified retrospective approach, ~~with early adoption permitted. The Company is evaluating~~and recognized a cumulative adjustment to retained earnings of $31 million during the ~~impact~~first quarter of ~~the adoption of this ASU on its consolidated financial statements.~~2017.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies (Continued)

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

New Accounting Standards Issued But Not Yet Adopted ASU 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period and presentation of the remaining components of net benefit cost in a separate line item outside operating items. Additionally, only the service cost component of net benefit cost will be eligible for capitalization. The ~~FASB issued~~ 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 $94 million for the nine months ended September 30, 2017, will be reclassified to other (income) expense, net, from G&A; oil and gas operating; gathering, processing, and marketing; and exploration expense. The Company does not expect any other material changes upon adoption of this ASU.

ASU 2016-18, 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 will adopt this ASU on January 1, 2018, and does not expect the adoption 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,~~. This ASU~~ 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 ~~in 2018~~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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~~The FASB issued ASU 2016-09,~~ A~~Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.~~ This ASU simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, classification on the statement of cash flows, and accounting for forfeitures. This ASU is effective for annual and interim periods beginning in 2017 with early adoption permitted. The Company will adopt this ASU beginning on January 1, 2017, and does not expect the adoption to have a material impact on its consolidated financial statements.NADARKO PETROLEUM CORPORATION

~~The FASB issued ASU 2016-02,~~ ~~Leases (Topic 842).~~ This ASU requires the 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 and disclose key information about their leasing transactions. This ASU is effective for annual and interim periods beginning in 2019. The Company is evaluating the impactNOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of ~~the adoption of this ASU on its consolidated financial statements.~~Significant Accounting Policies (Continued)

~~The FASB issued~~ ASU 2014-09, Revenue from Contracts with Customers (Topic 606), ,~~which~~ supersedes current revenue recognition requirements and ~~industry-specific guidance. The codification was amended through additional ASUs and, as amended,~~ requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing, and uncertainty of revenue and cash flows from contracts with customers. The Company has completed an initial review of contracts in each of its revenue streams and is ~~required~~developing accounting policies to ~~adopt~~address the provisions of the ASU. While the Company does not currently expect net earnings to be materially impacted, the Company has concluded that it is acting as an agent in the sale of certain volumes on behalf of its midstream service customers based on the requirements of the new ASU. This conclusion will result in the reduction of gathering and processing revenues and a corresponding reduction to gathering and processing expense related to its contracts with these customers. In addition, the Company expects to recognize revenue for commodities received as noncash consideration in exchange for services provided by our midstream business and revenue and associated cost of product for the subsequent sale of those same commodities. This recognition will result in an increase to revenues and expenses for gathering and processing activities with no impact on net earnings. The Company also expects changes in the timing of recognizing revenue for certain fees earned from its midstream business and hard minerals royalties due to the fee structure of certain contracts. Anadarko continues to evaluate the impact of these and other provisions of the ASU on its accounting policies, internal controls, and consolidated financial statements. Although the Company has not finalized the quantitative impact of the new standard, inbased on the ~~first~~assessment completed to date, the Company does not expect the adoption of this standard will have a material impact on its net earnings. The Company will complete its evaluation during the fourth quarter of 2017 and will adopt this new standard on January 1, 2018, using ~~one of two~~the modified retrospective ~~application methods.~~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 ~~Company is continuing to evaluate the~~ provisions of ~~this~~ 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. Anadarko 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. Anadarko has ~~not~~preliminarily determined its portfolio of leased assets and is reviewing all related contracts to determine the impact ~~this standard may~~that adoption will have on its consolidated financial ~~statements~~statements. The Company is also evaluating the impact of this ASU on its systems, processes, and ~~related disclosures or decided upon the method of adoption.~~internal controls. The Company will complete its evaluation in 2018 and adopt this new standard on January 1, 2019, using a modified retrospective approach for all comparative periods presented.

2. Inventories

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


millions	September 30, 2016		December 31, 2015		September 30, 2017		December 31, 2016
Oil	$	136	$	116	$	127	$	169
Natural gas	35		36		29		38
NGLs	83		64		108		106
Total inventories	$	254	$	216	$	264	$	313

810

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

3. Acquisitions, Divestitures, and Assets Held for Sale

Acquisition ~~In September~~On December 15, 2016, the Company ~~entered into an agreement to acquire certain oil and gas assets in~~closed the ~~Gulf of Mexico~~GOM Acquisition for ~~$2.0~~$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 constituted a business combination and was accounted for using the acquisition ~~is expected~~method of accounting. Fair-value measurements of the assets acquired and liabilities assumed at the acquisition date were finalized during the quarter ended June 30, 2017. There were no material changes to ~~close~~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 ~~fourth quarter~~DBJV system in exchange for WES’s 33.75% interest in nonoperated Marcellus midstream assets and $155 million in cash. WES recognized a gain of ~~2016~~$126 million as a result of this transaction. After the acquisition, the DBJV system is 100% owned by WES and ~~is subject to customary closing conditions. See~~ ~~Note 14—Stockholders’ Equity~~.consolidated by Anadarko.

Divestitures and Assets Held for Sale ~~For~~The following summarizes the proceeds received and gains (losses) recognized on divestitures and assets held for sale for the nine months ended September ~~30, 2016, the Company received $1.3 billion in net proceeds from divestitures and recognized net losses of $516 million from divestitures and assets held for sale.~~30:



millions	2017		2016
Proceeds received, net of closing adjustments	$	3,480	$	1,281
Gains (losses) on divestitures, net ⁽¹⁾	815		(516		)


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

~~Divestitures~~2017 During the nine months ended September 30, ~~2016,~~2017, the Company divested of the following ~~U.S. onshore~~ assets:

~~certain West Texas~~Eagleford assets in South Texas, included in the ~~oil~~Exploration and ~~gas exploration~~Production reporting segment, for net proceeds of $2.1 billion and ~~production~~a net gain of $730 million

Eaglebine assets in Southeast Texas, included in the Exploration and ~~midstream~~Production reporting segment, for net proceeds of $533 million and a net gain of $282 million

Utah CBM assets, included in the Exploration and Production and Midstream reporting segments, for net proceeds of ~~$223 million and a loss of $50 million~~

~~certain East Texas/Louisiana assets in the oil and gas exploration and production reporting segment for net proceeds of $199~~$69 million and a net loss of ~~$41~~$52 million

~~certain Wyoming~~Marcellus assets in Pennsylvania, included in the ~~oil~~Exploration and ~~gas exploration~~Production and ~~production~~Midstream reporting ~~segment~~segments, for net proceeds of ~~$588~~$758 million and net losses of $129 million in the fourth quarter of 2016 and $56 million for the nine months ended September 30, 2017

Certain Marcellus assets in Pennsylvania, included in the Exploration and Production and Midstream reporting segments, satisfied criteria to be considered held for sale during the fourth quarter of 2016, at which time the Company remeasured these assets to their current fair value using a market approach and Level 2 fair-value inputs and recognized the losses discussed above. Proceeds of $196 million associated with these assets were held in escrow by the purchaser and reflected as Accounts Receivable, Others on the Company’s Consolidated Balance Sheet as of September 30, 2017. In October 2017, proceeds of $193 million were released from escrow. The remaining $3 million is expected to be released by early 2018.

Certain Moxa Arch assets in Wyoming, included in the Exploration and Production reporting segment, satisfied criteria to be considered held for sale during the third quarter of 2017, at which time the Company remeasured these assets to their current fair value using a market approach and Level 2 fair-value inputs and recognized a loss of ~~$59~~$197 million. At September 30, 2017, the Company’s Consolidated Balance Sheet included long-term assets of $557 million

~~Assets Held~~ and long-term liabilities of $37 million associated with the Moxa Arch assets held for ~~Sale~~ sale. Losses on assets held for sale are included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income. ~~Certain U.S. onshore~~

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

2016 During the nine months ended September 30, 2016, the Company divested of the following assets:

Wamsutter assets ~~located primarily~~in Wyoming, included in the Exploration and Production reporting segment, for net proceeds of $588 million and a net loss of $59 million

Ozona and Steward assets in West Texas, included in the Exploration and Production and Midstream reporting segments, for net proceeds of $223 million and a net loss of $50 million

East Chalk assets in East Texas/Louisiana, included in the Exploration and Production reporting segment, for net proceeds of $99 million and a net gain of $13 million

Elm Grove assets in East Texas/Louisiana, included in the Exploration and Production reporting segment, for net proceeds of $100 million and a net loss of $54 million

The Carthage assets in East Texas, included in the ~~oil~~Exploration and ~~gas exploration~~Production and ~~production and midstream~~Midstream reporting segments, satisfied criteria to be considered held for sale during the third quarter of 2016, at which time the Company remeasured these assets to their current fair value using a market approach and Level 2 fair-value measurement and recognized a loss of $355 million. The sale of these assets ~~is expected to close~~closed in the fourth quarter of 2016. At September 30, 2016, the Company’s Consolidated Balance Sheet included long-term assets of $1.1 billion, which includes $184 million of goodwill, and long-term liabilities of $44 million associated with assets held for sale.

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A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

4. Impairments

Impairments of Long-Lived Assets Impairments of long-lived assets are included in impairment expense in the Company’s Consolidated Statements of Income. The following summarizes impairments of long-lived assets and the related post-impairment fair values by segment:

Three Months Ended Nine Months Ended
millions Impairment
Fair Value⁽¹⁾
Impairment
Fair Value⁽¹⁾
September 30, 2016
Oil and gas exploration and production
Long-lived assets held for use
U.S. onshore properties $ 23
$ 32
$ 27
$ 617
Gulf of Mexico properties —
—
2
—
Cost-method investment ⁽²⁾
—
—
2
32
Midstream
Long-lived assets held for use 3
—
24
5
Other
Long-lived assets held for use 1
—
6
—
Total $ 27
$ 32
$ 61
$ 654

September 30, 2015
Oil and gas exploration and production
Long-lived assets held for use
U.S. onshore properties $ 641
$ 634
$ 2,944
$ 1,904
Gulf of Mexico properties 101
94
126
94
Cost-method investment ⁽²⁾
1
32
2
32
Midstream
Long-lived assets held for use 15
7
499
209
Total $ 758
$ 767
$ 3,571
$ 2,239



	Nine Months Ended
millions	Impairment		Fair Value⁽¹⁾
September 30, 2017
Exploration and Production
U.S. onshore properties	$	2	$	3
Gulf of Mexico properties	211		231
Midstream	169		58
Other	1		—
Total	$	383	$	292


⁽¹⁾	Measured as of the impairment date using the income approach and Level 3 inputs.


⁽²⁾	~~Represents the after-tax~~ The primary assumptions used to estimate undiscounted future net ~~investment.~~cash flows include anticipated future production, commodity prices, and capital and operating costs.

Impairments during the three and nine months ended September 30, 2016, were primarily related to U.S. onshore oil and gas and midstream properties due to changes in development plans. Impairments during the three months ended September 30, 2015, were primarily related to U.S. onshore oil and gas properties and an oil and gas property in the Gulf of Mexico, all of which were impaired due to lower forecasted commodity prices. Impairments during the nine months ended September 30, ~~2015,~~2017, were primarily related to ~~the Company’s Greater Natural Buttes oil and gas and midstream properties, certain other U.S. onshore oil and gas and midstream properties, and~~ oil and gas properties in the Gulf of Mexico ~~all of which were impaired~~ due to lower forecasted commodity ~~prices.~~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. ~~During the third quarter of 2015, the~~The Company recognized ~~a $109~~$586 million ~~impairment~~of impairments of unproved ~~Utica properties resulting from an assignment~~Gulf of ~~mineral interests in settlement of a legal matter. The Company also recognized a $935 million impairment of unproved Greater Natural Buttes~~Mexico properties during the nine months ended September 30, ~~2015, as a result~~2017, primarily due to an impairment of ~~lower commodity prices.~~$463 million to the Shenandoah project. The unproved property balance related to the Shenandoah project originated from the purchase price allocated to Gulf of Mexico exploration projects from the acquisition of Kerr-McGee Corporation in 2006. For additional details on the Shenandoah project, see Note 5—Exploratory Well Costs.

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A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~4. Impairments (Continued)~~

~~Potential for Future Impairments~~ At September 30, 2016, the Company’s estimates of undiscounted future cash flows attributable to a certain international asset group with a net book value of approximately $1.4 billion, and certain U.S. onshore asset groups with a combined net book value of approximately $1.1 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 a non-cash impairment in excess of $600 million for the international asset group, and a 10% decline in natural-gas prices (with all other assumptions unchanged) could result in non-cash impairments in excess of $400 million for the U.S. onshore asset groups. It is ~~also~~ reasonably possible that ~~prolonged low or further~~significant declines in commodity prices, further changes to the Company’s drilling plans in response to lower prices, reduction of proved and probable reserve estimates, or increases in drilling or operating costs could result in other additional impairments.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

5. ~~Suspended~~ Exploratory Well Costs

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

Gulf of Mexico The Company expensed exploratory well costs of $801 million during the nine months ended September 30, 2017, primarily related to the following projects:

Shenandoah The Company expensed $438 million related to the Shenandoah-6 appraisal well and subsequent sidetrack, which completed appraisal activities in April 2017 and did not encounter the oil-water contact in the eastern portion of the field. Given the results of this well and the commodity-price environment at that time, the Company suspended further appraisal activities.

Phobos The Company expensed $221 million in the third quarter of 2017 related to wells at the Phobos project. These wells found insufficient quantities of oil pay to justify development in the current price environment.

Warrior The Company expensed $110 million in the third quarter of 2017 related to the northern appraisal well and sidetrack at the Warrior project. These wells found insufficient quantities of oil pay to justify development of the northern portion of the field in the current price environment. Evaluation of the remaining appraisal well in the southern portion of the field is ongoing.

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

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

Suspended Exploratory Well CostsThe Company’s suspended exploratory well costs were ~~$1.2 billion~~$530 million at September 30, ~~2016,~~2017, and ~~$1.1~~$1.2 billion at December 31, ~~2015. The increase in suspended~~2016. For exploratory ~~well costs during 2016 is primarily related to the capitalization of costs associated with appraisal activities in Côte d’Ivoire. Projects with suspended exploratory well~~wells, drilling costs are ~~those identified by management as exhibiting~~capitalized, or “suspended,” on the balance sheet when the well has found a sufficient ~~quantities~~quantity of ~~hydrocarbons~~reserves to justify ~~potential development or where it~~its completion as a producing well and sufficient progress is ~~reasonably possible that~~being made in assessing the ~~well can be utilized in~~reserves and the ~~development~~economic and operating viability of the ~~project and when management is actively pursuing efforts to assess whether reserves can be attributed to these projects.~~project. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time.

During the nine months ended September 30, ~~2016, $142~~2017, $488 million of suspended exploratory well costs previously capitalized for greater than one year at December 31, ~~2015,~~2016, were charged to exploration ~~expense and primarily related to the following:~~

$64 million related to a Shenandoah well in the Gulf of Mexico was expensed as it was no longer reasonably possible that the wellbore would be used in the development of the project if a final investment decision is reached

~~$38 million related to the Orca-4 well in Mozambique was expensed after additional reservoir analysis and the determination that the well was not associated with the first three Orca wells~~

$33 million related to the Tubarão Tigre discovery was expensed based on the outlook for development viability, given current commodity market conditions and the complexity introduced by the depth and characteristics of the reservoir

~~Costs of $21 million previously capitalized for less than one year at December 31, 2015, related to the Tubarão Tigre discovery discussed above, were also charged to exploration~~ expense.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6. Current Liabilities

Accounts Payable Accounts payable, trade included liabilities of $204 million at September 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	September 30, 2017		December 31, 2016
Accrued income taxes	$	211	$	6
Interest payable	161		244
Production, property, and other taxes payable	249		239
Accrued employee benefits	207		355
Derivatives	233		175
Other	142		218
Total other current liabilities	$	1,203	$	1,237

7. Derivative Instruments

Objective and Strategy The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Futures, swaps, and options are used to manage exposure to commodity-price risk inherent in the Company’s oil and natural-gas production and natural-gas processing operations (Oil and Natural-Gas Production/Processing Derivative Activities). Futures contracts and commodity-price swap agreements are used to fix the price of expected future oil and natural-gas sales at major industry trading locations such as Cushing, Oklahoma or Sullom Voe, Scotland for oil and Henry Hub, Louisiana for natural gas. Basis swaps are periodically used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities (Marketing and Trading Derivative Activities).

Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to interest-rate changes. The fair value of the Company’s current interest-rate swap portfolio is subject to changes in interest rates.

The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized currently in earnings. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings. ~~See~~ ~~Note 15—Accumulated Other Comprehensive Income (Loss)~~.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6.7. Derivative Instruments (Continued)

Oil and Natural-Gas Production/Processing Derivative Activities The oil prices listed below are a combination of ~~New York Mercantile Exchange (NYMEX)~~NYMEX West Texas Intermediate and Intercontinental Exchange, Inc. (ICE) Brent Blend prices. The natural-gas prices listed below are NYMEX Henry Hub prices. The NGLs prices listed below are Oil Price Information Services prices. The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at September 30, ~~2016~~:2017:

2016 Settlement 2017 Settlement 2018 Settlement
Oil
Three-Way Collars (MBbls/d) 83
—
—
Average price per barrel
Ceiling sold price (call) $ 63.82
$ —
$ —
Floor purchased price (put) $ 54.46
$ —
$ —
Floor sold price (put) $ 42.77
$ —
$ —
Natural Gas
Three-Way Collars (thousand MMBtu/d) —
682
250
Average price per MMBtu
Ceiling sold price (call) $ —
$ 3.60
$ 3.54
Floor purchased price (put) $ —
$ 2.75
$ 2.75
Floor sold price (put) $ —
$ 2.00
$ 2.00
Fixed-Price Contracts (thousand MMBtu/d) —
37
—
Average price per MMBtu $ —
$ 3.14
$ —
NGLs
Fixed-Price Contracts (MBbls/d) —
2
—
Average price per barrel $ —
$ 15.84
$ —

~~MBbls/d—thousand barrels per day~~

~~MMBtu/d—million British thermal units per day~~

~~MMBtu—million British thermal units~~



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

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

Marketing and Trading Derivative Activities The Company had financial derivative transactions with notional volumes of natural gas totaling ~~5 billion cubic feet (Bcf)~~15 Bcf at September 30, ~~2016~~,2017, and 82 Bcf at December 31, ~~2015~~,2016, that were entered into to mitigate commodity-price risk related to fixed-price purchase and sales contracts and storage activity.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6.7. Derivative Instruments (Continued)

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

In ~~February 2016, in exchange for amended terms with certain counterparties,~~June 2017, the Company ~~modified the mandatory termination dates from 2021 to 2018 and, in some cases, the related fixed interest rates on~~amended certain interest-rate swaps with an aggregate notional principal amount of ~~$500~~$625 million, extending the mandatory termination dates from 2018 to 2020, 2022, and 2023 in exchange for cash payments of approximately $57 million. ~~Additionally,~~In July 2017, the Company amended an interest-rate swap ~~agreement was settled~~with a notional principal amount of $125 million, extending the mandatory termination date from 2018 to 2022 in exchange for a cash payment of $193 million in March 2016, and interest-rate swap agreements were settled for total cash payments of $73 million in September 2016. Anadarko does not expect additional net cash outlays in 2016 related to interest-rate derivative settlements.approximately $15 million.

At September 30, ~~2016~~,2017, the Company had outstanding interest-rate swaps with a notional amount of $1.6 billion due prior to or atin September ~~2021~~2023 that ~~will~~ manage interest-rate risk associated with the potential refinancing of the Company’s $900 million Senior Notes due 2019 and the Zero-Coupon Senior Notes due 2036 (Zero Coupons), should the Zero Coupons be put to the Company prior to the swap termination dates. None of the Zero Coupons (accreted value of $839 million) ~~were put to the Company in October 2016. See~~ ~~Note 8—Debt and Interest Expense~~.future debt maturities. Depending on market conditions, liability-management actions, or other factors, the Company may enter into offsetting interest-rate swap positions or settle or amend certain or all of the currently outstanding interest-rate swaps. The Company had the following outstanding interest-rate swaps at September 30, 2017:



millions except percentages			Mandatory	Weighted-Average
Notional Principal Amount		Reference Period	Termination Date	Interest Rate
$	550	September 2016 - 2046	September 2020	6.418%
$	250	September 2016 - 2046	September 2022	6.809%
$	200	September 2017 - 2047	September 2018	6.049%
$	100	September 2017 - 2047	September 2020	6.891%
$	250	September 2017 - 2047	September 2021	6.570%
$	250	September 2017 - 2047	September 2023	6.761%

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

~~The Company had~~ Net cash payments related to settlements and amendments of interest-rate swap agreements were $118 million during the ~~following outstanding interest-rate swaps at~~ nine months ended September 30, ~~2016~~:

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%
2017, and $275 million during the nine months ended September 30, 2016.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6.7. Derivative Instruments (Continued)

Effect of Derivative Instruments—Balance Sheet The following summarizes the fair value of the Company’s derivative instruments:


	Gross Derivative Assets				Gross Derivative Liabilities						Gross Derivative Assets				Gross Derivative Liabilities
millions	September 30,		December 31,		September 30,			December 31,			September 30,		December 31,		September 30,			December 31,
Balance Sheet Classification	2016		2015		2016			2015			2017		2016		2017			2016
Commodity derivatives
Other current assets	$	65	$	462	$	(8	)	$	(177	)	$	58	$	10	$	(40	)	$	(3	)
Other assets	29		8		(2		)	—			33		9		(29		)	—
Accrued expenses	2		—		(18		)	(3		)
Other current liabilities											38		66		(44		)	(201		)
Other liabilities	3		—		(22		)	—			163		—		(166		)	(12		)
	99		470		(50		)	(180		)	292		85		(279		)	(216		)
Interest-rate derivatives
Other current assets	4		2		—			—			12		8		—			—
Other assets	18		54		—			—			42		23		—			—
Accrued expenses	—		—		(48		)	(54		)
Other current liabilities											—		—		(237		)	(48		)
Other liabilities	—		—		(1,806		)	(1,488		)	—		—		(1,176		)	(1,328		)
	22		56		(1,854		)	(1,542		)	54		31		(1,413		)	(1,376		)
Total derivatives	$	121	$	526	$	(1,904	)	$	(1,722	)	$	346	$	116	$	(1,692	)	$	(1,592	)

Effect of Derivative Instruments—Statement of Income The following summarizes gains and losses related to derivative instruments:


millions	Three Months Ended September 30,						Nine Months Ended September 30,					Three Months Ended September 30,					Nine Months Ended September 30,
Classification of (Gain) Loss Recognized	2016			2015			2016		2015			2017		2016			2017			2016
Commodity derivatives
Gathering, processing, and marketing sales ⁽¹⁾	$	(1	)	$	(1	)	$	5	$	—		$	—	$	(1	)	$	—		$	5
(Gains) losses on derivatives, net	(59		)	(125		)	7		(177		)	43		(59		)	(164		)	7
Interest-rate derivatives
(Gains) losses on derivatives, net	84			407			622		300			39		84			131			622
Total (gains) losses on derivatives, net	$	24		$	281		$	634	$	123		$	82	$	24		$	(33	)	$	634


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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6.7. Derivative Instruments (Continued)

Credit-Risk Considerations The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or ICE through systems of financial safeguards and transaction guarantees. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact on the fair value of its counterparties’ creditworthiness. The Company has the ability to require cash collateral or letters of credit to mitigate its credit-risk exposure.

The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities and routinely exercises its contractual right to offset gains and losses when settling with derivative counterparties. In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and provide for contract termination and net settlement across derivative types. At September 30, 2016, $52 million of the Company’s $1.904 billion gross derivative liability balance, and at December 31, 2015, $347 million of the Company’s $1.722 billion gross derivative liability balance, would have been eligible for setoff against the Company’s gross derivative asset balance in the event of default. Other than in the event of default, the Company does not net settle across derivative types.

The Company’s derivative instruments are subject to individually negotiated credit provisions that may require collateral of cash or letters of credit depending on the derivative’s portfolio valuation versus negotiated credit thresholds. These credit thresholds may also require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered, such as if the Company’s credit rating from ~~major credit rating agencies~~S&P and Moody’s declines to a level that is below investment grade. ~~In February 2016, Moody’s Investors Service (Moody’s) downgraded~~As of September 30, 2017, the Company’s long-term debt~~credit rating from “Baa2” to “Ba1,” which is~~ was rated investment grade (BBB) by both S&P and Fitch Ratings and below investment ~~grade. The downgrade triggered credit-risk-related features with~~grade (Ba1) by Moody’s. Although certain ~~derivative~~ counterparties ~~and~~ required the Company to post collateral under its derivative instruments. During the third quarter of 2016, Anadarko paid a fee in connection with the negotiated increase of a credit threshold for an interest-rate derivative with an other-than-insignificant financing element. As a result of the increased credit threshold, $200 million of collateral was returneddue to the ~~Company. No~~Moody’s rating, no counterparties have requested termination or full settlement of derivative positions. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was ~~$1.4~~$1.2 billion (net of ~~$422~~$159 million of collateral) at September 30, ~~2016,~~2017, and ~~$1.3~~$1.4 billion (net of ~~$58~~$117 million of collateral) at December 31, ~~2015.~~2016.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6.7. Derivative Instruments (Continued)

Fair Value Fair value of futures contracts is based on unadjusted quoted prices in active markets for identical assets or liabilities, which represent Level 1 inputs. Valuations of physical-delivery purchase and sale agreements, over-the-counter financial swaps, and commodity option collars are based on similar transactions observable in active markets and industry-standard models that primarily rely on market-observable inputs. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. Inputs used to estimate the fair value of swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and, for Black-Scholes option valuations, discount factors and implied market volatility.

The following summarizes the fair value of the Company’s derivative assets and liabilities by input level within the fair-value hierarchy:


millions																		Level 1			Level 2			Level 3		Netting ⁽¹⁾			Collateral		Total
September 30, 2016	Level 1			Level 2			Level 3		Netting ⁽¹⁾			Collateral			Total
September 30, 2017
Assets
Commodity derivatives	$	—		$	99		$	—	$	(14	)	$	—		$	85		$	—		$	292		$	—	$	(271	)	$	—	$	21
Interest-rate derivatives	—			22			—		—			—			22			—			54			—		—			—		54
Total derivative assets	$	—		$	121		$	—	$	(14	)	$	—		$	107		$	—		$	346		$	—	$	(271	)	$	—	$	75
Liabilities
Commodity derivatives	$	(1	)	$	(49	)	$	—	$	14		$	2		$	(34	)	$	—		$	(279	)	$	—	$	271		$	—	$	(8	)
Interest-rate derivatives	—			(1,854		)	—		—			422			(1,432		)	—			(1,413		)	—		—			159		(1,254		)
Total derivative liabilities	$	(1	)	$	(1,903	)	$	—	$	14		$	424		$	(1,466	)	$	—		$	(1,692	)	$	—	$	271		$	159	$	(1,262	)

December 31, 2015
December 31, 2016
Assets
Commodity derivatives	$	10		$	460		$	—	$	(178	)	$	(8	)	$	284		$	2		$	83		$	—	$	(69	)	$	—	$	16
Interest-rate derivatives	—			56			—		—			—			56			—			31			—		—			—		31
Total derivative assets	$	10		$	516		$	—	$	(178	)	$	(8	)	$	340		$	2		$	114		$	—	$	(69	)	$	—	$	47
Liabilities
Commodity derivatives	$	(1	)	$	(179	)	$	—	$	178		$	—		$	(2	)	$	(3	)	$	(213	)	$	—	$	69		$	6	$	(141	)
Interest-rate derivatives	—			(1,542		)	—		—			58			(1,484		)	—			(1,376		)	—		—			117		(1,259		)
Total derivative liabilities	$	(1	)	$	(1,721	)	$	—	$	178		$	58		$	(1,486	)	$	(3	)	$	(1,589	)	$	—	$	69		$	123	$	(1,400	)

__________________________________________________________________


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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~7. Tangible Equity Units~~

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

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

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

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

8. Debt ~~and Interest Expense~~

~~Debt Activity~~ ~~The following summarizes the Company’s borrowing activity, after eliminating the effect of intercompany transactions, during the nine months ended September 30, 2016:~~

Carrying Value
millions WES
WGP ⁽¹⁾

Anadarko ⁽²⁾
Anadarko Consolidated Description
Balance at December 31, 2015 $ 2,691
$ —
$ 12,957
$ 15,648

Issuances —
—
794
794
4.850% Senior Notes due 2021
—
—
1,088
1,088
5.550% Senior Notes due 2026
—
—
1,088
1,088
6.600% Senior Notes due 2046
495
—
—
495
WES 4.650% Senior Notes due 2026
Borrowings —
—
1,750
1,750
364-Day Facility
600
—
—
600
WES RCF
—
28
—
28
WGP RCF
Repayments —
—
(1,749 ) (1,749 ) 5.950% Senior Notes due 2016
—
—
(1,245 ) (1,245 ) 6.375% Senior Notes due 2017
—
—
(1,750 ) (1,750 ) 364-Day Facility
(880 ) —
—
(880 ) WES RCF
—
—
(250 ) (250 ) Commercial paper notes, net
—
—
(25 ) (25 ) TEUs - senior amortizing notes
Other, net 1
—
40
41
Amortization of discounts, premiums, and debt issuance costs
Balance at September 30, 2016 $ 2,907
$ 28
$ 12,698
$ 15,633


⁽¹⁾	~~Excludes WES.~~


⁽²⁾	~~Excludes WES and WGP.~~

During the second quarter of 2016, the Company used proceeds from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.250 billion of its $2.0 billion 6.375% Senior Notes due September 2017 pursuant to a tender offer and to redeem its $1.750 billion 5.950% Senior Notes due September 2016. The Company recognized a loss of $124 million for the early retirement and redemption of these senior notes, which included $114 million of premiums paid.

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

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

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⁾			Consolidated
September 30, 2016
Total borrowings at face value	$	2,940		$	28	$	14,317		$	17,285
Net unamortized discounts, premiums, and debt issuance costs ⁽³⁾	(33		)	—		(1,619		)	(1,652		)
Total borrowings ⁽⁴⁾	2,907			28		12,698			15,633
Capital lease obligations	—			—		245			245
Less short-term debt ⁽⁵⁾	—			—		788			788
Total long-term debt	$	2,907		$	28	$	12,155		$	15,090

December 31, 2015
September 30, 2017
Total borrowings at face value	$	2,720		$	—	$	14,592		$	17,312		$	3,370		$	28	$	13,523		$	16,921
Net unamortized discounts, premiums, and debt issuance costs ⁽³⁾	(29		)	—		(1,635		)	(1,664		)	(26		)	—		(1,563		)	(1,589		)
Total borrowings ⁽⁴⁾	2,691			—		12,957			15,648			3,344			28		11,960			15,332
Capital lease obligations	—			—		20			20			—			—		241			241
Less short-term debt	—			—		32			32			—			—		149			149
Total long-term debt	$	2,691		$	—	$	12,945		$	15,636		$	3,344		$	28	$	12,052		$	15,424

December 31, 2016
Total borrowings at face value												$	3,120		$	28	$	13,558		$	16,706
Net unamortized discounts, premiums, and debt issuance costs ⁽³⁾												(29		)	—		(1,599		)	(1,628		)
Total borrowings ⁽⁴⁾												3,091			28		11,959			15,078
Capital lease obligations												—			—		245			245
Less short-term debt												—			—		42			42
Total long-term debt												$	3,091		$	28	$	12,162		$	15,281


⁽¹⁾	Excludes WES.


⁽²⁾	Excludes WES and WGP.


⁽³⁾	Unamortized discounts, premiums, and debt issuance costs are amortized over the term of the related debt. Debt issuance costs related to ~~revolving credit facilities~~RCFs are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.


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


⁽⁵⁾	~~Short-term debt includes $750 million of 6.375% Senior Notes due September 2017. In October 2016, the Company provided notice of its intent to redeem the notes prior to year end.~~

Anadarko’s Zero Coupons can be put to the Company in October of each year, in whole or in part, for the then-accreted value of the outstanding Zero Coupons. None of the Zero Coupons (accreted value of $839 million) were put to the Company in October 2016.

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 ~~$17.6~~$17.4 billion at September 30, ~~2016,~~2017, and ~~$15.7~~$17.1 billion at December 31, ~~2015.~~2016.

Table of Contents

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

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

~~In January 2015,~~Anadarko’s Zero Coupons can be put to the Company ~~initiated a commercial paper program, which allows~~in October of each year, in whole or in part, for ~~a maximum of $3.0 billion of unsecured commercial paper notes and is supported by~~ the ~~Five-Year Facility. The maturities~~then-accreted value of the ~~commercial paper~~outstanding Zero Coupons. None of the Zero Coupons were put to the Company in October 2017. The Zero Coupons can next be put to the Company in October 2018, in whole or in part, for the then-accreted value of $930 million.

The Company also has notes ~~may vary, but may~~payable related to its ownership of certain noncontrolling mandatorily redeemable interests that are not ~~exceed 397 days. In February 2016, Moody’s downgraded~~included in the Company’s ~~commercial paper program credit rating, which eliminated~~reported debt balance and do not affect consolidated interest expense. See Note 8—Equity Method Investments in the Company’s ~~access to~~Annual Report on Form 10-K for the ~~commercial paper market. The Company has not issued commercial paper notes since the downgrade and had no outstanding borrowings under the commercial paper program at September 30,~~year ended December 31, 2016.

WES and WGP Borrowings ~~In July 2016,~~At September 30, 2017, WES ~~completed a public offering of $500 million aggregate principal amount of 4.650% Senior Notes due July 2026. Net proceeds were used to repay a portion of the amount outstanding under WES’s~~was in compliance with all covenants contained in its $1.2 billion~~five-year~~ senior unsecured ~~revolving credit facility~~RCF maturing in February ~~2019~~2020 (WES RCF), which is expandable to $1.5 billion.

During the nine months ended September 30, 2017, WES borrowed $250 million under its RCF, which was used for general partnership purposes. At September 30, ~~2016,~~2017, WES had outstanding borrowings under its RCF of ~~$20~~$250 million at an interest rate of ~~1.82%~~2.54%, had outstanding letters of credit of $5 million, and had available borrowing capacity of ~~$1.18 billion.~~ $945 million. WES’s $350 million 2.60% Senior Notes due August 2018 were classified as long-term debt on the Company’s Consolidated Balance Sheet at September 30, 2017, as WES has the ability and intent to refinance these obligations using long-term debt.

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

~~In March 2016, WGP entered into a~~covenants contained in its $250 millionthree-year senior secured ~~revolving credit facility~~RCF maturing in March 2019 (WGP RCF), which is expandable to $500 million subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions. Obligations under the WGP RCF are secured by a first priority lien on all of WGP’s assets (not including the consolidated assets of WES), as well as all equity interests owned by WGP. Borrowings under the WGP RCF bear interest at LIBOR (with a floor of 0%), plus applicable margins ranging from 2.00% to 2.75% depending on WGP’s consolidated leverage ratio, or at a base rate equal to the greatest of (i) the prime rate, (ii) the federal funds rate plus 0.50%, or (iii) LIBOR plus 1.00%, in each case plus applicable margins ranging from 1.00% to 1.75% based upon WGP’s consolidated leverage ratio. At September 30, ~~2016,~~2017, WGP had outstanding borrowings under its RCF of $28 million at an interest rate of ~~2.53%,~~3.24% and had available borrowing capacity of $222 ~~million, and was in compliance with all related covenants.~~

In October 2016, WES completed a public offering of $200 million aggregate principal amount of 5.450% Senior Notes due April 2044. Net proceeds were used to repay amounts outstanding under the WES RCF and the remaining proceeds will be used for general partnership purposes, including capital expenditures.

million.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

~~Capital Lease Obligations~~Construction of a floating production, storage and offloading unit (FPSO) for the Company’s Tweneboa/Enyenra/Ntomme (TEN) field operations in Ghana commenced in 2013. The Company recognized an asset and related obligation for its approximate 19% nonoperated working interest share during the construction period. Upon completion of the construction during the third quarter of 2016, the Company reported the asset and related obligation as a capital lease of $225 million for the Company’s share of the fair value of the FPSO. The FPSO lease provides for an initial term of 10 years with annual renewal periods for an additional 10 years, annual purchase options that decrease over time, and no residual value guarantees. The capital lease asset will be depreciated over the estimated proved reserves of the TEN field using the unit-of-production method, with the associated depreciation included in depreciation, depletion, and amortization (DD&A) in the Company’s Consolidated Statement of Income. The capital lease obligation will be accreted to the present value of the minimum lease payments using the effective interest method. The Company will make the first payment under the FPSO capital lease in the fourth quarter of 2016.

~~At September 30, 2016, future minimum lease payments due under capital leases were:~~

millions
2016 $ 16
2017 42
2018 42
2019 42
2020 42
Remaining years 433
Total future minimum lease payments $ 617
Less portion representing imputed interest 372
Capital lease obligations $ 245

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

Three Months Ended
September 30, Nine Months Ended
September 30,
millions 2016 2015 2016 2015
Debt and other $ 251
$ 245
$ 768
$ 743
Capitalized interest (31 ) (46 ) (111 ) (127 )
Total interest expense $ 220
$ 199
$ 657
$ 616

~~Table of Contents~~

A~~NADARKO 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 September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2016			2015			2016			2015			2017			2016			2017			2016
Income tax expense (benefit)	$	(260	)	$	(917	)	$	(957	)	$	(2,232	)
Current income tax expense (benefit)													$	430		$	64		$	670		$	212
Deferred income tax expense (benefit)													(855		)	(324		)	(1,036		)	(1,169		)
Total income tax expense (benefit)													$	(425	)	$	(260	)	$	(366	)	$	(957	)
Income (loss) before income taxes	(1,007		)	(3,077		)	(3,313		)	(7,520		)	(1,066		)	(1,007		)	(1,616		)	(3,313		)
Effective tax rate	26		%	30		%	29		%	30		%	40		%	26		%	23		%	29		%

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 nine months ended September 30, ~~2016~~2017 and ~~2015. As a result, items that ordinarily~~2016. The increase orfrom the 35% U.S. federal statutory rate for the three months ended September 30, 2017, was primarily attributable to the following:

tax impact from foreign operations

income attributable to noncontrolling interests

federal manufacturing deduction

These increases from the 35% U.S. federal statutory rate were partially offset by the following:

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

net changes in uncertain tax positions

The decrease from the 35% U.S. federal statutory rate for the nine months ended September 30, 2017, was primarily attributable to the following:

non-deductible Algerian exceptional profits tax for Algerian income tax purposes

tax impact from foreign operations

net changes in uncertain tax positions

These decreases from the 35% U.S. federal statutory rate ~~will have~~were partially offset by the ~~opposite effect.~~ following:

•income attributable to noncontrolling interests

•federal manufacturing deduction

The decrease from the 35% U.S. federal statutory rate for the three and nine months ended September 30, 2016, was primarily attributable to ~~the following decreases:~~

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

~~tax impact from foreign operations~~

~~non-deductible goodwill related to divestitures~~

~~adjustments to deferred tax balances~~

~~net changes in uncertain tax positions~~

~~These decreases were partially offset by the following increases:~~

•~~state taxes, net of federal benefit~~

•~~income attributable to noncontrolling interest~~

~~The decrease from the 35% U.S. federal statutory rate for the three and nine months ended September 30, 2015, was primarily attributable to~~ non-deductible Algerian exceptional profits tax for Algerian income tax purposes, ~~and~~ the tax impact from foreign ~~operations.~~

operations, non-deductible goodwill related to divestitures, and net changes in uncertain tax positions. These decreases were partially offset by increases to state taxes, net of federal benefit, and income attributable to noncontrolling interests. See Note 14—Noncontrolling Interests.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10. ~~Conveyance of Future Hard Minerals Royalty Revenues~~

During the first quarter of 2016, the Company conveyed a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party for $413 million, net of transaction costs. Such conveyance entitles the third party to receive up to $553 million in future royalty revenue over a period of not less than 10 years and not greater than 15 years. Additionally, such third party is entitled to receive 3% of the aggregate royalties earned during the first 10 years between $800 million and $900 million and 4% of the aggregate royalties earned during the first 10 years that exceed $900 million. Generally, such third party relies solely on the royalty payments to recover its investment and, as such, has the risk of the royalties not being sufficient to recover its investment over the term of the conveyance.

Proceeds from this transaction were accounted for as deferred revenues and are included in accrued expenses and other long-term liabilities on the Company’s Consolidated Balance Sheet. The deferred revenues will be amortized to other revenues, included in gains (losses) on divestitures and other, net on a unit-of-revenue basis over the term of the agreement. Net proceeds received from the third party were reported in financing activities on the Company’s Consolidated Statement of Cash Flows. Semi-annual payments to the third party are scheduled on March 1 and September 1 of each year through March 1, 2026. The specified future amounts that the Company expects to pay and the payment timing are subject to change based upon the actual royalties received by the Company during the term of the conveyance. Royalties received by Anadarko under this agreement are reported in operating activities on the Company’s Consolidated Statement of Cash Flows. The semi-annual payments to the third party, up to the aggregate amount of the $413 million net proceeds the Company received for the conveyance in the first quarter of 2016, are reported in financing activities on the Company’s Consolidated Statement of Cash Flows. Any additional payments to the third party are reported in operating activities on the Company’s Consolidated Statement of Cash Flows to offset the royalties received.

During the nine months ended September 30, 2016, the Company amortized $27 million of deferred revenues as a result of this agreement. The Company made the first semi-annual payment of $25 million for royalties in September 2016. The following summarizes the remaining amounts that the Company expects to pay, prior to the potential 3% to 4% of any excess described above:

millions
2017 $ 50
2018 50
2019 52
2020 56
2021 57
Later years 263
Total $ 528

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~11.~~ Contingencies

Litigation ~~The following is a discussion of any~~There are no material developments in previously reported contingencies ~~and~~nor are there any other material matters that have arisen since the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2015~~.

~~Deepwater Horizon Events~~ ~~In April 2010, the Macondo well in the Gulf of Mexico blew out and an explosion occurred on the~~ ~~Deepwater Horizon~~ drilling rig, resulting in an oil spill. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% nonoperated interest. In October 2011, the Company and BP entered into a settlement agreement relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company is fully indemnified by BP against all claims and damages arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and assessment costs, and any claims arising under the Operating Agreement with BP.

Numerous Deepwater Horizon event-related civil lawsuits were filed against BP and other parties, including the Company. Generally, the plaintiffs sought actual damages, punitive damages, declaratory judgment, and/or injunctive relief. This litigation was consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the U.S. District Court for the Eastern District of Louisiana in New Orleans, Louisiana (Louisiana District Court).

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

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

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~12.~~11. Restructuring Charges

In the first quarter of 2016, the Company initiated a workforce reduction program to align the size and composition of its workforce with its expected future operating and capital plans. Employee notifications related to the workforce reduction program were completed by June 30, 2016. ~~All~~The Company recognized restructuring charges ~~will be~~included in G&A in the Company’s Consolidated Statements of Income of $112 million during the three months ended September 30, 2016, and $363 million during the nine months ended September 30, 2016. All material restructuring charges were recognized in 2016, with the exception of ~~approximately $17 million of~~settlement expense ~~for retirement benefits~~ expected to be recognized ~~in 2017. The following summarizes~~during 2017 for lump-sum payments to terminated participants. During the ~~total expected restructuring charges and the amounts expensed during the three and~~ nine months ended September 30, ~~2016, which~~2017, the Company recognized restructuring charges of $20 million, primarily related to settlement expense. Settlement expenses for the remainder of 2017 are ~~included in general and administrative expenses in the Company’s Consolidated Statements of Income:~~

millions Total Expected Costs Three Months Ended
September 30, 2016 Nine Months Ended September 30, 2016
Costs by category
Cash severance $ 154
$ 5
$ 151
Retirement benefits ⁽¹⁾
219
102
178
Share-based compensation 37
5
34
Total $ 410
$ 112
$ 363


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

~~The following summarizes the changes in the cash severance-related liability included in accounts payable on the Company’s Consolidated Balance Sheet:~~

millions 2016
Balance at January 1 $ —
Accruals 151
Payments (141 )
Balance at September 30 $ 10
not expected to be material.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~13.~~12. Pension Plans and Other Postretirement Benefits

The Company has contributory and non-contributory defined-benefit pension plans, which include both qualified and supplemental plans. The Company also provides certain health care and life insurance benefits for certain retired employees. Retiree health care benefits are funded by contributions from the retiree and, in certain circumstances, contributions from the Company. The Company’s retiree life insurance plan is noncontributory. The following summarizes the Company’s pension and other postretirement benefit cost:


	Pension Benefits						Other Benefits					Pension Benefits						Other Benefits
millions	2016			2015			2016			2015		2017			2016			2017			2016
Three Months Ended September 30
Service cost	$	24		$	30		$	1		$	3	$	22		$	24		$	—		$	1
Interest cost	24			25			3			3		21			24			3			3
Expected return on plan assets	(24		)	(27		)	—			—
Expected (return) loss on plan assets												(21		)	(24		)	—			—
Amortization of net actuarial loss (gain)	12			13			—			—		7			12			—			—
Amortization of net prior service cost (credit)	—			—			(6		)	1		(1		)	—			(6		)	(6		)
Settlement expense(1)	102			—			—			—		22			102			—			—
Net periodic benefit cost	$	138		$	41		$	(2	)	$	7	$	50		$	138		$	(3	)	$	(2	)

Nine Months Ended September 30
Service cost	$	73		$	89		$	2		$	8	$	64		$	73		$	1		$	2
Interest cost	73			76			9			11		63			73			9			9
Expected return on plan assets	(75		)	(82		)	—			—
Expected (return) loss on plan assets												(63		)	(75		)	—			—
Amortization of net actuarial loss (gain)	30			39			—			—		20			30			—			—
Amortization of net prior service cost (credit)	—			—			(18		)	2		(1		)	—			(18		)	(18		)
Settlement expense(1)	126			—			—			—		80			126			—			—
Termination benefits expense(1)	44			—			—			—		4			44			—			—
Curtailment expense(1)	8			—			—			—		—			8			—			—
Net periodic benefit cost	$	279		$	122		$	(7	)	$	21	$	167		$	279		$	(8	)	$	(7	)


⁽¹⁾	Settlement expense, termination benefits expense, and curtailment expense for 2016 relate to the workforce reduction program. See Note 11—Restructuring Charges.

The ~~Company’s workforce reduction program resulted in remeasurements of its~~Company contributed $167 million to funded pension ~~and other postretirement plans during 2016. The remeasurements of the benefit obligation and plan assets resulted in a net liability increase of $327 million for the pension benefit~~ plans and ~~$24~~$84 million ~~for the other postretirement benefit plans, with a corresponding decrease in other comprehensive income.~~

~~At December 31, 2015, total expected contributions related~~ to unfunded pension plans ~~were $25 million for 2016. The Company~~during the nine months ended September 30, 2017, and expects to contribute an additional ~~$82~~$3 million ~~in 2016 and $23 million in 2017~~ to unfunded pension plans ~~primarily related to the workforce reduction program. See~~ ~~Note 12—Restructuring Charges~~.during 2017.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~14.~~13. Stockholders’ Equity

~~Common Stock Issuance~~Earnings Per Share In September 2016, the Company completed a public offering of 40.5 million shares of its common stock at a price of $53.23 per share. Net proceeds of $2.16 billion from this equity issuance will primarily be used to fund the acquisition of certain Gulf of Mexico assets, which is expected to close in the fourth quarter of 2016. The remaining net proceeds will be used for general corporate purposes. See ~~Note 3—Acquisitions, Divestitures, and Assets Held for Sale~~.

~~Earnings per Share (EPS)~~The Company’s basic ~~EPS~~earnings per share (EPS) is computed based on the average number of shares of common stock outstanding for the period and includes the effect of any participating securities and TEUs as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units, TEUs, and WES Series A Preferred units, if the inclusion of these items is dilutive.

The following provides a reconciliation between basic and diluted ~~earnings per share~~EPS attributable to common stockholders:


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
millions except per-share amounts	2016			2015			2016			2015			2017			2016			2017			2016
Net income (loss)
Net income (loss) attributable to common stockholders	$	(830	)	$	(2,235	)	$	(2,556	)	$	(5,442	)	$	(699	)	$	(830	)	$	(1,432	)	$	(2,556	)
Income (loss) effect of TEUs	(2		)	(3		)	(5		)	(3		)	(2		)	(2		)	(6		)	(5		)
Less distributions on participating securities	1			1			1			4			—			1			—			1
Basic	$	(833	)	$	(2,239	)	$	(2,562	)	$	(5,449	)	$	(701	)	$	(833	)	$	(1,438	)	$	(2,562	)
Income (loss) effect of TEUs	—			—			(1		)	—			—			—			(1		)	(1		)
Diluted	$	(833	)	$	(2,239	)	$	(2,563	)	$	(5,449	)	$	(701	)	$	(833	)	$	(1,439	)	$	(2,563	)
Shares
Average number of common shares outstanding—basic	517			508			512			508			553			517			552			512
Average number of common shares outstanding—diluted	517			508			512			508			553			517			552			512
Excluded due to anti-dilutive effect	11			10			11			11			11			11			11			11
Net income (loss) per common share
Basic	$	(1.61	)	$	(4.41	)	$	(5.00	)	$	(10.73	)	$	(1.27	)	$	(1.61	)	$	(2.60	)	$	(5.00	)
Diluted	$	(1.61	)	$	(4.41	)	$	(5.00	)	$	(10.73	)	$	(1.27	)	$	(1.61	)	$	(2.61	)	$	(5.00	)

Common Stock Repurchase Program In September 2017, the Company announced a $2.5 billion share-repurchase program under which shares of the Company’s common stock may be repurchased either in the open market or through private transactions. The program is authorized to extend through the end of 2018. In October 2017, Anadarko entered into an accelerated share-repurchase agreement (ASR Agreement) with an investment bank (Bank) to repurchase $1.0 billion of the Company’s common stock as part of the share-repurchase program. Under the terms of the ASR Agreement, the Company paid $1.0 billion in cash and received an initial delivery of shares of the Company’s common stock. At the conclusion of the term of the ASR Agreement, the Company and the Bank will enter into a final share settlement with the settlement price determined by applying a percentage discount to the volume-weighted average price of the shares during the term. The ASR Agreement is subject to customary adjustment and termination provisions, and final settlement is expected to occur prior to year end. All of the shares acquired by Anadarko under the ASR Agreement will be classified as treasury stock.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~15. Accumulated Other Comprehensive Income (Loss)~~

~~The following summarizes the after-tax changes in the balances of accumulated other comprehensive income (loss):~~

millions
Interest-rate
Derivatives
Previously
Subject to Hedge
Accounting

Pension and Other Postretirement
Plans
Total
Balance at December 31, 2015 $ (42 ) $ (341 ) $ (383 )
Other comprehensive income (loss), before reclassifications —
(219 ) (219 )
Reclassifications to Consolidated Statement of Income 4
80
84
Balance at September 30, 2016 $ (38 ) $ (480 ) $ (518 )

~~16.~~14. Noncontrolling Interests

WES ~~a publicly traded consolidated subsidiary,~~ is a limited partnership formed by Anadarko to acquire, own, develop, and operate midstream assets. During ~~the first quarter of~~ 2016, WES issued 1422 million Series A Preferred units to private investors for net proceeds of ~~$440~~$687 million and issued 1.3 million common units to the Company. Proceeds from these issuances were primarily used to acquire interests in Springfield Pipeline LLC from the Company. ~~During~~Pursuant to an agreement between WES and the ~~second quarter~~holders of ~~2016, WES issued an additional eight million~~the Series A Preferred units, ~~to private investors, pursuant to~~50% of the ~~full exercise of an option granted in connection with~~Series A Preferred units converted into WES common units on a one-for-one basis on March 1, 2017, and the ~~initial issuance, and raised net proceeds of $247 million.~~remaining Series A Preferred units converted on May 2, 2017.

WES Class C units issued to Anadarko will convert into WES common units on a one-for-one basis on the conversion date, which was extended in February 2017 from December 31, 2017, to March 1, 2020. The Class C units receive quarterly distributions in the form of additional Class C units until the ~~end of 2017,~~March 1, 2020 conversion date unless WES elects to convert the units to common units earlier or Anadarko elects to extend the conversion date. WES distributed ~~749~~620 thousand Class C units to Anadarko during the nine months ended September 30, ~~2016,~~2017, and ~~498~~946 thousand Class C units to Anadarko during ~~2015. During 2015, WES issued approximately 874 thousand common units to the public for net proceeds of $57 million.~~2016.

WGP ~~a publicly traded consolidated subsidiary,~~ is a limited partnership formed by Anadarko to own ~~partnership~~ interests in WES. During ~~the three months ended June 30,~~ 2016, Anadarko sold 12.5 million ~~of its~~ WGP common units to the public for net proceeds of $476 million.At September 30, ~~2016,~~2017, Anadarko’s ownership interest in WGP consisted of an 81.6% limited partner interest and the entire non-economic general partner interest. The remaining 18.4% limited partner interest in WGP was owned by the public.

At September 30, ~~2016,~~2017, WGP’s ownership interest in WES consisted of a ~~30.0%~~29.8% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At September 30, ~~2016,~~2017, Anadarko also owned ~~an 8.5%~~a 9.0% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining ~~60.0%~~59.7% limited partner interest in WES was owned by the public.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~17.~~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, WES, and ~~WES.~~all of their consolidated subsidiaries. See Note ~~16—~~14—Noncontrolling Interests for additional information on WGP and WES.

Assets and Liabilities of VIEs The assets of WGP, WES, and ~~WES~~their subsidiaries 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, WES, and ~~WES~~their subsidiaries 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 September 30, ~~2016,~~2017, and December 31, ~~2015,~~2016, including any borrowings under the WES RCF, is recourse to WES’s general partner, which in turn has been indemnified in certain circumstances by certain wholly owned subsidiaries of the Company for such liabilities. All outstanding debt for WGP at September 30, ~~2016,~~2017, and December 31, ~~2015,~~2016, including any borrowings under the WGP RCF, is recourse to WGP’s general partner, which is a wholly owned subsidiary of the Company. See Note 8—Debt ~~and Interest Expense~~ for additional information on WGP and WES long-term debt balances.

VIE Financing WGP’s sources of liquidity include borrowings under its RCF and distributions from WES. WES’s sources of liquidity include cash and cash equivalents, cash flows generated from operations, interest income from a note receivable from Anadarko as discussed below, borrowings under its RCF, the issuance of additional partnership units, or debt offerings. See Note 8—Debt ~~and Interest Expense~~ and Note ~~16—~~14—Noncontrolling Interests for additional information on WGP and WES financing activity.

Financial Support Provided to VIEs Concurrent with the closing of its May 2008 ~~initial public offering,~~IPO, WES loaned the Company $260 million in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The related interest income for WES was $5 million for each of the three months ended September 30, ~~2016~~2017 and ~~2015,~~2016, and $13 million for each of the nine months ended September 30, ~~2016~~2017 and ~~2015.~~2016. The note receivable and related interest income are eliminated in consolidation.

In March 2015, WES acquired the Company’s interest in ~~Delaware Basin JV Gathering LLC (DBJV).~~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 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. Thethe estimated net present value of ~~this~~the obligation ~~was $16 million~~ at ~~September 30, 2016, and $189 million at December~~March 31, 2015. 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 and an increase 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~~its contracts, Anadarko has commodity price swap agreements in place with WES expiring on December 31, ~~2016.~~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 ~~$35 million~~ capital contribution from Anadarko ~~for the nine months ended September 30, 2016, and a capital contribution~~ of $8$47 million for the nine months ended September 30, ~~2015.~~2017, and $35 million for the nine months ended September 30, 2016.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~18.~~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:


	Nine Months Ended September 30,						Nine Months Ended September 30,
millions	2016			2015			2017			2016
Cash paid (received)
Interest, net of amounts capitalized⁽¹⁾	$	735		$	1,916		$	764		$	735
Income taxes, net of refunds⁽²⁾⁽¹⁾	(878		)	(163		)	169			(878		)
Non-cash investing activities
Fair value of properties and equipment from non-cash transactions	$	2		$	156		$	619		$	2
Asset retirement cost additions	85			139			228			85
Accruals of property, plant, and equipment	454			858			786			454
Net liabilities assumed (divested) in acquisitions and divestitures	(39		)	(84		)	(115		)	(39		)
Non-cash investing and financing activities
Capital lease obligation⁽³⁾⁽²⁾	$	10		$	—		$	—		$	10
Floating production, storage, and offloading unit construction period obligation⁽³⁾	11			51
FPSO construction period obligation ⁽²⁾							—			11
Deferred drilling lease liability	3			—			14			3


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


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


⁽³⁾⁽²⁾	Upon completion of the FPSO ~~during~~in the third quarter of 2016, the Company reported the construction period obligation as a capital lease obligation ~~and recorded a fair-value adjustment. See~~ ~~Note 8—Debt and Interest Expense~~. based on the fair value of the FPSO.

~~19.~~17. Segment Information

Anadarko’s business segments are separately managed due to distinct operational ~~differences and unique technology, distribution, and marketing requirements. The Company’s~~ differences. Anadarko has previously presented three reporting segments ~~are oil~~in its quarterly and ~~gas exploration~~annual filings: Oil and ~~production, midstream,~~Gas Exploration and ~~marketing.~~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 no longer identifies marketing activities as a separate reporting segment and has two reporting segments, Exploration and Production and Midstream, which include their respective marketing results. The ~~oil~~Company has reclassified prior period amounts to conform to the current period’s presentation.

The Exploration and ~~gas exploration and production~~Production reporting segment explores for, produces, and ~~produces~~sells oil, ~~condensate,~~ natural gas, and NGLs and plans for the development and operation of the Company’s LNG project in Mozambique. The ~~midstream~~Midstream reporting segment engages in gathering, processing, treating, and transporting Anadarko and third-party oil, ~~condensate,~~ natural-gas, and NGLs ~~production.~~production as well as gathering and disposal of produced water. The ~~midstream~~Midstream reporting segment consists of two operating segments, WES and ~~other midstream,~~Other Midstream, which are aggregated into one reporting segment due to similar financial and operating characteristics. ~~The marketing segment sells much of Anadarko’s oil, condensate, natural-gas, and NGLs production as well as third-party purchased volumes.~~

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes; interest expense; DD&A; exploration expense; gains (losses) on divestitures, net; ~~exploration expense; DD&A;~~ impairments; ~~interest expense;~~ total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives; and certain items not related to the Company’s normal operations, less net income (loss) attributable to noncontrolling interests. During the periods presented, items not related to the Company’s normal operations included restructuring charges related to the workforce reduction program included in ~~general and administrative expenses, Deepwater Horizon settlement and related costs included in other operating expenses,~~G&A, loss on early extinguishment of debt, ~~Tronox-related contingent loss,~~ and certain other nonoperating items included in other (income) expense, net.

The Company’s definition of Adjusted EBITDAX excludes gains (losses) on divestitures, net and exploration expense as they are not indicators of operating efficiency for a given reporting period. ~~However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly,~~ DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Finally, net income (loss) attributable to noncontrolling interests is excluded from the Company’s measure of Adjusted EBITDAX, because it represents earnings that are not attributable to the Company’s common stockholders.

Management believes 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 September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
millions	2016			2015			2016			2015			2017			2016			2017			2016
Income (loss) before income taxes	$	(1,007	)	$	(3,077	)	$	(3,313	)	$	(7,520	)	$	(1,066	)	$	(1,007	)	$	(1,616	)	$	(3,313	)
Interest expense													230			220			680			657
DD&A													1,083			1,069			3,235			3,202
Exploration expense													751			304			2,371			506
(Gains) losses on divestitures, net	414			578			516			1,003			194			414			(815		)	516
Exploration expense	304			1,074			506			2,260
DD&A	1,069			1,111			3,202			3,581
Impairments	27			758			61			3,571			—			27			383			61
Interest expense	220			199			657			616
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	88			360			863			374			98			88			(12		)	863
Restructuring charges	112			—			363			—			3			112			20			363
Other operating expense	—			—			1			4			—			—			—			1
Loss on early extinguishment of debt	—			—			124			—			—			—			2			124
Tronox-related contingent loss	—			—			—			5
Certain other nonoperating items	—			—			(56		)	22			—			—			—			(56		)
Less net income (loss) attributable to noncontrolling interests	83			75			200			154			58			83			182			200
Consolidated Adjusted EBITDAX	$	1,144		$	928		$	2,724		$	3,762		$	1,235		$	1,144		$	4,066		$	2,724

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

Information presented below as “Other and Intersegment Eliminations” includes corporate costs, margin on sales of third-party commodity purchases, deficiency fees, results from hard-minerals royalties, ~~and~~ net cash from settlement of commodity ~~derivatives.~~derivatives, and net income (loss) attributable to noncontrolling interests. The following summarizes selected financial information for Anadarko’s reporting segments:


millions	Oil and Gas Exploration & Production		Midstream		Marketing			Other and Intersegment Eliminations			Total			Exploration & Production			Midstream		Other and Intersegment Eliminations			Total
Three Months Ended September 30, 2017
Sales revenues														$	2,101		$	496	$	13		$	2,610
Intersegment revenues														—			158		(158		)	—
Other(1)														6			39		35			80
Total revenues and other ⁽¹⁾⁽²⁾														2,107			693		(110		)	2,690
Operating costs and expenses ⁽²⁾⁽³⁾														959			391		84			1,434
Net cash from settlement of commodity derivatives														—			—		(16		)	(16		)
Other (income) expense, net														—			—		(21		)	(21		)
Net income (loss) attributable to noncontrolling interests(1)														—			—		58			58
Total expenses and other														959			391		105			1,455
Adjusted EBITDAX														$	1,148		$	302	$	(215	)	$	1,235

Three Months Ended September 30, 2016
Sales revenues	$	1,109	$	174	$	968		$	—		$	2,251		$	1,901		$	329	$	21		$	2,251
Intersegment revenues	717		370		(841		)	(246		)	—			—			227		(227		)	—
Other(1)	—		—		—			56			56			(2		)	35		23			56
Total revenues and other ⁽¹⁾⁽²⁾	1,826		544		127			(190		)	2,307			1,899			591		(183		)	2,307
Operating costs and expenses ⁽²⁾⁽³⁾	807		273		173			(79		)	1,174			877			284		13			1,174
Net cash from settlement of commodity derivatives	—		—		—			(63		)	(63		)	—			—		(63		)	(63		)
Other (income) expense, net	—		—		—			(31		)	(31		)	—			—		(31		)	(31		)
Net income (loss) attributable to noncontrolling interests(1)	—		83		—			—			83			—			—		83			83
Total expenses and other	807		356		173			(173		)	1,163			877			284		2			1,163
Adjusted EBITDAX	$	1,019	$	188	$	(46	)	$	(17	)	$	1,144		$	1,022		$	307	$	(185	)	$	1,144

Three Months Ended September 30, 2015
Sales revenues	$	1,067	$	195	$	968		$	—		$	2,230
Intersegment revenues	750		315		(832		)	(233		)	—
Other(1)	—		—		—			36			36
Total revenues and other ⁽¹⁾⁽²⁾	1,817		510		136			(197		)	2,266
Operating costs and expenses ⁽²⁾⁽³⁾	840		287		181			(14		)	1,294
Net cash from settlement of commodity derivatives	—		—		—			(79		)	(79		)
Other (income) expense, net	—		—		—			47			47
Net income (loss) attributable to noncontrolling interests(1)	—		75		—			—			75
Total expenses and other	840		362		181			(46		)	1,337
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—		—		(1		)	—			(1		)
Adjusted EBITDAX	$	977	$	148	$	(46	)	$	(151	)	$	928

__________________________________________________________________


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


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


⁽²⁾⁽³⁾	Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating ~~expense~~expenses since these expenses are excluded from Adjusted EBITDAX.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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


millions	Oil and Gas Exploration & Production		Midstream		Marketing			Other and Intersegment Eliminations			Total			Exploration & Production			Midstream		Other and Intersegment Eliminations			Total
Nine Months Ended September 30, 2016
Nine Months Ended September 30, 2017
Sales revenues	$	2,853	$	440	$	2,577		$	—		$	5,870		$	6,510		$	1,346	$	71		$	7,927
Intersegment revenues	1,885		1,012		(2,180		)	(717		)	—			—			507		(507		)	—
Other	—		—		—			128			128
Total revenues and other ⁽¹⁾	4,738		1,452		397			(589		)	5,998
Operating costs and expenses ⁽²⁾	2,370		675		526			(233		)	3,338
Other ⁽¹⁾														16			126		95			237
Total revenues and other ⁽²⁾														6,526			1,979		(341		)	8,164
Operating costs and expenses ⁽³⁾														2,687			1,063		230			3,980
Net cash from settlement of commodity derivatives	—		—		—			(226		)	(226		)	—			—		(23		)	(23		)
Other (income) expense, net ⁽³⁾	—		—		—			(30		)	(30		)
Net income (loss) attributable to noncontrolling interests	—		200		—			—			200
Other (income) expense, net														—			—		(43		)	(43		)
Net income (loss) attributable to noncontrolling interests⁽¹⁾														—			—		182			182
Total expenses and other	2,370		875		526			(489		)	3,282			2,687			1,063		346			4,096
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—		—		8			—			8			—			—		(2		)	(2		)
Adjusted EBITDAX	$	2,368	$	577	$	(121	)	$	(100	)	$	2,724		$	3,839		$	916	$	(689	)	$	4,066

Nine Months Ended September 30, 2015
Nine Months Ended September 30, 2016
Sales revenues	$	3,493	$	560	$	3,399		$	—		$	7,452		$	4,975		$	823	$	72		$	5,870
Intersegment revenues	2,752		920		(2,977		)	(695		)	—			—			671		(671		)	—
Other	—		—		—			196			196
Total revenues and other ⁽¹⁾	6,245		1,480		422			(499		)	7,648
Operating costs and expenses ⁽²⁾	2,674		761		571			(110		)	3,896
Other ⁽¹⁾														(17		)	76		69			128
Total revenues and other ⁽²⁾														4,958			1,570		(530		)	5,998
Operating costs and expenses ⁽³⁾														2,586			714		38			3,338
Net cash from settlement of commodity derivatives	—		—		—			(251		)	(251		)	—			—		(226		)	(226		)
Other (income) expense, net ⁽³⁾	—		—		—			87			87
Net income (loss) attributable to noncontrolling interests	—		154		—			—			154
Other (income) expense, net														—			—		(30		)	(30		)
Net income (loss) attributable to noncontrolling interests ⁽¹⁾														—			—		200			200
Total expenses and other	2,674		915		571			(274		)	3,886			2,586			714		(18		)	3,282
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement														—			—		8			8
Adjusted EBITDAX	$	3,571	$	565	$	(149	)	$	(225	)	$	3,762		$	2,372		$	856	$	(504	)	$	2,724

__________________________________________________________________


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


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


⁽²⁾⁽³⁾	Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating ~~expense~~expenses since these expenses are excluded from Adjusted EBITDAX.


⁽³⁾	~~Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.~~

~~Table of Contents~~

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

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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

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

the Company’s assumptions about energy markets

production and sales volume levels

levels of oil, natural-gas, and ~~natural-gas liquids (NGLs)~~NGLs reserves

operating results

competitive conditions

technology

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

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

volatility in the commodity-futures market

weather

inflation

availability of goods and services, including unexpected changes in costs

drilling and other operational risks

processing volumes and pipeline throughput

general economic conditions, nationally, internationally, or in the jurisdictions in which the Company is, or in the future may be, doing business

the Company’s inability to timely obtain or maintain permits or other governmental approvals, including those necessary for drilling and/or development projects

legislative or regulatory changes, including changes relating to hydraulic fracturing; retroactive royalty or production tax regimes; deepwater drilling and permitting regulations; derivatives reform; changes in state, federal, and foreign income taxes; environmental regulation, including regulations related to climate change; environmental risks; and liability under international, provincial, federal, regional, state, ~~foreign,~~tribal, local, and ~~local~~foreign environmental laws and regulations

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

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

~~Table of Contents~~

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

the Company’s ability to successfully monetize select assets, repurchase shares of common stock, repay or refinance its debt, and the impact of changes in the Company’s credit ratings

~~the Company’s ability to close the acquisition of certain Gulf of Mexico assets~~

~~risks and liabilities~~uncertainties associated with acquired properties orand businesses

disruptions in international oil ~~NGLs,~~ and ~~condensate~~NGLs cargo shipping activities

physical, digital, internal, and external security breaches

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

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

other factors discussed below and elsewhere in “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates” included in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2015,~~2016, this Form 10-Q, and in the Company’s other public filings, press releases, and discussions with Company management

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Form 10-Q in Part I, Item 1; the information set forth in the Risk Factors under Part II, Item 1A; the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Part II, Item 8 of the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2015;~~2016; and the information set forth in the Risk Factors under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2015.~~2016.

~~OUTLOOK~~MANAGEMENT OVERVIEW

Anadarko’s strategy is to explore for, develop and commercialize resources globally; ensure health, safety and environmental excellence; focus on financial discipline, flexibility and value creation; and demonstrate the Company’s core values in all its business activities. The Company’s revenues, operating results, cash flows from operations, capital spending, and future growth rates are highly ~~dependent on the global commodity-price markets,~~influenced by commodity prices, which affect the value the Company receives from its sales of oil, natural gas, and NGLs. ~~During 2015,~~

To effectively manage the ~~oil~~influence of potential commodity-price volatility, in 2017, Anadarko continues to optimize and ~~natural-gas industry experienced a significant decrease~~further concentrate its portfolio on higher-return, oil-levered opportunities in ~~commodity prices, which continued into 2016, driven by a global supply/demand imbalance for oil~~areas where it possesses both scale and ~~an oversupply of natural gas~~competitive advantages, namely the Delaware and DJ basins in the ~~United States.~~

~~The following actions in 2016 have enabled~~U.S. onshore and the ~~Company to manage through this lower commodity-price environment:~~

~~reducing capital expenditures by 50% from the prior year~~

~~enhancing operational efficiencies~~

continuing an active monetization program by closing monetizations totaling $2.8 billion through September 30, 2016, and entering into agreements for an additional $1.2 billion, which are expected to close in the fourth quarter of 2016

~~improving the Company’s cost structure by approximately $800 million annually after 2016 through a dividend decrease and a workforce reduction program~~

~~retiring approximately $3.0 billion of near-term maturities with proceeds from debt issued during the first quarter of 2016~~

In addition, in September 2016 the Company entered into an agreement to acquire certain assets in the Gulf of Mexico for $2.0 billion. The acquisition is expected to close in the fourth quarter of 2016 and is subject to customary closing conditions. The acquisition of these assets will expand Anadarko’s operated infrastructure in the Gulf of Mexico, doubling the Company’s ownership in the Lucius development to approximately 49% and increasing its oil production from thedeepwater Gulf of Mexico. ~~The acquired~~Anadarko’s deepwater Gulf of Mexico assets are expected to generate substantial cash ~~flow~~flows over the next five years at current strip ~~prices, enabling accelerated investment in Anadarko’s Delaware and DJ basin assets.~~prices. The Company ~~completed a public offering of 40.5 million shares of its common stock for net proceeds of $2.16 billion~~plans to ~~fund~~use the ~~acquisition of~~cash flows from the Gulf of Mexico ~~assets. The remaining net proceeds will be used for general corporate purposes.~~

~~Table of Contents~~

~~The Company has increased the estimate for~~as well as from its ~~2016 capital spending from a range of $3.1 billion~~international producing assets to $3.3 billion to a range of $3.3 billion to $3.5 billion, including approximately $490 million to $530 million for Western Gas Partners, LP (WES), a publicly traded consolidated subsidiary, and excluding any acquisitions made by Anadarko or WES. The increase primarily reflects increasedfund activity in the Company’s unconventional assets in the U.S. onshore. Much of the 2017 operational and investment focus is preparing the Delaware basin for development with increased operatorship and ~~DJ basins.~~infrastructure to facilitate long-term growth and value. The Company ~~has currently allocated approximately 65%~~ended the third quarter of ~~its 2016 capital spending budget~~2017 with 13 operated drilling rigs in the Delaware basin and 6 operated drilling rigs in the DJ basin, which compares to ~~development activities, 15% to exploration activities,~~9 operated drilling rigs in the Delaware basin and ~~20% to gathering and processing activities and other business activities. The Company currently expects its 2016 capital spending by area to be approximately 40% for~~5 operated drilling rigs in the ~~U.S. onshore region and Alaska, 20% for~~DJ basin at year end 2016. In the deepwater Gulf of Mexico, ~~20% for Midstream and other (including WES), and 20% for International.~~Anadarko has three floating rigs drilling with a focus on leveraging the Company’s expansive infrastructure position.

~~Liquidity~~ AsIn September 2017, the Company announced a $2.5 billion share-repurchase program under which shares of ~~September 30, 2016, Anadarko had $4.0~~the Company’s common stock may be repurchased either in the open market or through private transactions. The program is authorized to extend through the end of 2018. In October 2017, the Company entered into an agreement to complete $1.0 billion of ~~cash on hand plus $5.0 billion~~the share-repurchase program prior to the end of ~~borrowing capacity under its revolving credit facilities. Cash on hand includes net proceeds of $2.16 billion from~~2017.

Following a home explosion in Firestone, Colorado in April 2017, the ~~Company’s September 2016 public offering of 40.5 million shares of its common stock. Additionally, Anadarko has entered into divestiture agreements that are expected~~Company took precautionary measures to ~~close~~shut in all operated vertical wells in the ~~fourth~~DJ basin to conduct additional inspections. It subsequently tested and permanently plugged, abandoned, and capped all one-inch return lines associated with these wells. In May 2017, the Colorado Oil & Gas Conservation Commission (COGCC) issued a two-phase Notice to Operators (NTO) requiring all operators to inventory and integrity test existing flowlines within 1,000 feet of a building unit and abandon all inactive flowlines in such areas. During the third quarter, ~~for approximately $1.2 billion. Prior to year-end 2016, Anadarko plans to use approximately $1.8 billion of its cash on hand for the acquisition of certain Gulf of Mexico assets. In October 2016,~~ the Company provided notice of its intent to redeem its remaining $750 million of 6.375% Senior Notes due September 2017 prior to year end. Anadarko believes that its cash on hand, anticipated operating cash flows, and proceeds from expected future asset monetizations will be sufficient to fundsubstantially completed the Company’s projected 2016 operational and capital programs, the acquisition of certain assets in the Gulf of Mexico, and the redemption of its $750 million 2017 debt maturities in the fourth quarter of 2016.

Anadarko enters into strategic derivative positions to reduce its commodity-price risk and increase the predictability of cash flows. At September 30, 2016, derivative positions covered 26% of Anadarko’s anticipated oil sales volumes for 2016, 42% of its anticipated natural-gas sales volumes and 2% of its anticipated NGLs sales volumes for 2017, and 14% of its anticipated natural-gas sales volumes for 2018. These instruments had a fair value of $41 million as of September 30, 2016. See ~~Note 6—Derivative Instruments~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Part I, Item 1 of this Form 10-Q.~~

~~Potential for Future Impairments~~ Properties and equipment are reviewed for impairment when facts and circumstances indicate that net book values may not be recoverable. In performing this review, an undiscounted cash flow test is performed at the lowest level for which identifiable cash flows are independent of cash flows from other assets. If the sumrequirements of the ~~undiscounted future net cash flows~~NTO. In August 2017, following a three-month review of oil and gas operations, the Governor of Colorado announced several policy initiatives designed to enhance public safety, which are to be implemented over the next several months through rulemaking or legislation. The Company continues to work cooperatively with state regulators and others and is ~~less than~~also cooperating with the ~~net book value of the property, the property’s fair value is estimated and an impairment loss is recognized for the excess, if any, of the property’s net book value over~~NTSB in its estimated fair value. The primary assumptions used to estimate expected undiscounted future net cash flows include anticipated future production, commodity prices, and capital and operating costs. Unfavorable changes in any of these assumptions could result in a reduction in undiscounted future cash flows and could indicate property impairment. Uncertaintiesinvestigation related to the primary assumptions could affect the timing of an impairment. In most cases, the assumption that generates the most variability in undiscounted future net cash flows is future oil and gas prices. For impairment testing, the Company used the five-year forward strip prices for oil and natural gas, with prices subsequent to the fifth year held constant as the benchmark price in the undiscounted future net cash flows. Capital and operating costs were estimated assuming 0% escalation for years where the average oil strip price was below $50 per barrel (Bbl) and 1% escalation for years where the average oil strip price exceeded $50 per Bbl.

At September 30, 2016, the Company’s estimates of undiscounted future cash flows attributable to a certain international asset group with a net book value of approximately $1.4 billion, and certain U.S. onshore asset groups with a combined net book value of approximately $1.1 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 a non-cash impairment in excess of $600 million for the international asset group, and a 10% decline in natural-gas prices (with all other assumptions unchanged) could result in non-cash impairments in excess of $400 million for the U.S. onshore asset groups. It is also reasonably possible that prolonged low or further declines in commodity prices, further changes to the Company’s drilling plans in response to lower prices, or increases in drilling or operating costs could result in other additional impairments.

~~Table of Contents~~

~~OVERVIEW~~

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

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

~~Overall~~Total Company

Anadarko’s ~~third-quarter sales volumes averaged 780 thousand barrels of~~overall sales-volume product mix increased to 57% oil ~~equivalent per day (MBOE/d), representing a 1% decrease from~~in the third quarter of ~~2015, primarily due~~2017, compared to ~~divestitures of U.S. onshore assets partially offset by increased performance and continued field development~~42% in ~~U.S. onshore and new wells coming online in the Gulf of Mexico.~~

In September 2016, the Company entered into an agreement to acquire certain assets in the Gulf of Mexico for $2.0 billion. The acquisition is expected to close in the fourth quarter of 2016 and is subject to customary closing conditions.

The Company closed $2.8 billion of monetizations year to date, including asset divestitures, the sale of Anadarko’s interest in Springfield Pipeline LLC to WES, the sale of a portion of the Company’s common units in Western Gas Equity Partners, LP (WGP) to the public, and the Company’s conveyance of a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party.

~~U.S. Onshore~~

~~Third-quarter liquids sales volumes averaged 284 thousand barrels per day (MBbls/d), representing a 2% increase from~~ the third quarter of ~~2015, primarily due to increased performance in the DJ basin~~2016, which significantly improved margins and ~~continued field development in the Delaware basin.~~returns.

Third-quarter natural-gas sales volumes averaged 321 MBOE/d, representing a 5% decrease from the third quarter of 2015, primarily due to the September 2015 sale of certain coalbed methane properties, the July 2015 sale of certain properties in East Texas, and the June 2016 sale of certain Wyoming assets. These decreases were partially offset by improved well performance in the DJ basin and production modulation in the Marcellus shale in 2015.

~~Gulf of Mexico~~

~~Third-quarter~~Anadarko’s third-quarter oil sales volumes averaged ~~65 MBOE/d, representing an 18% increase from the third quarter of 2015, primarily due to new wells coming online at K2 and Caesar/Tonga.~~

~~The Company acquired a 33% operated working interest in the Constellation discovery (formerly Hopkins). The field is expected to be tied back to Anadarko’s Constitution spar.~~

~~International~~

~~Third-quarter sales volumes averaged 91~~353 MBbls/d, representing an 11% increase from the third quarter of ~~2015,~~2016, primarily ~~as a result~~due to increased volumes from the Gulf of ~~timing~~Mexico, partially offset by the divestiture of ~~liftings~~certain U.S. onshore oil and gas assets in ~~Algeria.~~2016 and 2017.

~~The Tweneboa/Enyenra/Ntomme (TEN) development project (19% nonoperated working interest) in Ghana achieved first oil~~U.S. Onshore

Oil sales volumes in the ~~third quarter of 2016.~~

~~Table of Contents~~

~~Financial~~

~~Anadarko’s net loss attributable to common stockholders for~~Delaware basin increased by 10 MBbls/d, representing a 40% increase from the third quarter of 2016, ~~totaled $830 million.~~primarily due to continued drilling and completion activities.

~~The Company completed a public offering of 40.5 million shares of its common stock for net proceeds of $2.16 billion. Net proceeds will primarily be used to fund the acquisition of certain~~ Gulf of Mexico ~~assets discussed above,~~

Oil sales volumes averaged 126 MBbls/d, representing a 95% increase from the third quarter of 2016, primarily due to the GOM Acquisition and continued tieback activity at several facilities, partially offset by deferred production as a result of Hurricanes Harvey and Irma during the third quarter of 2017.

International

The International Tribunal for the Law of the Sea issued a ruling in September 2017 regarding the delimitation of the maritime boundary between Ghana and Côte d’Ivoire in the Atlantic Ocean. The new maritime boundary as determined by the tribunal does not affect the TEN fields, and the ~~remaining net proceeds~~operator now plans to work with the Government of Ghana to put in place the permits necessary to resume development drilling.

Interim spread 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. Anadarko continues to work with its partners to optimize a permanent turret solution that will ~~be used~~effectively stabilize the vessel with a minimum amount of shut-in time, which is expected to start in early 2018. In October, the partnership received Ghanaian Government approval for ~~general corporate purposes.~~the full-field plan of development, with drilling operations expected to commence in 2018.

The foundational legal and contractual framework was completed for the Company’s onshore LNG project in Mozambique. A few formal government approvals remain before the commencement of resettlement and site preparation activities, which will position the onshore area for construction of the LNG facilities.

Anadarko and its co-venturers in Offshore Area 1 in Mozambique reached agreement on the project’s first long-term sale and purchase agreement (SPA) for 2.6 million tonnes per annum with PTT Public Company Limited (PTT), Thailand’s national oil and gas company. The SPA is subject to the approval of the Government of Thailand.

Financial

The Company generated ~~$785~~$639 million of cash flow from operations and ended the ~~third~~ quarter with ~~$4.0~~$5.3 billion of ~~cash on hand, which included net proceeds from~~cash.

In September 2017, Anadarko announced a $2.5 billion share-repurchase program. In October 2017, the ~~Company’s September 2016 equity offering.~~

~~The~~ Company ~~recognized workforce reduction program expenses of $112 million in the third quarter for a total of $363 million for the nine months ended September 30, 2016. Total program expenses are expected~~entered into an ASR Agreement to ~~be $410 million.~~

~~WES completed a public offering of $500 million aggregate principal amount of 4.650% Senior Notes due July 2026. Net proceeds were used to repay a portion~~complete $1.0 billion of the ~~amount outstanding under WES’s $1.2 billion five-year senior unsecured revolving credit facility maturing in February 2019 (WES RCF).~~

~~In October 2016, the Company provided notice of its intent to redeem its $750 million of 6.375% Senior Notes due September 2017~~share-repurchase program prior to ~~year end.~~the end of 2017.

~~Table of Contents~~

FINANCIAL RESULTS


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
millions except per-share amounts	2016			2015			2016			2015			2017			2016			2017			2016
Oil and condensate, natural-gas, and NGLs sales	$	1,901		$	1,896		$	4,975		$	6,520
Oil, natural-gas, and NGLs sales													$	2,101		$	1,901		$	6,510		$	4,975
Gathering, processing, and marketing sales	350			334			895			932			509			350			1,417			895
Gains (losses) on divestitures and other, net	(358		)	(542		)	(388		)	(807		)	(114		)	(358		)	1,052			(388		)
Revenues and other	1,893			1,688			5,482			6,645			$	2,496		$	1,893		$	8,979		$	5,482
Costs and expenses	2,686			4,237			7,471			13,312			3,271			2,686			9,989			7,471
Other (income) expense	214			528			1,324			853			291			214			606			1,324
Income tax expense (benefit)	(260		)	(917		)	(957		)	(2,232		)	(425		)	(260		)	(366		)	(957		)
Net income (loss) attributable to common stockholders	$	(830	)	$	(2,235	)	$	(2,556	)	$	(5,442	)	$	(699	)	$	(830	)	$	(1,432	)	$	(2,556	)
Net income (loss) per common share attributable to common stockholders—diluted	$	(1.61	)	$	(4.41	)	$	(5.00	)	$	(10.73	)	$	(1.27	)	$	(1.61	)	$	(2.61	)	$	(5.00	)
Average number of common shares outstanding—diluted	517			508			512			508			553			517			552			512

The following discussion pertains to Anadarko’s results of operations, financial condition, and changes in financial condition. ~~Any increases~~Increases or decreases “for the three months ended September 30, ~~2016,~~2017,” refer to the comparison of the three months ended September 30, ~~2016,~~2017, to the three months ended September 30, ~~2015,~~2016, and ~~any~~ increases or decreases “for the nine months ended September 30, ~~2016,~~2017,” refer to the comparison of the nine months ended September 30, ~~2016,~~2017, to the nine months ended September 30, ~~2015.~~2016. The primary factors that affect the Company’s results of operations include commodity prices for oil, natural gas, and NGLs; sales volumes; the cost of finding and developing such reserves; and operating costs.

Revenues and Sales Volumes


	Three Months Ended September 30,												Three Months Ended September 30,
millions except percentages	Oil and Condensate			Natural Gas			NGLs			Total			Oil			Natural Gas			NGLs			Total
2015 sales revenues	$	1,229		$	484		$	183		$	1,896
2016 sales revenues													$	1,239		$	435		$	227		$	1,901
Changes associated with prices													189			33			103			325
Changes associated with sales volumes	67			(40		)	10			37			139			(199		)	(65		)	(125		)
Changes associated with prices	(57		)	(9		)	34			(32		)
2016 sales revenues	$	1,239		$	435		$	227		$	1,901
Increase (decrease) vs. 2015	1		%	(10		)%	24		%	—		%
2017 sales revenues													$	1,567		$	269		$	265		$	2,101
Increase (decrease) vs. 2016													26		%	(38		)%	17		%	11		%

	Nine Months Ended September 30,												Nine Months Ended September 30,
millions except percentages	Oil and Condensate			Natural Gas			NGLs			Total			Oil			Natural Gas			NGLs			Total
2015 sales revenues	$	4,264		$	1,612		$	644		$	6,520
2016 sales revenues													$	3,214		$	1,121		$	640		$	4,975
Changes associated with prices													1,027			372			269			1,668
Changes associated with sales volumes	(97		)	(167		)	(18		)	(282		)	411			(403		)	(141		)	(133		)
Changes associated with prices	(953		)	(324		)	14			(1,263		)
2016 sales revenues	$	3,214		$	1,121		$	640		$	4,975
Increase (decrease) vs. 2015	(25		)%	(30		)%	(1		)%	(24		)%
2017 sales revenues													$	4,652		$	1,090		$	768		$	6,510
Increase (decrease) vs. 2016													45		%	(3		)%	20		%	31		%

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

~~Table of Contents~~

divestitures (primarily natural gas).

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2016 Inc (Dec) vs. 2015 2015 2016 Inc (Dec) vs. 2015 2015
Barrels of Oil Equivalent
(MMBOE except percentages)
United States 64
(2 )% 65
196
(6 )% 209
International 8
11
8
23
(6 ) 25
Total barrels of oil equivalent 72
(1 ) 73
219
(6 ) 234

Barrels of Oil Equivalent per Day
(MBOE/d except percentages)
United States 689
(2 )% 705
715
(6 )% 765
International 91
11
82
85
(6 ) 90
Total barrels of oil equivalent per day 780
(1 ) 787
800
(6 ) 855

~~_______________________________________________________________________________~~

~~MMBOE—million barrels of oil equivalent~~



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017	Inc (Dec) vs. 2016		2016	2017	Inc (Dec) vs. 2016		2016
Barrels of Oil Equivalent
(MMBOE except percentages)
United States	50	(22	)%	64	161	(18	)%	196
International	8	—		8	26	13		23
Total barrels of oil equivalent	58	(20	)	72	187	(15	)	219

Barrels of Oil Equivalent per Day
(MBOE/d except percentages)
United States	535	(22	)%	689	587	(18	)%	715
International	91	—		91	96	14		85
Total barrels of oil equivalent per day	626	(20	)	780	683	(15	)	800

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 6—7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form ~~10-Q and~~ ~~Other (Income) Expense—(Gains) Losses on Derivatives, net~~.10-Q. Production of oil, natural gas, and NGLs is usually not affected by seasonal swings in demand.

Oil Sales Revenues, Average Prices, and Volumes



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016
Oil sales revenues (millions)	$	1,567	26	%	$	1,239	$	4,652	45	%	$	3,214

United States
Sales volumes—MMBbls	25		14	%	22		71		12	%	63
MBbls/d	266		14		233		259		12		230
Price per barrel	$	46.89	14		$	41.29	$	47.63	30		$	36.52

International
Sales volumes—MMBbls	8		4	%	8		25		15	%	22
MBbls/d	87		4		84		91		15		79
Price per barrel	$	52.61	15		$	45.82	$	51.59	23		$	41.98

Total
Sales volumes—MMBbls	33		11	%	30		96		13	%	85
MBbls/d	353		11		317		350		13		309
Price per barrel	$	48.31	14		$	42.49	$	48.66	28		$	37.91

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

~~Table of Contents~~



millions	Change in Revenues		Due to Change in Prices		Due to Change in Volumes
Three months ended September 30, 2017 vs. 2016	$	328	$	189	$	139
Nine months ended September 30, 2017 vs. 2016	1,438		1,027		411

Oil Prices

The average oil price received increased for the three and ~~Condensate Sales Volumes, Average Prices, and Revenues~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2016 Inc (Dec) vs. 2015 2015 2016 Inc (Dec) vs. 2015 2015
United States
Sales volumes—MMBbls 22
4 % 21
63
(1 )% 64
MBbls/d 233
4
224
230
(1 ) 233
Price per barrel $ 41.29
(5 ) $ 43.48
$ 36.52
(23 ) $ 47.37
International
Sales volumes—MMBbls 8
10 % 7
22
(6 )% 23
MBbls/d 84
10
77
79
(6 ) 84
Price per barrel $ 45.82
(3 ) $ 47.30
$ 41.98
(22 ) $ 54.13
Total
Sales volumes—MMBbls 30
5 % 28
85
(2 )% 87
MBbls/d 317
5
301
309
(2 ) 317
Price per barrel $ 42.49
(4 ) $ 44.45
$ 37.91
(23 ) $ 49.16
Oil and condensate sales revenues (millions)
$ 1,239
1
$ 1,229
$ 3,214
(25 ) $ 4,264

~~_______________________________________________________________________________~~

~~MMBbls—million barrels~~nine months ended September 30, 2017, primarily due to the expectation of decreasing global oversupply as a result of OPEC’s agreement to reduce production through the first quarter of 2018.

~~Anadarko’s~~Oil Sales Volumes

2017 vs. 2016 The Company’s oil ~~and condensate~~ sales volumes increased by 1636 MBbls/d for the three months ended September 30, ~~2016,~~2017, and ~~decreased by 8~~41 MBbls/d for the nine months ended September 30, ~~2016,~~2017, primarily due to the following:

U.S. Onshore

~~DJ basin~~ ~~- decrease of 4 MBbls/d~~Sales volumes for the ~~nine months ended September 30, 2016, primarily due to reduced capital activity~~

Delaware basin ~~- increase of~~ increased by 10 MBbls/d for the three months ended September 30, ~~2016,~~2017, and 711 MBbls/d for the nine months ended September 30, ~~2016,~~2017, primarily due to continued ~~field development~~

drilling and completion activities in 2017.

~~Eagleford shale~~ ~~- decrease of 6~~Sales volumes for the DJ basin decreased by 10 MBbls/d for the three months ended September 30, ~~2016,~~2017, and 715 MBbls/d for the nine months ended September 30, ~~2016,~~2017, primarily due to ~~natural~~reduced capital activity in 2016 during the low commodity-price cycle resulting in production ~~decline~~

declines during 2017 and downtime related to the Company’s response efforts in Colorado in the second and third quarters of 2017. This decrease was partially offset by increased production due to increased drilling and completion activity in 2017.

Divestitures - resulted in a decrease in sales volumes of 533 MBbls/d for the three months ended September 30, ~~2016, primarily due to the sale of certain Wyoming assets,~~2017, and ~~decrease of 6~~30 MBbls/d for the nine months ended September 30, ~~2016,~~2017, primarily ~~due~~related to the sale of ~~certain enhanced oil recovery (EOR)~~the Eagleford assets

in the first half of 2017.

Gulf of Mexico

~~Caesar/Tonga, K2, and Lucius~~ ~~- increase of 12~~Sales volumes increased by 61 MBbls/d for the three months ended September 30, ~~2016, primarily due to new wells coming online at K2~~2017, and ~~Caesar/Tonga, and increase of 9~~62 MBbls/d for the nine months ended September 30, ~~2016,~~2017, primarily due to ~~new wells coming online~~the GOM Acquisition in December 2016 and continued tieback activity at K2several facilities, partially offset by deferred production as a result of Hurricanes Harvey and ~~Caesar/Tonga and~~Irma during the ~~achievement of first oil at Lucius in the first~~third quarter of ~~2015~~

2017.

International

~~Algeria~~ SalesvolumesforGhanaincreasedby8MBbls/dforthethreemonthsendedSeptember30~~- increase of 16 MBbls/d for the three months ended September 30, 2016,~~ ,2017,and 7 12MBbls/d for the nine months ended September 30, ~~2016,~~2017, primarily due to liftings from the ~~timing~~TEN development project, which came online late in the third quarter of ~~liftings~~

~~Ghana~~ ~~- decrease of 9 MBbls/d for the three months ended September 30,~~ 2016, and ~~12 MBbls/d for the nine months ended September 30,~~downtime in 2016 ~~primarily due to downtime~~ to address new production and offtake procedures resulting from issues associated with the Jubilee field ~~floating production, storage and offloading unit (FPSO)~~FPSO turret bearing. ~~The partners are pursuing a long-term solution to convert the FPSO to a permanently moored facility in 2017. In the meantime, shuttle tankers continue to conduct offtakes.~~

~~Table of Contents~~

Anadarko’s average oil price received decreased for the three and nine months ended September 30, 2016, primarily due to continued high petroleum inventories globally and stronger supply growth from the Organization of Petroleum Exporting Countries.

Natural-Gas Sales Volumes, Average Prices, and Revenues

Three Months Ended
September 30, Nine Months Ended
September 30,
2016 Inc (Dec) vs. 2015 2015 2016 Inc (Dec) vs. 2015 2015
United States
Sales volumes—Bcf 184
(8 )% 201
593
(10 )% 662
MMcf/d 2,003
(8 ) 2,186
2,164
(10 ) 2,424
Price per Mcf $ 2.36
(2 ) $ 2.41
$ 1.89
(23 ) $ 2.44
Natural-gas sales revenues (millions)
$ 435
(10 ) $ 484
$ 1,121
(30 ) $ 1,612

~~_______________________________________________________________________________~~

~~Bcf—billion cubic feet~~

~~MMcf/d—million cubic feet per day~~

~~Mcf—thousand cubic feet~~



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016
Natural-gas sales revenues (millions)	$	269	(38	)%	$	435	$	1,090	(3	)%	$	1,121

United States
Sales volumes—Bcf	100		(46	)%	184		380		(36	)%	593
MMcf/d	1,086		(46	)	2,003		1,392		(36	)	2,164
Price per Mcf	$	2.69	14		$	2.36	$	2.87	52		$	1.89

The following summarizes primary drivers for the change in natural-gas sales revenues:



millions	Change in Revenues			Due to Change in Prices		Due to Change in Volumes
Three months ended September 30, 2017 vs. 2016	$	(166	)	$	33	$	(199	)
Nine months ended September 30, 2017 vs. 2016	(31		)	372		(403		)

Natural-Gas Prices

The average natural-gas price received increased for the three and nine months ended September 30, 2017, primarily due to the industry’s year-over-year production declines and increased exports to Mexico, resulting in reduced gas storage industry-wide.

Natural-Gas Sales Volumes

2017 vs. 2016The Company’s natural-gas sales volumes decreased by ~~183~~917 MMcf/d for the three months ended September 30, ~~2016,~~2017, and ~~260~~772 MMcf/d for the nine months ended September 30, ~~2016, primarily due to the following:~~

~~U.S. Onshore~~


~~��~~	~~DJ basin~~ ~~- increase of 101 MMcf/d for the three months ended September 30, 2016, and 108 MMcf/d for the nine months ended September 30, 2016, primarily due to improved well performance~~

~~Marcellus shale~~ ~~- increase of 73 MMcf/d for the three months ended September 30, 2016, and 27 MMcf/d for the nine months ended September 30, 2016, primarily due to production modulation in 2015~~

~~Greater Natural Buttes~~ ~~- decrease of 1 MMcf/d for the three months ended September 30, 2016, and 45 MMcf/d for the nine months ended September 30, 2016, primarily due to natural production decline~~

~~Divestitures~~ ~~- decrease of 267 MMcf/d for the three months ended September 30, 2016, and 278 MMcf/d for the nine months ended September 30, 2016,~~2017, primarily due to the sale of ~~certain coalbed methane properties,~~ the ~~sale~~Marcellus and Eagleford assets in the first half of ~~certain Wyoming assets,~~2017 and the ~~sale~~Elm Grove and Carthage assets in the second half of ~~certain East Texas assets~~2016.

~~Gulf of Mexico~~

~~Independence Hub~~ - decrease of 76 MMcf/d for the three months ended September 30, 2016, and 69 MMcf/d for the nine months ended September 30, 2016, primarily as a result of the last producing well going off line in December 2015

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

~~Table of Contents~~

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


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
													2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016
Natural-gas liquids sales revenues (millions)													$	265	17	%	$	227	$	768	20	%	$	640

United States
Sales volumes—MMBbls													9		(28	)%	11		27		(23	)%	34
MBbls/d													88		(28	)	122		96		(22	)	124
Price per barrel													$	31.07	65		$	18.87	$	27.43	54		$	17.78

International
Sales volumes—MMBbls													—		(44	)%	—		1		(12	)%	1
MBbls/d													4		(44	)	7		5		(12	)	6
Price per barrel													$	32.98	39		$	23.74	$	34.02	44		$	23.55
	2016		Inc (Dec) vs. 2015		2015		2016		Inc (Dec) vs. 2015		2015
Total
Sales volumes—MMBbls	11		6	%	12		35		(3	)%	37		9		(29	)%	11		28		(22	)%	35
MBbls/d	129		6		122		130		(3	)	134		92		(29	)	129		101		(22	)	130
Price per barrel	$	19.13	18		$	16.26	$	18.04	2		$	17.63	$	31.15	63		$	19.13	$	27.77	54		$	18.04
Natural-gas liquids sales revenues (millions)	$	227	24		$	183	$	640	(1	)	$	644

NGLs sales represent revenues from the sale of product derived from the processing of Anadarko’s natural-gas production. The ~~Company’s~~following summarizes primary drivers for the change in NGLs sales ~~volumes increased by 7 MBbls/d for the three months ended September 30, 2016, and decreased by 4 MBbls/d for the nine months ended September 30, 2016, primarily due to the following:~~revenues:



millions	Change in Revenues		Due to Change in Prices		Due to Change in Volumes
Three months ended September 30, 2017 vs. 2016	$	38	$	103	$	(65	)
Nine months ended September 30, 2017 vs. 2016	128		269		(141		)

~~U.S. Onshore~~NGLs Prices

~~DJ basin~~ - increase of 17 MBbls/d for the three months ended September 30, 2016, primarily due to improved well performance and the injection of volumes into storage in 2015, and 8 MBbls/d for the nine months ended September 30, 2016, primarily due to improved well performance

~~East Texas/Louisiana~~ ~~- decrease of 5 MBbls/d for the three and nine months ended September 30, 2016, primarily due to natural production decline at Carthage/Haynesville~~

~~Greater Natural Buttes~~ ~~- decrease of 4 MBbls/d for the nine months ended September 30, 2016, primarily due to natural production decline in 2016 and sales from storage in 2015~~

~~Divestitures~~ ~~- decrease of 7 MBbls/d for the three months ended September 30, 2016, and 3 MBbls/d for the nine months ended September 30, 2016, primarily due to the sale of certain Wyoming assets in June 2016~~

~~Anadarko’s~~The average NGLs price received increased for the three and nine months ended September 30, ~~2016,~~2017, primarily due to increased propane prices stemming from higher ~~ethane rejection in 2016 resulting in higher-value NGL sales volumes.~~exports and increased domestic demand.

NGLs Sales Volumes

2017 vs. 2016 The Company’s NGLs sales volumes decreased by 37 MBbls/d for the three months ended September 30, 2017, and 29 MBbls/d for the nine months ended September 30, 2017, primarily due to the sale of the Eagleford assets in the first half of 2017 and the Carthage assets in the second half of 2016.

Gathering, Processing, and Marketing


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2016		Inc (Dec) vs. 2015		2015		2016		Inc (Dec) vs. 2015		2015		2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016
Gathering, processing, and marketing sales	$	350	5	%	$	334	$	895	(4	)%	$	932	$	509	45	%	$	350	$	1,417	58	%	$	895
Gathering, processing, and marketing expense	291		1		289		758		(5	)	798		398		37		291		1,108		46		758
Total gathering, processing, and marketing, net	$	59	31		$	45	$	137	2		$	134	$	111	88		$	59	$	309	126		$	137

Gathering and processing sales ~~includes~~include 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 ~~$14~~$52 million for the three months ended September 30, ~~2016,~~2017, and by $172 million for the nine months ended September 30, 2017, primarily due to lower operating expenses at the Delaware Basin Midstream (DBM) complex as a result of plant maintenance in 2015, decreased overhead expense due to the workforce reduction program, and higher processing margins duerelated to increased throughput volumes at the DBM ~~complex. Gathering,~~complex due to increased processing capacity from the start-up of newly constructed facilities in May and ~~marketing, net was relatively flat for~~October 2016 and previously existing facilities returning to service after the ~~nine months ended September 30, 2016.~~2016 outage at the DBM complex.

~~Table of Contents~~

Gains (Losses) on Divestitures and Other, net


	Three Months Ended September 30,								Nine Months Ended September 30,								Three Months Ended September 30,								Nine Months Ended September 30,
millions except percentages	2016			Inc (Dec) vs. 2015		2015			2016			Inc (Dec) vs. 2015		2015			2017			Inc (Dec) vs. 2016		2016			2017		Inc (Dec) vs. 2016		2016
Gains (losses) on divestitures	$	(414	)	28	%	$	(578	)	$	(516	)	49	%	$	(1,003	)
Gains (losses) on divestitures, net																	$	(194	)	53	%	$	(414	)	$	815	NM		$	(516	)
Other	56			56		36			128			(35	)	196			80			43		56			237		85	%	128
Total gains (losses) on divestitures and other, net	$	(358	)	34		$	(542	)	$	(388	)	52		$	(807	)	$	(114	)	68		$	(358	)	$	1,052	NM		$	(388	)

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. ~~Gains (losses) on divestitures~~

During the three and ~~other, net primarily relate~~nine months ended September 30, 2017 and 2016, Anadarko divested certain non-core U.S. onshore assets. See Note 3—Acquisitions, Divestitures, and Assets Held for Salein the Notes to ~~the following:~~Consolidated Financial Statements under Item 1 of this Form 10-Q for additional information.

~~2016~~

Costs and Expenses

The ~~Company recognized a loss of $355 million in the third quarter on assets held~~following provides Anadarko’s total costs and expenses for ~~sale associated with the divestiture of certain U.S. onshore assets in East Texas, which is expected to close in the fourth quarter of 2016.~~three and nine months ended September 30:

~~The Company recognized a loss of $54 million associated with the third-quarter divestiture of certain U.S. onshore assets in East Texas/Louisiana.~~

~~The Company recognized a loss of $59 million associated with the second-quarter divestiture of certain U.S. onshore assets in Wyoming.~~



	Three Months Ended September 30,				Nine Months Ended September 30,
millions	2017		2016		2017		2016
Oil and gas operating	$	257	$	198	$	748	$	608
Oil and gas transportation	220		256		698		744
Exploration	751		304		2,371		506
Gathering, processing, and marketing ⁽¹⁾	398		291		1,108		758
General and administrative	280		362		840		1,116
Depreciation, depletion, and amortization	1,083		1,069		3,235		3,202
Production, property, and other taxes	159		148		449		422
Impairments	—		27		383		61
Other operating expense	123		31		157		54
Total	$	3,271	$	2,686	$	9,989	$	7,471


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

The Company recognized a loss of $50 million in the second quarter on assets held for sale associated with the divestiture of certain U.S. onshore assets in West Texas, which closed in the third quarter.Oil and Gas Operating Expense

~~2015~~



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016
Oil and gas operating (millions)	$	257	30	%	$	198	$	748	23	%	$	608
Oil and gas operating—per BOE	4.46		62		2.76		4.01		44		2.78

~~The Company recognized a loss of $440 million associated with the third-quarter divestiture of certain U.S. onshore oil~~

Oil and gas ~~coalbed methane properties. Additionally, the Company recognized a loss of $100~~operating expense increased by $140 million ~~in the third quarter on assets held~~ for ~~sale for the related midstream assets.~~

The Company recognized a loss of $344 million primarily in the first quarter on assets held for sale associated with the divestiture of certain U.S. onshore EOR assets, which closed in the second quarter.

The Company recognized a loss of $97 million in the second quarter on assets held for sale associated with the divestiture of certain U.S. onshore assets in East Texas, which closed in the third quarter with an additional loss of $13 million due to closing adjustments.

~~The Company recognized income of $13 million during the third quarter, and $130 million during~~ the nine months ended September 30, ~~2015,~~2017, primarily due to the following:

higher operating costs of $180 million primarily related to ~~the settlement of a royalty lawsuit associated with a property~~increased activity in the Gulf of ~~Mexico.~~Mexico and the GOM Acquisition

higher operating costs of $48 million related to increased activity in the DJ and Delaware basins and additional costs related to the Company’s response efforts in Colorado in the second and third quarters of 2017

lower non-operating costs of $18 million in Ghana primarily related to FPSO maintenance costs in 2016, partially offset by higher costs due to increased production from the TEN development in 2017, which came online late in the third quarter of 2016

lower expenses of $67 million as a result of U.S. onshore asset divestitures

The related costs per BOE increased by $1.23 for the nine months ended September 30, 2017, primarily due to increased costs as discussed above and shifting to a higher-return, oil-levered portfolio.

~~Table of Contents~~

~~Costs and Expenses~~Exploration Expense

Three Months Ended
September 30, Nine Months Ended
September 30,
2016 Inc (Dec) vs. 2015 2015 2016 Inc (Dec) vs. 2015 2015
Oil and gas operating (millions)
$ 198
(24 )% $ 262
$ 608
(22 )% $ 784
Oil and gas operating—per BOE 2.76
(24 ) 3.62
2.78
(17 ) 3.36
Oil and gas transportation (millions)
256
(3 ) 265
744
(13 ) 853
Oil and gas transportation—per BOE 3.56
(3 ) 3.66
3.40
(7 ) 3.65

~~BOE—barrel of oil equivalent~~



	Three Months Ended September 30,				Nine Months Ended September 30,
millions	2017		2016		2017		2016
Exploration Expense
Dry hole expense	$	565	$	203	$	1,408	$	209
Impairments of unproved properties	113		52		736		91
Geological and geophysical, exploration overhead, and other expense	73		49		227		206
Total exploration expense	$	751	$	304	$	2,371	$	506

~~Oil and gas operating~~Total exploration expense ~~decreased~~increased by ~~$64~~$447 million for the three months ended September 30, ~~2016,~~2017, and $1.9 billion for the nine months ended September 30, 2017, primarily ~~due~~related to ~~lower workover~~the following:

Dry Hole Expense

The Company expensed $1.4 billion of exploratory well costs for the nine months ended September 30, 2017. See Note 5—Exploratory Well Costs in the Notes to Consolidated Financial Statements under Part I, Item 1 of ~~$23~~this Form 10-Q for additional information.

Dry hole expense for the nine months ended September 30, 2017, primarily related to the following:

$438 million related to the Shenandoah project in the Gulf of Mexico ~~and U.S. onshore and lower expenses~~

$221 million related to the Phobos project in the Gulf of ~~$18~~Mexico

$110 million ~~as a result~~related to the Warrior project in the Gulf of ~~divestitures. Oil and gas operating~~Mexico

$325 million related to wells in Côte d’Ivoire

$243 million related to wells in the Grand Fuerte area in Colombia

Dry hole expense ~~decreased by $176 million~~ for the nine months ended September 30, 2016, ~~due~~primarily related to ~~lower expenses of $82~~the following:

$92 million asrelated to certain wells in Mozambique

$64 million related to a ~~result of divestitures, lower workover costs of $37 million~~Shenandoah well in the Gulf of Mexico ~~and U.S. onshore, lower nonoperated costs~~

$38 million related to a well in Côte d’Ivoire

Impairments of ~~$25 million across all areas, and decreased surface maintenance costs~~Unproved Properties

Impairments of $18 million in U.S. onshore and the Gulf of Mexico. The related costs per BOE decreased for the three and nine months ended September 30, 2016, primarily due to cost reduction initiatives and efficiencies across the Company’s operating areas.

~~Oil and gas transportation expense decreased by $9 million for the three months ended September 30, 2016, and $109 million~~unproved properties for the nine months ended September 30, 2016, due to lower sales volumes across all areas. The related costs per BOE decreased for the three and nine months ended September 30, 2016, due to lower costs as a result of decreased sales volumes.

~~Table of Contents~~

Three Months Ended
September 30, Nine Months Ended
September 30,
millions 2016 2015 2016 2015
Exploration Expense
Dry hole expense $ 203
$ 817
$ 209
$ 859
Impairments of unproved properties 52
136
91
1,134
Geological and geophysical expense 12
67
81
105
Exploration overhead and other 37
54
125
162
Total exploration expense $ 304
$ 1,074
$ 506
$ 2,260

~~For the three months ended September 30, 2016, total exploration expense decreased by $770 million~~2017, primarily related ~~to the following:~~

~~Dry hole expense decreased by $614 million, primarily due~~ to the following:

•

The Company ~~expensed suspended exploratory well costs~~recognized $586 million of ~~$92~~impairments of unproved Gulf of Mexico properties, of which $463 million related to ~~certain wells in Mozambique and $64 million~~the Shenandoah project. The unproved property balance related to ~~a well in~~the Shenandoah project originated from the purchase price allocated to the Gulf of Mexico exploration projects from the acquisition of Kerr-McGee Corporation in 2006. For additional details on the ~~third quarter of 2016. See~~Shenandoah project, 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 $38~~recognized $88 million ~~for a well in Côte d’Ivoire that finished drilling in the third quarter~~ of ~~2016 and encountered noncommercial quantities of hydrocarbons.~~

The Company expensed suspended exploratory well costs of $668 million in the third quarter of 2015, primarily related to Brazil where the Company does not expect to have substantive exploration and development activities for the foreseeable future given the current oil-price environment and other considerations.

~~Anadarko expensed $149 million due to unsuccessful drilling activities primarily associated with Gulf of Mexico properties and the deeper objective of a well in Colombia in the third quarter of 2015.~~

~~Impairments~~impairments of unproved international properties decreased by $84 million primarily due to a $109 million impairment in 2015 of the Company’s unproved Utica properties resulting from an assignment of mineral interests in settlement of a legal matter.

~~Geological and geophysical expense decreased by $55 million primarily due to seismic activities in Colombia in 2015.~~

~~Exploration overhead and other decreased by $17 million primarily due to lower employee-related expenses in 2016.~~

~~For~~during the nine months ended September 30, ~~2016, total exploration expense decreased by $1.8 billion primarily due to the following:~~2017.

~~Dry hole expense decreased by $650 million, primarily related to the following:~~

~~In 2016, the Company expensed $92 million related to certain wells in Mozambique and $64 million of suspended exploratory well costs related to a well~~ See Note 4—Impairmentsin the ~~Gulf~~Notes to Consolidated Financial Statements under Part I, Item 1 of ~~Mexico as discussed above.~~

In 2016, the Company expensed $38 million related to a well in Côte d’Ivoire, as discussed above, and expensed $15 million due to unsuccessful drilling activities primarily associated with Gulf of Mexico and U.S. onshore properties.

In 2015, Anadarko expensed suspended exploratory well costs of $668 million primarily related to Brazil, as discussed above, and expensed $191 million due to unsuccessful drilling activities primarily associated with Gulf of Mexico properties and the deeper objective of a well in Colombia.

Impairments of unproved properties decreased by $1.0 billion primarily due to the 2015 impairment in the amount of $935 million related to the Company’s unproved Greater Natural Buttes properties as a result of lower commodity prices and an impairment of $109 million for unproved Utica properties in 2015.

~~Geological and geophysical expense decreased by $24 million primarily due to reduced seismic activities in U.S. onshore and New Zealand in 2016.~~

~~Exploration overhead and other decreased by $37 million primarily due to lower employee-related expenses in 2016.~~this Form 10-Q.

~~Table of Contents~~

Three Months Ended
September 30, Nine Months Ended
September 30,
millions except percentages 2016 Inc (Dec) vs. 2015 2015 2016 Inc (Dec) vs. 2015 2015
General and administrative $ 362
19 % $ 303
$ 1,116
26 % $ 888
Depreciation, depletion, and amortization 1,069
(4 ) 1,111
3,202
(11 ) 3,581
Other taxes 148
17
127
422
(8 ) 460
Impairments 27
(96 ) 758
61
(98 ) 3,571
Other operating expense 31
(35 ) 48
54
(54 ) 117

General and ~~administrative expense (G&A) included $112~~Administrative Expense



	Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2017		Inc (Dec) vs. 2016		2016		2017		Inc (Dec) vs. 2016		2016
General and administrative	$	280	(23	)%	$	362	$	840	(25	)%	$	1,116

G&A expenses decreased by $82 million ~~of charges associated with the workforce reduction program~~ for the three months ended September 30, ~~2016,~~2017, and ~~$363~~$276 million for the nine months ended September 30, ~~2016.~~2017. Excluding the $91 million decrease related to the 2016 workforce reduction ~~expenses, G&A decreased by $53 million~~program and other severance-related costs for the three months ended September 30, ~~2016,~~2017, and ~~by $135~~the $285 million decrease for the nine months ended September 30, ~~2016, primarily due to lower employee-related~~2017, G&A expenses ~~resulting from a workforce reduction program initiated in March 2016.~~remained relatively flat. See Note ~~12—~~11—Restructuring Charges in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Depreciation, ~~depletion,~~Depletion, and ~~amortization~~Amortization



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

DD&A expense ~~decreased~~increased by ~~$42 million for the three months ended September 30, 2016, and by $379~~$33 million for the nine months ended September 30, ~~2016,~~2017, primarily due to the following:

$363 million related to higher sales volumes in the Gulf of Mexico primarily due to the GOM Acquisition

$236 million related to international production DD&A primarily due to higher sales volumes from the Ghana TEN project, which came online late in the third quarter of 2016

These increases were offset by the following:

$584 million related to lower ~~carrying value for~~2017 sales volumes and asset property balances associated with U.S. onshore ~~and midstream~~ properties as a result of ~~2015 asset impairments~~divestitures in 2016 and ~~divestitures~~

~~lower 2016 sales volumes associated with U.S. onshore properties~~

~~cost revisions related to certain asset retirement obligations associated with fully depreciated assets~~2017

~~Other taxes decreased by $38 million for~~Impairments



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

During the nine months ended September 30, ~~2016, primarily due to lower ad valorem taxes~~2017, impairments included $211 million associated with Gulf of ~~$48 million due to lower commodity prices.~~

~~Impairment expenses for the three and nine months ended September 30, 2016, were primarily related to U.S. onshore~~Mexico oil and gas ~~and midstream~~ properties due to changes in development plans. Impairment expense for the three months ended September 30, 2015, included $641 million for certain U.S. onshore oil and gas properties and $101 million for an oil and gas property in the Gulf of Mexico, all due to lower forecasted commodity prices. ~~Impairment expense for the nine months ended September 30, 2015, included $2.3 billion~~Additional impairments of $172 million primarily related to ~~the Company’s Greater Natural Buttes oil and gas properties and $449 million for related midstream properties, $662 million for certain other~~a U.S. onshore ~~oil and gas properties, and $126 million for oil and gas properties in the Gulf of Mexico, all due to lower forecasted commodity prices.~~

Other operating expense decreased by $17 million for the three months ended September 30, 2016, and $63 million for the nine months ended September 30, 2016, primarily due to legal settlements in 2015, partially offset by costs related to an idle rig in the Gulf of Mexico in 2016. Other operating expense for the nine months ended September 30, 2016, also decreased due to early rig-termination fees in 2015.

~~Table of Contents~~

~~Other (Income) Expense~~

Three Months Ended
September 30, Nine Months Ended
September 30,
millions 2016 2015 2016 2015
Interest Expense
Debt and other $ 251
$ 245
$ 768
$ 743
Capitalized interest (31 ) (46 ) (111 ) (127 )
Total interest expense $ 220
$ 199
$ 657
$ 616

~~Interest expense increased by $21 million for the three months ended September 30, 2016, and by $41 million for the nine months ended September 30, 2016, primarily~~midstream property due to a ~~decrease in capitalized interest~~reduced throughput fee as a result of ~~lower construction-in-progress balances~~a producer’s bankruptcy. For further discussion related to impairments, including the potential for ~~long-term capital projects in Brazil, and increased interest expense due to the $3.0 billion March 2016 Senior Notes issuances.~~

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

Three Months Ended
September 30, Nine Months Ended
September 30,
millions 2016 2015 2016 2015
(Gains) Losses on Derivatives, net
(Gains) losses on commodity derivatives, net $ (59 ) $ (125 ) $ 7
$ (177 )
(Gains) losses on interest-rate derivatives, net 84
407
622
300
Total (gains) losses on derivatives, net $ 25
$ 282
$ 629
$ 123

(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. An interest-rate swap agreement was settled for a cash payment of $193 million in March 2016, and interest-rate swap agreements were settled for total cash payments of $73 million in September 2016. The Company settled commodity derivatives for cash receipts of $63 million for the three months ended September 30, 2016, $79 million for the three months ended September 30, 2015, $226 million for the nine months ended September 30, 2016, and $251 million for the nine months ended September 30, 2015.

~~For additional information,~~future impairments, see Note ~~6—Derivative Instruments~~4—Impairments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

~~Table of Contents~~

Other Operating Expenses

Three Months Ended
September 30, Nine Months Ended
September 30,
millions 2016 2015 2016 2015
Other (Income) Expense, net
Interest income $ (3 ) $ (2 ) $ (10 ) $ (9 )
Other (28 ) 49
(76 ) 118
Total other (income) expense, net $ (31 ) $ 47
$ (86 ) $ 109



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

~~For~~Other operating expenses increased by $92 million for the three months ended September 30, ~~2016, other income, net increased by $78 million.~~

~~Favorable changes in foreign currency gains/losses of $26~~2017, and $103 million were primarily associated with foreign currency held in escrow pending final determination of the Company’s Brazilian tax liability attributable to the 2008 divestiture of the Peregrino field offshore Brazil.

~~The Company reversed a tax indemnification liability of $39 million in September 2016 due to the expiration of the statute of limitations.~~

~~Other income, net increased by $12 million due to 2015 losses associated with certain equity investments as a result of lower commodity prices.~~

~~For~~for the nine months ended September 30, ~~2016, other income, net increased by $195 million.~~

~~As a result~~2017, primarily due to $105 million expensed in the third quarter of 2017 for the early termination of a Chapter 11 bankruptcy declaration by a third party, the U.S. Department of the Interior ordered Anadarko to perform the decommissioning of a production facility and related wells previously sold to the third party. The Company accrued the costs to decommission the facility and wells in prior years, including $22 million in 2015. During the second quarter of 2016, the Company substantially completed the decommissioning of the wells. Final costs were lower than expected, and the Company recognized income of $56 million as a result of the reduced obligation.

Favorable changes in foreign currency gains/losses of $60 million were primarily associated with foreign currency held in escrow pending final determination of the Company’s Brazilian tax liability attributable to the 2008 divestiture of the Peregrino field offshore Brazil.

~~Other income, net increased by $39 million related to the reversal of the tax indemnification liability mentioned above.~~

~~Other income, net increased by $25 million due to 2015 losses associated with certain equity investments as a result of lower commodity prices.~~drilling rig.

Other (Income) Expense

The following provides Anadarko’s other (income) expense for the three and nine months ended September 30:



	Three Months Ended September 30,						Nine Months Ended September 30,
millions	2017			2016			2017			2016
Interest expense	$	230		$	220		$	680		$	657
Loss on early extinguishment of debt	—			—			2			124
(Gains) losses on derivatives, net ⁽¹⁾	82			25			(33		)	629
Other (income) expense, net	(21		)	(31		)	(43		)	(86		)
Total	$	291		$	214		$	606		$	1,324


⁽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.

~~Table of Contents~~

Income Tax Expense (Benefit)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2016			2015			2016			2015			2017			2016			2017			2016
Income tax expense (benefit)	$	(260	)	$	(917	)	$	(957	)	$	(2,232	)	$	(425	)	$	(260	)	$	(366	)	$	(957	)
Income (loss) before income taxes	(1,007		)	(3,077		)	(3,313		)	(7,520		)	(1,066		)	(1,007		)	(1,616		)	(3,313		)
Effective tax rate	26		%	30		%	29		%	30		%	40		%	26		%	23		%	29		%

The Company reported a loss before income taxes for the three and nine months ended September 30, ~~2016~~2017 and ~~2015. As a result, items that ordinarily increase or decrease the~~2016. The Company’s effective tax rate ~~will have~~is impacted each year by the ~~opposite effect. The decrease from~~relative pre-tax income (loss) earned by the ~~35%~~Company’s operations in the U.S., Algeria, and the rest of the world. Additionally, state income taxes (net of federal ~~statutory rate for the three and nine months ended September 30, 2016, was primarily attributable to the following decreases:~~

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

~~tax impact from foreign operations~~

~~non-deductible goodwill related to divestitures~~

~~adjustments to deferred tax balances~~

~~net changes in uncertain tax positions~~

~~These decreases were partially offset by the following increases:~~

•~~state taxes, net of federal benefit~~

•~~income attributable to noncontrolling interest~~

~~The decrease from the 35% U.S. federal statutory rate for the three and nine months ended September 30, 2015, was primarily attributable to~~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 ~~impact from foreign operations.~~

~~Net Income (Loss) Attributable to Noncontrolling Interests~~

Three Months Ended
September 30, Nine Months Ended
September 30,
millions except percentages 2016 2015 2016 2015
Net income (loss) attributable to noncontrolling interests $ 83
$ 75
$ 200
$ 154
Public ownership in WES, limited partnership interest 60.0 % 55.2 % 60.0 % 55.2 %
Public ownership in WGP, limited partnership interest 18.4 % 12.7 % 18.4 % 12.7 %

~~See~~rate. For additional information on income taxes, see Note ~~16—Noncontrolling Interests~~9—Income Taxesin the Notes to Consolidated Financial Statementsunder ~~Part I,~~ Item 1 of this Form 10-Q.

~~Table of Contents~~

LIQUIDITY AND CAPITAL RESOURCES


	Nine Months Ended September 30,						Nine Months Ended September 30,
millions	2016			2015			2017			2016
Net cash provided by (used in) operating activities	$	1,877		$	(2,134	)	$	2,619		$	1,877
Net cash provided by (used in) investing activities	(1,256		)	(3,696		)	(26		)	(1,256		)
Net cash provided by (used in) financing activities	2,421			534			(527		)	2,421

Overview As of September 30, 2016, Anadarko had $4.0 billion of cash on hand plus $5.0 billion of borrowing capacity under its revolving credit facilities. Cash on hand includes net proceeds of $2.16 billion from the Company’s September 2016 public offering of 40.5 million shares of its common stock. Additionally, Anadarko has entered into divestiture agreements that are expected to close in the fourth quarter for approximately $1.2 billion. Prior to year-end 2016, Anadarko plans to use approximately $1.8 billion of its cash on hand for the acquisition of certain Gulf of Mexico assets. In October 2016, the Company provided notice of its intent to redeem its remaining $750 million of 6.375% Senior Notes due September 2017 prior to year end.

Anadarko believes that its cash on hand, anticipated operating cash flows, and proceeds from expected future asset monetizations will be sufficient to fund the Company’s projected 2016 operational and capital programs, the acquisition of certain assets in the Gulf of Mexico, and the redemption of its $750 million 2017 debt maturities in the fourth quarter of 2016. In addition, the Company has available borrowing capacity to supplement its working capital needs. The Company ~~continuously monitors its liquidity needs and evaluates available funding alternatives in light of current and expected conditions. Anadarko~~ has a variety of funding sources available, including cash, ~~on hand,~~ an asset portfolio that provides ongoing cash-flow-generating capacity, opportunities for liquidity enhancement through divestitures and joint-venture arrangements that reduce future capital expenditures, ~~and~~ the Company’s credit ~~facilities.~~facilities, and access to both debt and equity capital markets. In addition, an effective registration statement is available to Anadarko covering the sale of WGP common units owned by the Company.

~~Effects~~ WGP and WES function with capital structures that are separate from Anadarko, consisting of ~~Moody’s Credit Rating Downgrade~~ ~~In February 2016, Standard~~their own debt instruments and Poor’s (S&P) affirmed Anadarko’s “BBB” long-term debt credit rating and changed the outlook from stable to negative. Later in February 2016, Moody’s Investors Service (Moody’s) lowered the Company’s long-term debt credit rating from “Baa2” to “Ba1,” which is below investment grade. In March 2016, Fitch Ratings affirmed Anadarko’s “BBB” long-term debt credit rating and changed the outlook from stable to negative. In September 2016, S&P and Moody’s changed the outlook from negative to stable.publicly traded common units.

~~As a result~~Through September 2017, Anadarko received net proceeds of Moody’s downgrade of Anadarko’s credit rating to a level that is below investment grade, the Company’s credit thresholds with certain derivative counterparties were reduced and in some cases eliminated, which required the Company to increase the amount of collateral posted with derivative counterparties when the Company’s net trading position is a liability in excess of the contractual threshold. During the third quarter of 2016, Anadarko paid a fee in connection with the negotiated increase of a credit threshold for an interest-rate derivative with an other-than-insignificant financing element. As a result of the increased credit threshold, $200 million of collateral was returned$3.5 billion from divestitures, primarily related to the Company. 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 $1.4 billion (net of $422 million of collateral) at September 30, 2016, and $1.3 billion (net of $58 million of collateral) at December 31, 2015.

The Moody’s credit rating downgrade required Anadarko to post collateral in the form of letters of credit or cash as financial assurance of its performance under certain contractual arrangements such as pipeline transportation contracts and oil and gas sales contracts. The amount of letters of credit or cash provided as assurancesale of the Company’s ~~performance under these types~~Eagleford, Marcellus, Eaglebine, and Utah CBM assets. As of ~~contractual arrangements with respect to credit-risk-related contingent features was $274 million at~~ September 30, ~~2016,~~2017, Anadarko had $5.3 billion of cash plus $5.0 billion of borrowing capacity under its RCFs. Anadarko believes that its current available cash and ~~zero at December 31, 2015.~~

~~Also in February 2016, Moody’s downgraded Anadarko’s commercial paper program credit rating, which eliminated~~anticipated operating cash flows will be sufficient to fund the Company’s ~~access to~~remaining 2017 and projected long-term operational and capital programs as well as the ~~commercial paper market.~~Company’s $2.5 billion share-repurchase program announced by the Company in September 2017. The Company ~~has not issued commercial paper notes since the downgrade, but instead has used~~continuously monitors its ~~364-day senior unsecured revolving credit facility (364-Day Facility) for short-term working capital requirements, as needed.~~liquidity position and evaluates available funding alternatives in light of current and expected conditions.

~~Table of Contents~~

Operating Activities

One of the primary sources of variability in the Company’s cash flows from operating activities is the fluctuation in commodity prices, the impact of which Anadarko partially mitigates by periodically entering into commodity derivatives. Sales volume changes also impact cash flow but historically have not been as volatile as commodity prices. Anadarko’s cash flows from operating activities are also impacted by the costs related to operations and interest payments related to the Company’s outstanding debt.

~~Anadarko generated $1.9 billion of cash from~~Cash provided by operating activities ~~during~~was $2.6 billion for the nine months ended September 30, 2017, $742 million higher compared to the same period of 2016. This increase was primarily a result of higher sales revenues in 2017 due to the impact of higher commodity prices as well as the $159.5 million payment of the Clean Water Act penalty in 2016 ~~which included~~and $217 million related to severance costs and retirement benefits paid in 2016 in connection with the workforce reduction program. These increases were partially offset by an $881 million tax refund received in 2016 related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback, the payment of $217 million related to severance costs and retirement benefits in connection with the workforce reduction program, and the $159.5 million payment of a Clean Water Act (CWA) penalty. Cash used in operating activities for the same period of 2015 was $2.1 billion, which included the $5.2 billion Tronox settlement payment. Excluding the impact of the tax refund, payments for the CWA penalty, severance costs and retirement benefits, and the Tronox settlement, operating cash flows for the nine months ended September 30, 2016, decreased by $1.7 billion primarily due to decreased sales revenues as a result of lower commodity prices.carryback.

Investing Activities

Capital Expenditures Anadarko currently estimates a 2017 capital spending range of $5.0 billion to $5.25 billion, which includes WES capital spending of approximately $800 million to $850 million. These capital spending estimates represent decreases of more than 5% for Anadarko and 10% for WES from the initial 2017 estimates. The Company has currently allocated approximately 80% of its 2017 capital spending budget to the U.S. onshore upstream and midstream and deepwater Gulf of Mexico development; 15% to future value areas, such as deepwater exploration and Mozambique LNG; 2% to international cash generation assets in Algeria and Ghana; and 3% to corporate activities. The Company’s 2017 capital program was designed to leverage its streamlined portfolio and sharpened focus on higher-margin oil production.

The following presents the Company’s capital expenditures for the nine months ended September 30:


millions	2016			2015			2017		2016
Cash Flows from Investing Activities
Additions to properties and equipment ⁽¹⁾	$	2,618		$	4,861		$	3,538	$	2,618
Adjustments for capital expenditures
Changes in capital accruals	(300		)	(315		)	237		(300		)
Other	3			29			21		3
Total capital expenditures ⁽²⁾	$	2,321		$	4,575		$	3,796	$	2,321

Exploration and Production and other capital expenditures							$	2,877	$	1,921
Midstream capital expenditures - Anadarko ⁽³⁾							258		45
Midstream capital expenditures - WES							661		355

________________________________________________________________________________________


⁽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 $355 million for the nine months ended September 30, 2016, and $405 million for the nine months ended September 30, 2015.~~ Capital expenditures exclude the FPSO capital lease ~~asset, see Financing Activities~~asset.


—~~Capital Lease Obligations~~ ~~below.~~⁽³⁾	Excludes WES.

The Company’s capital expenditures ~~decreased~~increased by ~~$2.3~~$1.5 billion for the nine months ended September 30, ~~2016, as reduced~~2017. Exploration and Production capital expenditures increased primarily due to increased development ~~and exploration~~costs of $694 million driven by U.S. onshore drilling activity ~~resulted~~primarily in the ~~following:~~

Delaware and DJ basins and increased exploration costs of $281 million primarily due to exploration drilling in the Gulf of Mexico and $216 million primarily driven by U.S. onshore acreage acquisitions, partially offset by decreased development costs of ~~$1.7 billion~~$220 million driven by the TEN development project in Ghana, which achieved first oil in the third quarter of 2016. Midstream capital expenditures increased primarily due to $306 million related to the development of WES midstream assets primarily in ~~U.S. onshore~~

~~decreased exploration costs~~the Delaware and DJ basins and $213 million related to the development of ~~$273 million~~APC midstream assets primarily in ~~Colombia~~the Delaware basin.

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 ~~Mozambique~~

~~decreased gathering, processing,~~$155 million in cash. WES funded the cash consideration with cash on hand and ~~other costs~~recognized a gain of ~~$267~~$126 million ~~primarily~~ as a result of this transaction. After the acquisition, the DBJV system is 100% owned by WES and consolidated by Anadarko. See Note 3—Acquisitions, Divestitures, and Assets Held for Salein ~~U.S. onshore~~the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Carried-Interest ArrangementsIn the third quarter of 2014, the Company entered into a carried-interest arrangement that ~~requires~~required a third party to fund $442 million of Anadarko’s capital costs in exchange for a 34% working interest in the Company’s Eaglebine development, located in Southeast Texas. The ~~third-party funding is expected to cover Anadarko’s future capital costs in the development through 2020. At September 30, 2016, $147 million~~carry was canceled as part of the ~~$442 million carry obligation had been funded.~~

Insale of the Eaglebine assets in the second quarter of 2013, the Company entered into a carried-interest arrangement that requires a third party to fund $860 million of Anadarko’s capital costs in exchange for a 12.75% working interest in the Heidelberg development, located in the Gulf of Mexico. At September 30, 2016, the entire $860 million carry obligation had been funded.

~~Table of Contents~~

~~Acquisition~~ In September 2016, the Company entered into an agreement to acquire certain oil and gas assets in the Gulf of Mexico for $2.0 billion using a portion of the net proceeds from the September 2016 equity issuance. The acquisition is expected to close in the fourth quarter of 2016 and is subject to customary closing conditions. See ~~Note 14—Stockholders’ Equity~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Part I, Item 1 of this Form 10-Q.~~2017.

Divestitures During the nine months ended September 30, ~~2016,~~2017, Anadarko received net proceeds of ~~$1.3~~$3.5 billion from divestitures, primarily related to the ~~divestitures~~sale of ~~certain U.S. onshore assets in Wyoming, East Texas/Louisiana,~~the Company’s Eagleford, Marcellus, Eaglebine, and ~~West Texas.~~Utah CBM assets. See Note 3—Acquisitions, Divestitures, and Assets Held for Sale in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

~~Investments~~ During the nine months ended September 30, 2016, the Company made capital contributions of $54 million for equity investments, which are included in other, net under Investing Activities in the Consolidated Statements of Cash Flows. These contributions were primarily associated with joint ventures for pipelines.

Financing Activities


millions except percentages	September 30, 2016			December 31, 2015			September 30, 2017			December 31, 2016
Anadarko							$	12,201		$	12,204
WES							3,344			3,091
WGP							28			28
Total debt	$	15,878		$	15,668		$	15,573		$	15,323
Total equity	15,912			15,457			13,922			15,497
Debt to total capitalization ratio	49.9		%	50.3		%	52.8		%	49.7		%

Debt Activity ~~The following summarizes the Company’s borrowing activity during the nine months ended September 30, 2016:~~

millions Face Value Description
Issuances $ 800
4.850% Senior Notes due 2021
1,100
5.550% Senior Notes due 2026
1,100
6.600% Senior Notes due 2046
500
WES 4.650% Senior Notes due 2026
Borrowings 1,750
364-Day Facility
600
WES RCF
28
WGP RCF
Repayments (1,750 ) 5.950% Senior Notes due 2016
(1,250 ) 6.375% Senior Notes due 2017
(1,750 ) 364-Day Facility
(880 ) WES RCF
(25 ) Tangible equity units (TEUs) - senior amortizing notes

~~Senior Notes~~ During the second quarter of 2016, the Company used proceeds from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.250 billion of its $2.0 billion 6.375% Senior Notes due September 2017 pursuant to a tender offer and to redeem its $1.750 billion 5.950% Senior Notes due September 2016. The Company recognized a loss of $124 million for the early retirement and redemption of these senior notes, which included $114 million of premiums paid.

In July 2016, WES completed a public offering of $500 million aggregate principal amount of 4.650% Senior Notes due July 2026. Net proceeds were used to repay a portion of the amount outstanding under the WES RCF.

~~Table of Contents~~

Anadarko ~~Revolving Credit Facilities~~RCFs Anadarko has a $3.0 billion ~~five-year senior unsecured revolving credit facility maturing~~RCF that matures in January 2021 ~~(Five-Year Facility)~~ and ~~the~~a $2.0 billion 364-Day Facility that matures in January ~~2017. During the nine months ended September 30, 2016, borrowings under the 364-Day Facility were primarily used for general short-term working capital needs.~~2018. At September 30, ~~2016,~~2017, the Company had no outstanding borrowings under the ~~Five-Year Facility~~APC RCF or the 364-Day Facility.

WES and WGP ~~Revolving Credit Facilities~~RCFs WES has a $1.2 billion RCF ~~which~~that matures in February 2020 and is expandable to $1.5 billion. During the nine months ended September 30, ~~2016,~~2017, WES ~~borrowings were primarily~~borrowed $250 million under its RCF, which was used for general ~~corporate purposes, including the funding of a portion of its acquisition of Springfield Pipeline LLC and capital expenditures.~~partnership purposes. At September 30, ~~2016,~~2017, WES had $250 million of outstanding borrowings under its RCF ~~of $20 million~~ at an interest rate of ~~1.82%~~2.54%, had outstanding letters of credit of $5 million, and had available borrowing capacity of ~~$1.18 billion.~~$945 million.

~~In March 2016,~~ WGP ~~entered into~~has a $250 million ~~three-year senior secured revolving credit facility maturing~~RCF that matures in March 2019 ~~(WGP RCF), which~~and is expandable to $500 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions. ~~During the nine months ended September 30, 2016, WGP borrowings were used to fund the purchase of WES common units.~~ At September 30, ~~2016,~~2017, WGP had outstanding borrowings under its RCF of $28 million at an interest rate of ~~2.53%~~3.24% and had available borrowing capacity of $222 million.

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

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

~~Capital Lease Obligations~~ Construction of the FPSO for the Company’s TEN field operations in Ghana commenced in 2013. The Company recognized an asset and related obligation during the construction period. Upon completion of the construction during the third quarter of 2016, the Company reported the asset and related obligation as a capital lease of $225 million for the Company’s share of the fair value of the FPSO. The Company expects to make the first payment related to the FPSO in the fourth quarter of 2016. At September 30, ~~2016,~~2017, Anadarko’s scheduled payments associated with capital lease obligations were $16 million during 2016 and $42 million during 2017. Principal payments related to capital lease obligations are reported in financing activities and interest payments related to capital lease obligations are reported in operating activities on the Company’s Consolidated Statement of Cash Flows. See ~~Note 8—Debt and Interest Expensein the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Part I, Item 1 of this Form 10-Q for additional information.~~

~~Debt Maturities~~ Anadarko may from time to time seek to retire or purchase its outstanding debt through cash purchases and/or exchanges for other debt or equity securities in open market purchases, privately negotiated transactions, or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions, and other factors. The amounts involved may be material.

~~At September 30, 2016, Anadarko’s~~remaining scheduled debt maturities during ~~2016~~2017 consisted of $8$9 million of senior amortizing notes associated with the TEUs. At September 30, ~~2016,~~2017, Anadarko’s scheduled debt maturities during ~~2017~~2018 consisted of ~~$34~~$17 million of senior amortizing notes associated with the TEUs and ~~$750~~$114 million of ~~6.375%~~7.05% Debentures due May 2018. In addition, WES has a scheduled debt maturity during 2018 of $350 million of 2.60% Senior Notes due ~~September 2017. The Company provided notice in October 2016 of its intent to redeem the 6.375%~~August 2018.

WES’s $350 million 2.60% Senior Notes due August 2018 were classified as long-term debt on the Company’s Consolidated Balance Sheet at September 30, 2017, ~~during~~as WES has the ~~fourth quarter~~ability and intent to refinance these obligations using ~~cash on hand.~~ long-term debt.

Anadarko’s ~~Zero-Coupon Senior Notes due 2036 (Zero Coupons)~~Zero Coupons can be put to the Company in October of each year, in whole or in part, for the then-accreted value of the outstanding Zero Coupons. None of the Zero Coupons ~~(accreted value of $839 million)~~ were put to the Company in October ~~2016.~~2017. The Zero Coupons can next be put to the Company in October ~~2017,~~2018, in whole or in part, for the then-accreted value of ~~$883~~$930 million.

For additional information on the Company’s debt instruments, ~~and capital lease obligations, such as transactions during the period, years of maturity, and interest rates,~~ seeNote 8—Debt ~~and Interest Expense~~ in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

~~Table~~Equity Transactions WES can issue common units to the public under its $500 million continuous offering program, which allows for an aggregate of ~~Contents~~

$500 million of WES common units.

Derivative Instruments For information on derivative instruments, including cash flow treatment, see Note 6—7—Derivative Instruments ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Part I, Item 1 of this Form 10-Q and~~ ~~Effects of Moody’s Credit Rating Downgrade~~ ~~above.~~

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

Common Stock Dividends Anadarko paid dividends ~~of $78 million~~ to its common stockholders ~~during the nine months ended September 30, 2016, and $415~~of $84 million during the nine months ended September 30, ~~2015.~~2017, and $78 million during the nine months ended September 30, 2016. In response to the commodity-price environment, ~~in February 2016,~~ the ~~Board~~Company decreased the ~~Company’s~~ quarterly dividend from $0.27 per share to $0.05 per ~~share.~~share in February 2016. Anadarko has paid a dividend to its common stockholders ~~on a~~ quarterly ~~basis~~ since becoming a public company in 1986.

The amount of future dividends paid to Anadarko common stockholders ~~will be~~is determined by the Board on a quarterly basis and is based on the Company’s earnings, financial ~~conditions,~~condition, capital requirements, the effect a dividend payment would have on the Company’s compliance with relevant financial covenants, and other factors deemed relevant by the Board.

~~Equity Transactions~~ In September 2016, Anadarko completed a public offering of 40.5 million shares of its common stock for net proceeds of $2.16 billion. Net proceeds will primarily be used to fund the acquisition of certain Gulf of Mexico assets, which is expected to close in the fourth quarter of 2016. The remaining net proceeds will be used for general corporate purposes.

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

Distributions to Noncontrolling Interest Owners ~~WES distributed~~Distributions to ~~its unitholders other than Anadarko and WGP an aggregate of $192 million during~~noncontrolling interest owners primarily relate to the following for the nine months ended September 30, 2016, and $170 million during the nine months ended September 30, 2015. WES has made quarterly distributions to its unitholders since its initial public offering (IPO) in the second quarter of 2008, and has increased its distribution from $0.30 per common unit for the third quarter of 2008 to $0.845 per common unit for the third quarter of 2016 (to be paid in November 2016).30:

For the three months ended September 30, 2016, the WES Series A Preferred unitholders will receive a quarterly distribution of $0.68 per unit for the Series A Preferred units issued in March 2016 and April 2016, or an aggregate $15 million (to be paid in November 2016). For the three months ended June 30, 2016, the WES Series A Preferred unitholders received a quarterly distribution of $0.68 per unit for the Series A Preferred units issued in March 2016, and a quarterly distribution of $0.68 per unit for the Series A Preferred units issued in April 2016, prorated for the 77-day period the units were outstanding during the second quarter of 2016, or an aggregate $14 million (paid in August 2016). For the three months ended March 31, 2016, the WES Series A Preferred unitholders received a quarterly distribution of $0.68 per unit, prorated for the 18-day period the units were outstanding during the first quarter, or an aggregate $2 million (paid in May 2016).

WGP distributed to its unitholders other than Anadarko an aggregate of $41 million during the nine months ended September 30, 2016, and $27 million during the nine months ended September 30, 2015. WGP has made quarterly distributions to its unitholders since its IPO in December 2012, and has increased its distribution from $0.17875 per common unit for the first quarter of 2013 to $0.44750 per unit for the third quarter of 2016 (to be paid in November 2016).



millions	2017		2016
WES distributions to unitholders (excluding Anadarko and WGP) ⁽¹⁾	$	235	$	192
WES distributions to Series A Preferred unitholders ⁽²⁾	22		16
WGP distributions to unitholders (excluding Anadarko) ⁽³⁾	60		41


⁽¹⁾	WES has made quarterly distributions to its unitholders since its IPO in the second quarter of 2008 and has increased its distribution from $0.30 per common unit for the third quarter of 2008 to $0.905 per common unit for the third quarter of 2017 (to be paid in November 2017).


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


⁽³⁾	WGP has made quarterly distributions to its unitholders since its IPO in December 2012 and has increased its distribution from $0.17875 per common unit for the first quarter of 2013 to $0.53750 per unit for the third quarter of 2017 (to be paid in November 2017).

RECENT ACCOUNTING DEVELOPMENTS

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Company’s primary market risks are attributable to fluctuations in energy prices and interest rates. These risks can affect revenues and cash flows, and the Company’s risk-management policies provide for the use of derivative instruments to manage these risks. The types of commodity derivative instruments used by the Company include futures, swaps, options, and fixed-price physical-delivery contracts. The volume of commodity derivatives entered into by the Company is governed by risk-management policies and may vary from year to year. Both exchange and over-the-counter traded derivative instruments may be subject to margin-deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 6—7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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

Derivative Instruments Held for Non-Trading PurposesThe Company had derivative instruments in place to reduce the price risk associated with future production of 8 MMBbls of oil ~~354~~and 170 Bcf of natural gas ~~and 1 MMBbls of NGLs~~ at September 30, ~~2016~~,2017, with a net derivative asset position of ~~$41~~$9 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by ~~$89~~$34 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by ~~$86~~$36 million. However, any cash received or paid to settle these derivatives would be substantially offset by the sales value of production covered by the derivative instruments.

Derivative Instruments Held for Trading PurposesAt September 30, ~~2016~~,2017, the Company had a net derivative asset position of $8$3 million on outstanding derivative instruments entered into for trading purposes. Based on actual derivative contractual volumes, a 10% increase or decrease in underlying commodity prices would not materially impact the Company’s gains or losses on these derivative instruments.

INTEREST-RATE RISKBorrowings, if any, under each of the 364-Day Facility, the ~~Five-Year Facility,~~APC RCF, the WES RCF, and the WGP RCF are subject to variable interest rates. The balance of Anadarko’s long-term debt on the Company’s Consolidated Balance Sheets has fixed interest rates. The Company has $2.9 billion of LIBOR-based obligations ~~based on the London Interbank Offered Rate (LIBOR)~~ that are presented on the Company’s Consolidated Balance Sheets net of preferred investments in two noncontrolled entities. These obligations give rise to minimal net interest-rate risk because coupons on the related preferred investments are also LIBOR-based. While a 10% change in LIBOR would not materially impact the Company’s interest cost, it would affect the fair value of outstanding fixed-rate debt.

At September 30, ~~2016~~,2017, the Company had a net derivative liability position of ~~$1.8~~$1.4 billion related to interest-rate swaps. A 10% increase (decrease) in the three-month LIBOR interest-rate curve would decrease (increase) the aggregate fair value of outstanding interest-rate swap agreements by ~~$70~~$88 million. However, any change in the interest-rate derivative gain or loss could be substantially offset by changes in actual borrowing costs associated with future debt issuances. For a summary of the Company’s outstanding interest-rate derivative positions, see Note 6—7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (Exchange Act). The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and to ensure that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of September 30, ~~2016~~.2017.

Changes in Internal Control over Financial Reporting

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

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

WGR Operating, LP, a wholly owned subsidiary of the Company, is currently in negotiations with the ~~U.S. Environmental Protection Agency and the state of Wyoming~~EPA with respect to alleged noncompliance with the leak detection and repair requirements of the Clean Air Act at its Granger, Wyoming facilities. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.

Anadarko E&P Onshore LLC, a wholly owned subsidiary of the Company, is currently in negotiations with the Pennsylvania Department of Environmental Protection concerning enforcement over a produced water release in Pennsylvania in 2015. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.

Kerr-McGee Oil and Gas Onshore, LP, a wholly owned subsidiary of the Company, is currently in negotiations with the State of Colorado’s Department of Public Health and Environment with respect to alleged noncompliance with the Colorado Air Quality Control Commission’s Regulations. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.

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

The Company is currently in negotiations with the EPA with respect to alleged violations of the Resource Conservation and Recovery Act at certain facilities in the Gulf of Mexico. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.

See Note ~~11—~~10—Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q, which is incorporated herein by reference, for a discussion of material ~~developments with respect to~~legal matters ~~previously reported in~~that have arisen since the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2015~~2016.~~, and material matters that have arisen since the filing of such report.~~

Item 1A. Risk Factors

~~Consider carefully~~There have been no material changes from the risk factors ~~included below, as well as those~~ included under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2015.~~2016.

~~The pending completion of the acquisition~~of~~certain assets in the Gulf of Mexico from an unaffiliated third party for $2.0 billion is subject to a number of conditions, and we may not be able to consummate it if such conditions are not met.~~

We expect to close the acquisition of certain assets in the Gulf of Mexico in the fourth quarter of 2016. However, the completion of the acquisition is subject to a number of conditions, and we may not be able to consummate it if such conditions are not met. Upon termination of the purchase agreement for willful breach by us or failure to close as of an outside termination date, the seller has the option to receive a $100 million liquidated damages payment or seek all remedies available at law, including specific performance. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—~~Liquidity and Capital Resources~~—~~Investing Activities~~—~~Acquisition” for more information regarding the acquisition.~~

~~Risks related to the assets to be acquired in the pending Gulf of Mexico acquisition, if consummated, may adversely affect our business, financial condition and results of operation.~~

~~Any acquisition, including the pending acquisition of certain assets in the Gulf of Mexico, involves potential risks, including, among other things:~~

~~the validity of our assumptions about, among other things, reserves, estimated production, revenues, capital expenditures, operating expenses, and costs;~~

~~the assumption of environmental and other unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;~~

~~an inability to obtain satisfactory title to the assets we acquire;~~

~~the diversion of management’s attention from other business concerns;~~

~~the inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;~~

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~~the incurrence of significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;~~

~~increased cost of transportation of production to markets;~~

~~significant costs associated with the acquisition and subsequent integration efforts; and~~

~~a failure to attain or maintain compliance with environmental and other governmental regulations.~~

If we consummate the acquisition and if any of these risks were to materialize, the benefits of the acquisition may not be fully realized, if at all, and our business, financial condition, and results of operations could be negatively impacted.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following sets forth information with respect to repurchases by the Company of its shares of common stock during the third quarter of ~~2016~~:2017:

Period
Total number of shares purchased ⁽¹⁾
Average price paid per share Total number of shares purchased as part of publicly announced plans or programs Approximate dollar value of shares that may yet be purchased under the plans or programs
July 1 - 31, 2016 21,897
$ 53.60
—
$ —
August 1 - 31, 2016 2,294
$ 53.79
—
$ —
September 1 - 30, 2016 4,741
$ 58.47
—
$ —
Total 28,932
$ 54.41
—
$ —



Period	Total number of shares purchased ⁽¹⁾	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs	Approximate dollar value of shares that may yet be purchased under the plans or programs ⁽²⁾
July 1 - 31, 2017	4,369	$	44.80	—	$	—
August 1 - 31, 2017	2,304	$	44.69	—	$	—
September 1 - 30, 2017	1,158	$	40.92	—	$	2,500,000,000
Total	7,831	$	44.20	—

____________________________________________________________


⁽¹⁾	During the third quarter of ~~2016~~,2017, (i) no shares were purchased under the Company’s share-repurchase program and (ii) all shares 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.


⁽²⁾	On September 20, 2017, the Company announced a share-repurchase program to purchase up to $2.5 billion in shares of common stock. The program is authorized to extend through the end of 2018. In October 2017, the Company entered into the ASR Agreement to complete $1.0 billion of the share-repurchase program prior to the end of 2017.

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Item 6. Exhibits

Exhibits designated by an asterisk (*) are filed herewith or double asterisk (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing under File Number 1-8968 as indicated.



Exhibit Number			Description
	3	(i)	Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated May 21, 2009, filed as Exhibit 3.3 to Form 8-K filed on May 22, 2009
		(ii)	By-Laws of Anadarko Petroleum Corporation, amended and restated as of September 15, 2015, filed as Exhibit 3.1 to Form 8-K filed on September 21, 2015
*	10	~~(i)~~	~~Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as Amended and Restated Effective as of May 10, 2016, Stock Option Award Agreement~~
*		~~(ii)~~	~~Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as Amended and Restated Effective as of May 10, 2016, Restricted Stock Unit Award Agreement~~
*		~~(iii)~~	~~Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as Amended and Restated Effective as of May 10, 2016, Performance Unit Award Agreement~~
		~~(iv)~~	~~Form of Termination Agreement and Release of all Claims Under Officer Severance Plan, filed as Exhibit 10.1 to Form 8-K filed on August 24, 2016~~
*	31	(i)	Rule 13a-14(a)/15d-14(a) Certification—Chief Executive Officer
*	31	(ii)	Rule 13a-14(a)/15d-14(a) Certification—Chief Financial Officer
**	32		Section 1350 Certifications
*	101	.INS	XBRL Instance Document
*	101	.SCH	XBRL Schema Document
*	101	.CAL	XBRL Calculation Linkbase Document
*	101	.DEF	XBRL Definition Linkbase Document
*	101	.LAB	XBRL Label Linkbase Document
*	101	.PRE	XBRL Presentation Linkbase Document

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



		ANADARKO PETROLEUM CORPORATION
		(Registrant)

October 31, ~~2016~~2017	By:	/s/ ROBERT G. GWIN
		Robert G. Gwin Executive Vice President, Finance and Chief Financial Officer

6255



	Three Months Ended				Nine Months Ended
millions	Impairment		Fair Value⁽¹⁾		Impairment		Fair Value⁽¹⁾
September 30, 2016
Oil and gas exploration and production
Long-lived assets held for use
U.S. onshore properties	$	23	$	32	$	27	$	617
Gulf of Mexico properties	—		—		2		—
Cost-method investment ⁽²⁾	—		—		2		32
Midstream
Long-lived assets held for use	3		—		24		5
Other
Long-lived assets held for use	1		—		6		—
Total	$	27	$	32	$	61	$	654

September 30, 2015
Oil and gas exploration and production
Long-lived assets held for use
U.S. onshore properties	$	641	$	634	$	2,944	$	1,904
Gulf of Mexico properties	101		94		126		94
Cost-method investment ⁽²⁾	1		32		2		32
Midstream
Long-lived assets held for use	15		7		499		209
Total	$	758	$	767	$	3,571	$	2,239



	2016 Settlement		2017 Settlement		2018 Settlement
Oil
Three-Way Collars (MBbls/d)	83		—		—
Average price per barrel
Ceiling sold price (call)	$	63.82	$	—	$	—
Floor purchased price (put)	$	54.46	$	—	$	—
Floor sold price (put)	$	42.77	$	—	$	—
Natural Gas
Three-Way Collars (thousand MMBtu/d)	—		682		250
Average price per MMBtu
Ceiling sold price (call)	$	—	$	3.60	$	3.54
Floor purchased price (put)	$	—	$	2.75	$	2.75
Floor sold price (put)	$	—	$	2.00	$	2.00
Fixed-Price Contracts (thousand MMBtu/d)	—		37		—
Average price per MMBtu	$	—	$	3.14	$	—
NGLs
Fixed-Price Contracts (MBbls/d)	—		2		—
Average price per barrel	$	—	$	15.84	$	—



	Carrying Value
millions	WES			WGP ⁽¹⁾		Anadarko ⁽²⁾			Anadarko Consolidated			Description
Balance at December 31, 2015	$	2,691		$	—	$	12,957		$	15,648
Issuances	—			—		794			794			4.850% Senior Notes due 2021
	—			—		1,088			1,088			5.550% Senior Notes due 2026
	—			—		1,088			1,088			6.600% Senior Notes due 2046
	495			—		—			495			WES 4.650% Senior Notes due 2026
Borrowings	—			—		1,750			1,750			364-Day Facility
	600			—		—			600			WES RCF
	—			28		—			28			WGP RCF
Repayments	—			—		(1,749		)	(1,749		)	5.950% Senior Notes due 2016
	—			—		(1,245		)	(1,245		)	6.375% Senior Notes due 2017
	—			—		(1,750		)	(1,750		)	364-Day Facility
	(880		)	—		—			(880		)	WES RCF
	—			—		(250		)	(250		)	Commercial paper notes, net
	—			—		(25		)	(25		)	TEUs - senior amortizing notes
Other, net	1			—		40			41			Amortization of discounts, premiums, and debt issuance costs
Balance at September 30, 2016	$	2,907		$	28	$	12,698		$	15,633



millions
2017	$	50
2018	50
2019	52
2020	56
2021	57
Later years	263
Total	$	528



millions	Total Expected Costs		Three Months Ended September 30, 2016		Nine Months Ended September 30, 2016
Costs by category
Cash severance	$	154	$	5	$	151
Retirement benefits ⁽¹⁾	219		102		178
Share-based compensation	37		5		34
Total	$	410	$	112	$	363



millions	2016
Balance at January 1	$	—
Accruals	151
Payments	(141		)
Balance at September 30	$	10



millions	Interest-rate Derivatives Previously Subject to Hedge Accounting			Pension and Other Postretirement Plans			Total
Balance at December 31, 2015	$	(42	)	$	(341	)	$	(383	)
Other comprehensive income (loss), before reclassifications	—			(219		)	(219		)
Reclassifications to Consolidated Statement of Income	4			80			84
Balance at September 30, 2016	$	(38	)	$	(480	)	$	(518	)



millions	Face Value			Description
Issuances	$	800		4.850% Senior Notes due 2021
	1,100			5.550% Senior Notes due 2026
	1,100			6.600% Senior Notes due 2046
	500			WES 4.650% Senior Notes due 2026
Borrowings	1,750			364-Day Facility
	600			WES RCF
	28			WGP RCF
Repayments	(1,750		)	5.950% Senior Notes due 2016
	(1,250		)	6.375% Senior Notes due 2017
	(1,750		)	364-Day Facility
	(880		)	WES RCF
	(25		)	Tangible equity units (TEUs) - senior amortizing notes