

		Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

EXCHANGE ACT OF 1934

For the quarterly period ended ~~September 30, 2018~~March 31, 2019

[ ] 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 every Interactive Data File required to be submitted 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 such files). Yes þ No ¨

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

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~~Securities registered pursuant to Section 12(b) of the ~~Company’s common stock at October 18, 2018, is shown below:~~Act:



Title of each class	Trading symbol	Name of each exchange on which registered	Number of shares outstanding of the Company’s common stock at May 3, 2019
Common Stock, par value $0.10 per share	APC	New York Stock Exchange	502,118,789



		Table of Contents



~~Title of Class~~TABLE OF CONTENTS	~~Number of Shares Outstanding~~Page
~~Common Stock, par value $0.10 per share~~		~~504,280,902~~

~~TABLE OF CONTENTS~~



PART I		~~Page~~
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~	46
	Consolidated Statements of Comprehensive Income for the Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~	57
	Consolidated Balance Sheets at ~~September 30, 2018,~~March 31, 2019, and December 31, ~~2017~~2018	68
	Consolidated ~~Statement~~Statements of Equity for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2019 and 2018	79
	Consolidated Statements of Cash Flows for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~	810
	Notes to Consolidated Financial Statements	911
	Note 1—Summary of Significant Accounting Policies	911
	Note 2—Revenue from Contracts with Customers	1213
	Note 3—Commodity Inventories	1614
	Note 4—Divestitures	15
	Note 5—Suspended Exploratory Well Costs	15
	Note 6—Current Liabilities	15
	Note 7—Derivative Instruments	16
	Note ~~5—Impairments~~8—Debt	17
	~~Note 6—Suspended Exploratory Well Costs~~	17
	~~Note 7—Current Liabilities~~	18
	~~Note 8—Derivative Instruments~~	1821
	Note 9—~~Tangible Equity Units~~Leases	2423
	Note 10—~~Debt~~Income Taxes	2426
	Note 11—~~Income Taxes~~Contingencies	27
	Note 12—~~Contingencies~~Pension Plans and Other Postretirement Benefits	27
	Note 13—Stockholders’ Equity	28
	Note ~~13—Pension Plans and Other Postretirement Benefits~~14—Noncontrolling Interests	29
	Note ~~14—Stockholders’ Equity~~15—Variable Interest Entities	30
	Note ~~15—Noncontrolling Interests~~16—Supplemental Cash Flow Information	32
	~~Note 16—Variable Interest Entities~~	3331
	Note 17—~~Supplemental Cash Flow Information~~	35
	~~Note 18—~~Segment Information	3632
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
	~~Cautionary Statement About Forward-Looking Statements~~	3935
	Management Overview	4136
	Financial Results	4338
	Liquidity and Capital Resources	5449
	Recent Accounting Developments	5752
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5853
Item 4.	Controls and Procedures	5954

PART II

Item 1.	Legal Proceedings	6055
Item 1A.	Risk Factors	6156
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	6258
Item 6.	Exhibits	6359



		Table of Contents

COMMONLY USED TERMS AND DEFINITIONS

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

364-Day Facility - Anadarko’s $2.0 billion 364-day senior unsecured RCF that expired in January 2019

APC RCF - Anadarko’s $3.0 billion senior unsecured RCF

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

ASU- Accounting Standards Update

Bcf - Billion cubic feet

Board - The Board of Directors of Anadarko

BOE - Barrels of oil equivalent

~~CBM~~Chevron - ~~Coalbed methane~~Chevron Corporation

~~DBJV~~Chevron Merger - ~~Delaware Basin JV Gathering LLC~~Chevron’s acquisition by merger of Anadarko pursuant to, and subject to the conditions of, the Chevron Merger Agreement

~~DBJV System~~Chevron Merger Agreement - ~~A gathering system~~Agreement and ~~related facilities located in the Delaware basin in Loving, Ward, Winkler,~~Plan of Merger, dated as of April 11, 2019, by and ~~Reeves Counties in West Texas~~

~~DBM Complex~~ ~~- The processing plants, gas gathering system,~~among Chevron Corporation, Justify Merger Sub 1 Inc., Justify Merger Sub 2 Inc. 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~~Anadarko

DD&A - Depreciation, depletion, and amortization

DJ - Denver-Julesberg

DJ Basin Complex - The Platte Valley system, Wattenberg system, ~~and~~ Lancaster plant, ~~which were combined into a single complex in Colorado in the first quarter of 2014 to serve production in the DJ basin~~and Wattenberg processing plant

FID- Final investment decision

Fitch- Fitch Ratings

FPSO - Floating production, storage, and offloading unit

G&A - General and administrative expenses

~~IRS~~ ~~- Internal Revenue Service~~

IPO - Initial public offering

IRS - U.S. Internal Revenue Service

LIBOR - London Interbank Offered Rate

LNG - Liquefied natural gas

LPG - Liquefied petroleum gas

MBbls/d - Thousand barrels per day

MBOE/d- Thousand barrels of oil equivalent per day

Mcf - Thousand cubic feet

MMBbls- Million barrels

MMBOE- Million barrels of oil equivalent

~~MMBtu~~ ~~- Million British thermal units~~

~~MMBtu/d~~ ~~- Million British thermal units per day~~

MMcf/d- Million cubic feet per day

Moody’s - Moody’s Investors Service

~~N/A~~MTPA- ~~Not applicable~~Million tonnes per annum

NGL or NGLs - ~~Natural gas~~Natural-gas liquids

NMNYMEX ~~- Not meaningful~~

~~NTSB~~ ~~- National Transportation Safety Board~~

~~NYMEX~~ - New York Mercantile Exchange

~~Oil~~ NYSE- New York Stock Exchange

Oil-Includes crude oil and condensate

Occidental - Occidental Petroleum Corporation

Occidental Proposal - On April 24, 2019, Occidental announced a proposal to acquire Anadarko and further revised its proposal on May 5, 2019. All references herein to the Occidental Proposal refer to the Occidental Proposal as revised and received by Anadarko on May 5, 2019.

RCF - Revolving credit facility

~~ROTF~~ROU - ~~Regional oil treating facility~~Right-of-use

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S&P - Standard and Poor’s

Share-Repurchase Program - A program authorizing the repurchase of Anadarko’s common stock

~~Tax Reform Legislation~~ ~~- The U.S. Tax Cuts and Jobs Act signed into law on December 22, 2017~~

TEN - Tweneboa/Enyenra/Ntomme

TEU or TEUs - Tangible equity units

Tronox - Tronox Incorporated

VIE or VIEs- Variable interest entity

WES- Western ~~Gas~~Midstream Partners, LP, a publicly traded limited partnership, ~~which~~ is a consolidated subsidiary of Anadarko, with its common units traded on the NYSE under ticker symbol “WES”. WES consolidates Western Midstream Operating, LP. Prior to February 28, 2019, WES was known as Western Gas Equity Partners, LP, and its common units traded on the NYSE under ticker symbol “WGP”.

WES 364-Day Facility - WES Operating’s $2.0 billion 364-day senior unsecured credit facility

WES Merger - A merger, which was completed on February 28, 2019, whereby a wholly owned subsidiary of WES merged with and into WES Operating.

WES Operating - Western Midstream Operating, LP, a Delaware limited partnership in which WES holds (a) a 98% limited partner interest and (b) the entire non-economic general partner interest through its ownership of WES Operating’s sole general partner. Prior to February 28, 2019, WES Operating was known as Western Gas Partners, LP, and its common units traded on the NYSE under ticker symbol “WES”. Upon completion of the WES Merger, WES Operating’s common units ceased trading on the NYSE.

WES RCF - ~~WES’s $1.5~~WES Operating’s $2.0 billion senior unsecured RCF

West Texas Complex - The DBM Complex and DBJV and Haley systems, all of which were combined into a single complex effective January 1, 2018.

WGP - Western Gas Equity Partners, LP, ~~a publicly traded limited partnership,~~ which ~~is a consolidated subsidiary of Anadarko~~changed its name to Western Midstream Partners, LP and began trading on the NYSE using the ticker symbol “WES” following the WES Merger.

WGP RCF- WGP’s $35 million senior secured RCF that matured in March 2019

WTI- West Texas Intermediate

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

~~PART I. FINANCIAL INFORMATION~~

3 | APC 2019 FORM 10-Q



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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, matters related to the Chevron Merger Agreement and the Occidental Proposal, 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 NGL 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 volume, pipeline throughput, and produced water disposal


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


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

–

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


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


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


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


–	the impact of changes in the Company’s credit ratings

APC 2019 FORM 10-Q | 4



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–	the Company’s ability to successfully plan, secure additional government and partner approvals, enter into additional long-term sales contracts, make a final investment decision and the timing thereof, finance, build, and operate the necessary infrastructure and LNG park in Mozambique


–	uncertainties and liabilities associated with acquired and divested properties and businesses


–	disruptions in international oil and NGL cargo shipping activities


–	physical, digital, internal, and external security breaches


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

–

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


–	the completion of a proposed merger transaction with Chevron or Occidental

–

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, 2018, this Form 10-Q, and in the Company’s other public filings, press releases, and discussions with Company management

5 | APC 2019 FORM 10-Q



	FINANCIAL STATEMENTS	Table of Contents

PART I

Item 1. Financial Statements

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended					Nine Months Ended					Three Months Ended
	September 30,					September 30,					March 31,
millions except per-share amounts	2018		2017			2018		2017			2019			2018
Revenues and Other
Oil sales	$	2,572	$	1,567		$	6,964	$	4,652		$	2,096		$	2,127
Natural-gas sales	232		269			682		1,090			320			247
Natural-gas liquids sales	382		265			992		768			240			292
Gathering, processing, and marketing sales	421		509			1,163		1,417			470			360
Gains (losses) on divestitures and other, net	90		(114		)	232		1,052			92			19
Total	3,697		2,496			10,033		8,979			3,218			3,045
Costs and Expenses
Oil and gas operating	294		253			845		738			289			276
Oil and gas transportation	228		220			633		698			222			196
Exploration	118		750			380		2,366			49			168
Gathering, processing, and marketing	256		396			745		1,101			256			237
General and administrative	248		261			814		768			267			278
Depreciation, depletion, and amortization	1,130		1,083			3,123		3,235			1,081			990
Production, property, and other taxes	246		159			637		449			199			190
Impairments	172		—			319		383			—			19
Other operating expense	26		123			188		157			21			140
Total	2,718		3,245			7,684		9,895			2,384			2,494
Operating Income (Loss)	979		(749		)	2,349		(916		)	834			551
Other (Income) Expense
Interest expense	240		230			705		682			253			228
(Gains) losses on derivatives, net	32		82			503		(33		)	313			35
Other (income) expense, net	24		5			16		51			6			(12		)
Total	296		317			1,224		700			572			251
Income (Loss) Before Income Taxes	683		(1,066		)	1,125		(1,616		)	262			300
Income tax expense (benefit)	256		(425		)	507		(366		)	166			126
Net Income (Loss)	427		(641		)	618		(1,250		)	96			174
Net income (loss) attributable to noncontrolling interests	64		58			105		182			111			53
Net Income (Loss) Attributable to Common Stockholders	$	363	$	(699	)	$	513	$	(1,432	)	$	(15	)	$	121

Per Common Share
Net income (loss) attributable to common stockholders—basic	$	0.72	$	(1.27	)	$	0.99	$	(2.60	)	$	(0.03	)	$	0.23
Net income (loss) attributable to common stockholders—diluted	$	0.72	$	(1.27	)	$	0.99	$	(2.61	)	$	(0.03	)	$	0.22
Average Number of Common Shares Outstanding—Basic	499		553			507		552			490			518
Average Number of Common Shares Outstanding—Diluted	500		553			508		552			490			519
Dividends (per common share)	$	0.25	$	0.05		$	0.75	$	0.15

See accompanying Notes to Consolidated Financial Statements.

APC 2019 FORM 10-Q | 6



	FINANCIAL STATEMENTS	Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
millions	2018			2017			2018			2017			2019			2018
Net Income (Loss)	$	427		$	(641	)	$	618		$	(1,250	)	$	96		$	174
Other Comprehensive Income (Loss)
Adjustments for derivative instruments
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	1			1			2			3			1			1
Income taxes on reclassification of previously deferred derivative losses	—			—			—			(1		)
Total adjustments for derivative instruments, net of taxes	1			1			2			2			1			1
Adjustments for pension and other postretirement plans
Net gain (loss) incurred during period	25			(14		)	25			1
Income taxes on net gain (loss) incurred during period	(6		)	5			(6		)	—
Amortization of net actuarial (gain) loss to other (income) expense, net	15			29			28			100			8			7
Income taxes on amortization of net actuarial (gain) loss	(4		)	(11		)	(7		)	(37		)	(2		)	(2		)
Amortization of net prior service (credit) cost to other (income) expense, net	(6		)	(7		)	(18		)	(19		)	(1		)	(6		)
Income taxes on amortization of net prior service (credit) cost	2			3			4			7			—			1
Total adjustments for pension and other postretirement plans, net of taxes	26			5			26			52			5			—
Total	27			6			28			54			6			1
Comprehensive Income (Loss)	454			(635		)	646			(1,196		)	102			175
Comprehensive income (loss) attributable to noncontrolling interests	64			58			105			182			111			53
Comprehensive Income (Loss) Attributable to Common Stockholders	$	390		$	(693	)	$	541		$	(1,378	)	$	(9	)	$	122

See accompanying Notes to Consolidated Financial Statements.

7 | APC 2019 FORM 10-Q



	FINANCIAL STATEMENTS	Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30,			December 31,			March 31,			December 31,
millions except per-share amounts	2018			2017			2019			2018
ASSETS
Current Assets
Cash and cash equivalents ($133 and $80 related to VIEs)	$	1,883		$	4,553
Accounts receivable (net of allowance of $11 and $14)
Customers ($159 and $106 related to VIEs)	1,644			1,222
Others ($15 and $19 related to VIEs)	547			607
Cash and cash equivalents ($100 and $92 related to VIEs)							$	2,026		$	1,295
Accounts receivable (net of allowance of $11 and $13)
Customers ($138 and $138 related to VIEs)							1,553			1,491
Others							512			535
Other current assets	397			380			338			474
Total	4,471			6,762			4,429			3,795
Net Properties and Equipment (net of accumulated depreciation, depletion, and amortization of $36,375 and $34,107) ($6,419 and $5,731 related to VIEs)	28,744			27,451
Other Assets ($801 and $579 related to VIEs)	2,292			2,211
Goodwill and Other Intangible Assets ($1,170 and $1,191 related to VIEs)	5,638			5,662
Net Properties and Equipment (net of accumulated depreciation, depletion, and amortization of $38,903 and $37,905) ($8,630 and $6,612 related to VIEs)							28,936			28,615
Other Assets ($1,246 and $868 related to VIEs)							3,006			2,336
Goodwill and Other Intangible Assets ($1,279 and $1,163 related to VIEs)							5,622			5,630
Total Assets	$	41,145		$	42,086		$	41,993		$	40,376

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable
Trade ($337 and $305 related to VIEs)	$	2,144		$	1,894
Other ($16 and $1 related to VIEs)	201			266
Trade ($196 and $263 related to VIEs)							$	1,946		$	2,003
Other ($6 and $15 related to VIEs)							165			161
Short-term debt - Anadarko⁽¹⁾	910			142			21			919
Short-term debt - WGP/WES	28			—
Current asset retirement obligations	332			294
Other current liabilities	1,502			1,310
Short-term debt - WES							2,000			28
Current asset retirement obligations ($23 and $26 related to VIEs)							277			252
Other current liabilities ($107 and $54 related to VIEs)							1,340			1,295
Total	5,117			3,906			5,749			4,658
Long-term Debt
Long-term debt - Anadarko⁽¹⁾	11,189			12,054			10,695			10,683
Long-term debt - WGP/WES	4,566			3,493
Long-term debt - WES							5,208			4,787
Total	15,755			15,547			15,903			15,470
Other Long-term Liabilities
Deferred income taxes	2,455			2,234			2,624			2,437
Asset retirement obligations ($158 and $143 related to VIEs)	2,538			2,500
Asset retirement obligations ($312 and $260 related to VIEs)							2,876			2,847
Other	4,043			4,109			4,308			4,021
Total	9,036			8,843			9,808			9,305

Equity
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 576.2 million and 574.2 million shares issued)	57			57
Common stock, par value $0.10 per share (1.0 billion shares authorized, 577.8 million and 576.6 million shares issued)							57			57
Paid-in capital	12,344			12,000			13,057			12,393
Retained earnings	1,291			1,109			1,024			1,245
Treasury stock (82.3 million and 43.4 million shares)	(4,608		)	(2,132		)
Treasury stock (87.5 million and 87.2 million shares)							(4,881		)	(4,864		)
Accumulated other comprehensive income (loss)	(383		)	(338		)	(329		)	(335		)
Total Stockholders’ Equity	8,701			10,696			8,928			8,496
Noncontrolling interests	2,536			3,094			1,605			2,447
Total Equity	11,237			13,790			10,533			10,943
Total Liabilities and Equity	$	41,145		$	42,086		$	41,993		$	40,376

Parenthetical references reflect amounts as of ~~September 30, 2018,~~March 31, 2019, and December 31, ~~2017.~~2018.

VIE amounts relate to ~~WGP and~~ WES. See Note ~~16—~~15—Variable Interest Entities.


⁽¹⁾	Excludes ~~WES and WGP.~~WES.

See accompanying Notes to Consolidated Financial Statements.

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	FINANCIAL STATEMENTS	Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED ~~STATEMENT~~STATEMENTS OF EQUITY

(Unaudited)


	Total Stockholders’ Equity																				Total Stockholders’ Equity
millions	Common Stock		Paid-in Capital			Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Non- controlling Interests			Total Equity			Common Stock		Paid-in Capital		Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)				Non- controlling Interests				Total Equity
Balance at December 31, 2017	$	57	$	12,000		$	1,109		$	(2,132	)	$	(338	)	$	3,094		$	13,790
Balance at December 31, 2018																					$	57	$	12,393	$	1,245		$	(4,864	)		$	(335	)		$	2,447		$	10,943
Net income (loss)	—		—			513			—			—			105			618			—		—		(15		)	—				—				111			96
Common stock issued	—		6			—			—			—			—			6
Share-based compensation expense	—		125			—			—			—			—			125			—		38		—			—				—				—			38
Dividends—common stock	—		—			(380		)	—			—			—			(380		)	—		—		(150		)	—				—				—			(150		)
Repurchases of common stock	—		—			—			(2,476		)	—			—			(2,476		)	—		—		—			(17		)		—				—			(17		)
Subsidiary equity transactions	—		(17		)	—			—			—			25			8			—		626		(1		)	—				—				(823		)	(198		)
Settlement of tangible equity units	—		230			—			—			—			(300		)	(70		)
Distributions to noncontrolling interest owners	—		—			—			—			—			(365		)	(365		)	—		—		—			—				—				(130		)	(130		)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	—		—			—			—			2			—			2
Adjustments for pension and other postretirement plans	—		—			—			—			26			—			26			—		—		—			—				5				—			5
Cumulative effect of accounting change ⁽¹⁾	—		—			49			—			(73		)	(23		)	(47		)	—		—		(55		)	—				—				—			(55		)
Balance at September 30, 2018	$	57	$	12,344		$	1,291		$	(4,608	)	$	(383	)	$	2,536		$	11,237
Other																					—		—		—			—				1				—			1
Balance at March 31, 2019																					$	57	$	13,057	$	1,024		$	(4,881	)		$	(329	)		$	1,605		$	10,533


⁽¹⁾	Beginning January 1, 2019, the Company adopted ASU 2016-02, Leases (Topic 842). See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements for further information.

~~__________________________________________________________________~~



	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, 2017	$	57	$	12,000		$	1,109		$	(2,132	)		$	(338	)		$	3,094		$	13,790
Net income (loss)	—		—			121			—				—				53			174
Share-based compensation expense	—		39			—			—				—				—			39
Dividends—common stock	—		—			(127		)	—				—				—			(127		)
Repurchases of common stock	—		(332		)	—			(1,627		)		—				—			(1,959		)
Subsidiary equity transactions	—		(6		)	—			—				—				9			3
Distributions to noncontrolling interest owners	—		—			—			—				—				(118		)	(118		)
Cumulative effect of accounting change ⁽¹⁾	—		—			49			—				(73		)		(23		)	(47		)
Other	—		—			—			—				1				—			1
Balance at March 31, 2018	$	57	$	11,701		$	1,152		$	(3,759	)		$	(410	)		$	3,015		$	11,756

⁽¹⁾

Beginning January 1, 2018, the Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. See Note 1—Summary of Significant Accounting Policies in the ~~Notes to Consolidated Financial Statements~~Company’s Annual Report on Form 10-K for ~~further information.~~the year ended December 31, 2018.

See accompanying Notes to Consolidated Financial Statements.

9 | APC 2019 FORM 10-Q



	FINANCIAL STATEMENTS	Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended						Three Months Ended
	September 30,						March 31,
millions	2018			2017			2019			2018
Cash Flows from Operating Activities
Net income (loss)	$	618		$	(1,250	)	$	96		$	174
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	3,123			3,235			1,081			990
Deferred income taxes	141			(1,026		)	1			42
Dry hole expense and impairments of unproved properties	212			2,144			—			106
Impairments	319			383			—			19
(Gains) losses on divestitures, net	(31		)	(815		)	5			24
Total (gains) losses on derivatives, net	506			(33		)	315			36
Operating portion of net cash received (paid) in settlement of derivative instruments	(433		)	21			1			(63		)
Other	224			227			42			74
Changes in assets and liabilities
(Increase) decrease in accounts receivable	(344		)	(32		)	(39		)	23
Increase (decrease) in accounts payable and other current liabilities	230			(95		)	(294		)	45
Other items, net	(263		)	(140		)	(79		)	(40		)
Net cash provided by (used in) operating activities	4,302			2,619			1,129			1,430
Cash Flows from Investing Activities
Additions to properties and equipment	(4,891		)	(3,538		)	(1,389		)	(1,547		)
Divestitures of properties and equipment and other assets	393			3,480			7			371
Other, net	(161		)	30			(146		)	63
Net cash provided by (used in) investing activities	(4,659		)	(28		)	(1,528		)	(1,113		)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	2,131			249			2,420			1,333
Repayments of debt	(1,176		)	(42		)	(935		)	(639		)
Financing portion of net cash received (paid) for derivative instruments	19			(160		)	(98		)	54
Increase (decrease) in outstanding checks	(13		)	(58		)	68			(26		)
Dividends paid	(380		)	(84		)	(150		)	(127		)
Repurchases of common stock	(2,476		)	(37		)	(17		)	(1,959		)
Issuances of common stock	6			—
Distributions to noncontrolling interest owners	(365		)	(327		)	(130		)	(118		)
Payments of future hard-minerals royalty revenues conveyed	(50		)	(50		)	(24		)	(25		)
Other financing activities	(2		)	(18		)
Other							(5		)	—
Net cash provided by (used in) financing activities	(2,306		)	(527		)	1,129			(1,507		)
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and restricted cash equivalents	(18		)	4			1			—
Net Increase (Decrease) in Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	(2,681		)	2,068			731			(1,190		)
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at Beginning of Period	4,674			3,308			1,429			4,674
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at End of Period	$	1,993		$	5,376		$	2,160		$	3,484

See accompanying Notes to Consolidated Financial Statements.

APC 2019 FORM 10-Q | 10



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~1. Summary of Significant Accounting Policies~~

1. Summary of Significant Accounting Policies

GeneralAnadarko Petroleum Corporation is engaged in the exploration, development, production, and sale of oil, natural gas, and NGLs and ~~in advancing~~is continuing to advance its Mozambique LNG project toward FID. In addition, the Company engages in gathering, compressing, treating, processing, and transporting of natural gas; gathering, stabilizing, and transporting of oil and NGLs; and gathering and disposing of produced water. The Company also participates in the hard-minerals business through royalty arrangements.

Basis of PresentationThe accompanying unaudited consolidated financial statements have been prepared in ~~accordance~~conformity with U.S. Generally Accepted Accounting Principles for interim financial information and the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain notes and other information have been condensed or omitted. The accompanying interim financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the Company’s consolidated financial statements. Certain prior-period amounts have been reclassified to conform to the current-period presentation. These interim financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2017.~~2018.

Chevron Merger On April 11, 2019, the Company entered into the Chevron Merger Agreement pursuant to which, and subject to the conditions of the agreement, all outstanding shares of Anadarko will be acquired by Chevron in a stock and cash transaction valued at $33 billion, or $65.00 per share, as of the announcement date. Under the terms of the Chevron Merger Agreement, Anadarko stockholders will receive 0.3869 of a share of Chevron common stock and $16.25 in cash for each Anadarko share. The transaction was approved by the Boards of Directors of both companies. On May 6, 2019, Anadarko announced that the Board unanimously determined that the Occidental Proposal constituted a “Superior Proposal” as defined in the Chevron Merger Agreement. Under the terms of the Occidental Proposal, Occidental would acquire Anadarko for consideration consisting of $59.00 in cash and 0.2934 of a share of Occidental common stock per share of Anadarko common stock. Anadarko has notified Chevron that (i) the Board has unanimously determined that the Occidental Proposal constitutes a "Superior Proposal" and (ii) after complying with its obligations to Chevron under the Chevron Merger Agreement, Anadarko intends to terminate the Chevron Merger Agreement in order to enter into a definitive merger agreement with Occidental in connection with the Occidental Proposal. Pursuant to the Chevron Merger Agreement, Chevron has the right, during the four business day period ending on May 10, 2019, which may be extended in accordance with the terms of the Chevron Merger Agreement, to propose revisions to the terms of the Chevron Merger Agreement, or to make another proposal. If Anadarko terminates the Chevron Merger Agreement in order to enter into a definitive agreement with respect to the Occidental Proposal, Anadarko will pay Chevron a $1.0 billion termination fee as required by the Chevron Merger Agreement. The Chevron Merger Agreement remains in effect unless and until terminated, and accordingly, the Board reaffirms its existing recommendation of the transaction with Chevron at this time. Either transaction would be subject to Anadarko stockholder approval, regulatory approvals, and other customary closing conditions.

Midstream Asset Sale and WES Merger On February 28, 2019, Anadarko completed the previously announced contribution and sale of substantially all of its midstream assets, which consisted of oil infrastructure assets in the DJ basin and oil and water infrastructure assets in the Delaware basin, to WES Operating for $4.0 billion, with $2.0 billion of cash proceeds and $2.0 billion in WES Operating common units. As a result, the Company will no longer report an Other Midstream segment and will now have two reporting segments: Exploration and Production and WES Midstream. Prior period amounts have been reclassified to conform to the current period’s presentation. See Note 17—Segment Informationfor information on the Company’s reporting segments.

Immediately after the asset contribution and sale, a wholly owned subsidiary of WES merged with and into WES Operating, with WES Operating continuing as the surviving entity and a subsidiary of WES, resulting in a simplified midstream structure. Under the terms of the WES Merger, WES acquired all of the outstanding publicly held common units of WES Operating and substantially all of the WES Operating common units owned by Anadarko and its affiliates. WES Operating survived as a partnership with no publicly traded equity, owned 98% by WES and 2% by Anadarko. WES Operating owns all the operating assets and equity investments of WES, is the borrower for all existing WES debt and is expected to be the borrower for all future debt. Anadarko maintains operating control of WES, with approximately 55.5% ownership of the combined entity.

11 | APC 2019 FORM 10-Q



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

1. Summary of Significant Accounting Policies (Continued)

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

Recently Adopted Accounting Standards~~ASU 2017-07,~~ ~~Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost~~, requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period and presentation of the remaining components of net benefit cost in a separate line item outside operating items. Additionally, only the service cost component of net benefit cost will be eligible for capitalization. The Company adopted 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 $107 million for 2017, including $94 million for the nine months ended September 30, 2017, were reclassified to other (income) expense, net, from G&A; oil and gas operating; gathering, processing, and marketing; and exploration expense.

~~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. The Company adopted this ASU using a retrospective approach on January 1, 2018. Adoption did not have a material impact on the Company’s consolidated financial statements. See Consolidated Statements of Cash Flows and ~~Note 17—Supplemental Cash Flow Informationfor additional information.~~

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~1. Summary of Significant Accounting Policies (Continued)~~

ASU ~~2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606), supersedes the revenue recognition requirements and industry-specific guidance under~~ ~~Revenue Recognition~~ (~~Topic 605)~~. Topic 606 requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company adopted Topic 606 on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. Under the modified retrospective method, prior-period financial positions and results will not be adjusted. The cumulative effect adjustment recognized in the opening balances included a reduction to total equity of $47 million. While the Company does not expect 2018 net earnings to be materially impacted by revenue recognition timing changes, Topic 606 requires certain changes to the presentation of revenues and related expenses beginning January 1, 2018. See ~~Note 2—Revenue from Contracts with Customers~~ ~~for additional information.~~ ~~The Company’s revenue recognition accounting policy effective January 1, 2018, is detailed below.~~

~~Exploration and Production~~—The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.

Contracts with customers have varying terms, including spot sales or month-to-month contracts, contracts with a finite term, and life-of-field contracts where all production from a well or group of wells is sold to one or more customers. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs. For natural gas and NGLs sold on our behalf by a processor, revenue is typically measured based on the price the processor receives for the sale, less certain costs withheld by the processor.

~~Revenues are recognized for the sale of Anadarko’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues.~~

The Company enters into buy/sell arrangements related to the transportation of a portion of its oil production. Under these arrangements, barrels are sold to a third party at a location-based contract price and subsequently repurchased by the Company at a downstream location. The difference in value between the sale and purchase price represents the transportation fee to move oil from the lease or certain gathering locations to more liquid markets. These arrangements are often required by private transporters. These buy/sell transactions are recorded net in oil and gas transportation expense in the Company’s Consolidated Statements of Income.

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~1. Summary of Significant Accounting Policies (Continued)~~

~~WES Midstream and Other Midstream~~—Anadarko provides gathering, compressing, treating, processing, stabilizing, transporting, and disposal services pursuant to a variety of contracts. Under these arrangements, the Company receives fees and/or retains a percentage of products or a percentage of the proceeds from the sale of the customer’s products. These revenues are included in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income. Payment is generally received from the customer in the month of service or the month following the service. Contracts with customers generally have initial terms ranging from 5 to 10 years.

Revenue is recognized for fee-based gathering and processing services in the month of service based on the volumes delivered by the customer. Revenues are valued based on the rate in effect for the month of service when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. The Company may charge additional service fees to customers for a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold) due to the significant upfront capital investment. These fees are recognized as revenue over the expected period of customer benefit, generally the life of the related properties. Deficiency fees, which are charged to the customer if they do not meet minimum delivery requirements, are recognized over the performance period based on an estimate of the deficiency fees that will be billed upon completion of the performance period.

The Company’s midstream business also purchases natural-gas volumes from producers at the wellhead or production facility, typically at an index price, and charges the producer fees associated with the downstream gathering and processing services. These fees are treated as a reduction of the purchase cost when the fees relate to services performed after control of the product has transferred to Anadarko. Revenue is recognized, along with cost of product expense related to the sale, when the purchased product is sold to a third party.

Revenue from percentage of proceeds gathering and processing contracts is recognized net of the cost of product for purchases from service customers when the Company is acting as their agent in the product sale, and any fees charged on these percentage of proceeds contracts are recognized in service revenues.

~~ASU 2018-02,~~ ~~Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income~~, provides entities the option to reclassify stranded tax effects resulting from the Tax Reform Legislation from accumulated other comprehensive income (AOCI) to retained earnings. In accordance with its accounting policy, the Company releases stranded income tax effects from AOCI in the period the underlying portfolio is liquidated. This ASU allows for the reclassification of stranded tax effects as a result of the change in tax rates from Tax Reform Legislation to be recorded upon adoption of the ASU, rather than at the actual portfolio liquidation date. The Company adopted this ASU on January 1, 2018, electing to reclassify $73 million from AOCI to retained earnings, including a $2 million federal benefit of state tax impact related to the Tax Reform Legislation.

~~New Accounting Standards Issued But Not Yet Adopted~~ ~~ASU~~ 2016-02, Leases (Topic 842), This ASU requires lessees to recognize a lease liability and ~~a right-of-use (ROU)~~an ROU asset on the balance sheet for all leases, including operating ~~leases, with a term greater than 12 months on the balance sheet.~~leases. This ASU modifies the definition of a lease and outlines the recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The Company ~~plans~~adopted Topic 842 on January 1, 2019, using the modified retrospective method applied to ~~make certain elections allowing the Company~~all leases that existed on January 1, 2019, and prior-period financial statements were not adjusted. Anadarko elected not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for existing or expired land easements, and not to recognize ROU assets or lease liabilities for short-term leases. ~~Anadarko continues to review contracts in its portfolio~~Upon adoption, the Company recognized approximately $600 million of ~~leased assets to assess the impact of adopting this ASU. The Company expects the adoption of this ASU to primarily impact other~~ROU assets and ~~other long-term~~lease liabilities ~~and does not expect a material impact on its consolidated results of operations. To facilitate compliance with this ASU, Anadarko expects~~related to ~~implement new accounting software and complete the evaluation of its systems, processes, and internal controls by the end of 2018. Anadarko will adopt this ASU on~~leases existing at January 1, ~~2019, using~~2019. The difference between ROU assets and operating lease liabilities, net of the deferred tax impact, was recognized as a ~~modified retrospective approach. As permitted by ASU 2018-11,~~ ~~Leases (Topic 842): Targeted Improvements, the Company does not expect to adjust comparative-period financial statements and will recognize a cumulative effect adjustment~~$55 million reduction in the opening balance of retained earnings ~~in the period of adoption.~~

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~2. Revenue from Contracts with Customers~~

~~Change in Accounting Policy~~ ~~The Company adopted ASU 2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606), on January 1, 2018, using the modified retrospective method applied to contracts that were not completed~~ as ~~of January 1, 2018.~~a cumulative effect adjustment. See Note ~~1—Summary of Significant Accounting Policies~~9—Leases for additional information.

~~Impacts on Financial Statements~~Accounting Policy

~~Exploration~~Leases Anadarko determines if an arrangement is a lease based on rights and ~~Production~~ ~~There were no significant changes to~~obligations conveyed at inception of a contract. At the ~~timing~~commencement date, a lease is classified as either operating or ~~valuation~~finance, and an ROU asset and lease liability is recognized based on the present value of ~~revenue recognized for sales of production by~~future lease payments over the ~~Exploration and Production segment.~~

~~WES Midstream and Other Midstream~~ ~~Gathering and processing revenues decreased for contracts where~~lease term. As the rate implicit in Anadarko’s leases generally is not readily determinable, the Company ~~is acting~~discounts lease liabilities using the Company’s incremental borrowing rate at the commencement date. Non-lease components associated with leases that begin in 2019 or later are accounted for as ~~an agent for its processing customer~~part of the lease component, and prepaid lease payments are included in the ~~sale~~ROU asset. Options to extend or terminate a lease are included in the lease term when it is reasonably certain that Anadarko will exercise that option. Leases of processed volumes and increased for contracts with noncash consideration, with an offset to gathering and processing expense upon product sale. The magnitude of these presentation changes in subsequent periods is dependent on future customer volumes subject to the impacted contracts and commodity prices for those volumes. These presentation changes do12 months or less are not ~~impact net earnings.~~

~~The following tables summarize the impacts of adopting Topic 606~~recognized on the Company’s ~~consolidated financial statements:~~Consolidated Balance Sheet.

Lease cost is recognized over the lease term, unless the end of the useful life of the underlying asset in a finance lease is before the end of the lease term. Lease cost is recognized on a straight-line basis unless another method better represents the pattern that benefit is expected to be derived from the right to use the underlying asset. For finance leases, interest expense is recognized over the lease term using the effective interest method. Variable lease payments are recognized when the obligation for those payments is incurred.

CONSOLIDATED BALANCE SHEET Impact of Change in Accounting Policy
millions As Reported Without Adoption of Topic 606
Effect of Change
Increase/(Decrease)
September 30, 2018
Assets
Other current assets $ 397
$ 395
$ 2
Net properties and equipment 28,744
28,697
47
Other assets 2,292
2,282
10
Liabilities
Other current liabilities 1,502
1,494
8
Deferred income taxes 2,455
2,461
(6 )
Other 4,043
3,932
111
Equity
Total equity 11,237
11,291
(54 )

Generally, a contract in a joint arrangement is evaluated as a lease if Anadarko is the operator. Anadarko recognizes an ROU asset and lease liability for the full amount of each contract determined to be a lease, although a portion of lease payments is generally recovered from partners. Lease payments associated with the drilling of exploratory wells and development wells net of amounts billed to partners will initially be capitalized as a component of oil and gas properties and either depreciated, impaired, or written off as exploration expense in future periods.

APC 2019 FORM 10-Q | 12

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

~~2. Revenue from Contracts with Customers (Continued)~~

CONSOLIDATED STATEMENT OF INCOME Impact of Change in Accounting Policy
millions As Reported Without Adoption of Topic 606
Effect of Change
Increase/(Decrease)
Three Months Ended September 30, 2018
Revenues
Gathering, processing, and marketing sales $ 421
$ 717
$ (296 )
Gains (losses) on divestitures and other, net 90
89
1
Expenses
Gathering, processing, and marketing 256
551
(295 )
Income tax expense (benefit) 256
254
2
Net income (loss) attributable to noncontrolling interests 64
71
(7 )
Net Income (Loss) Attributable to Common Stockholders $ 363
$ 358
$ 5

Nine Months Ended September 30, 2018
Revenues
Gathering, processing, and marketing sales $ 1,163
$ 1,944
$ (781 )
Gains (losses) on divestitures and other, net 232
233
(1 )
Expenses
Gathering, processing, and marketing 745
1,520
(775 )
Income tax expense (benefit) 507
507
—
Net income (loss) attributable to noncontrolling interests 105
111
(6 )
Net Income (Loss) Attributable to Common Stockholders $ 513
$ 514
$ (1 )

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~2. Revenue from Contracts with Customers(Continued)~~

2. Revenue from Contracts with Customers

Disaggregation of Revenue from Contracts with Customers The following table disaggregates revenue by significant product type and segment:

millions Exploration
& Production WES Midstream Other Midstream Other and
Intersegment
Eliminations Total
Three Months Ended September 30, 2018
Oil sales $ 2,572
$ —
$ —
$ —
$ 2,572
Natural-gas sales 232
—
—
—
232
Natural-gas liquids sales 382
—
—
—
382
Gathering, processing, and marketing sales ⁽¹⁾
—
511
113
1
625
Other, net 9
—
—
31
40
Total Revenue from Customers $ 3,195
$ 511
$ 113
$ 32
$ 3,851
Gathering, processing, and marketing sales ⁽²⁾
—
(3 ) 3
(204 ) (204 )
Gains (losses) on divestitures, net 5
—
1
(3 ) 3
Other, net (8 ) 52
12
(9 ) 47
Total Revenue from Other than Customers $ (3 ) $ 49
$ 16
$ (216 ) $ (154 )
Total Revenue and Other $ 3,192
$ 560
$ 129
$ (184 ) $ 3,697

Nine Months Ended September 30, 2018
Oil sales $ 6,964
$ —
$ —
$ —
$ 6,964
Natural-gas sales 682
—
—
—
682
Natural-gas liquids sales 992
—
—
—
992
Gathering, processing, and marketing sales ⁽¹⁾
—
1,438
255
83
1,776
Other, net 16
—
—
71
87
Total Revenue from Customers $ 8,654
$ 1,438
$ 255
$ 154
$ 10,501
Gathering, processing, and marketing sales ⁽²⁾
—
(6 ) 6
(613 ) (613 )
Gains (losses) on divestitures, net 24
—
10
(3 ) 31
Other, net (21 ) 113
30
(8 ) 114
Total Revenue from Other than Customers $ 3
$ 107
$ 46
$ (624 ) $ (468 )
Total Revenue and Other $ 8,657
$ 1,545
$ 301
$ (470 ) $ 10,033

~~__________________________________________________________________~~



millions	Exploration & Production				WES Midstream				Other and Intersegment Eliminations				Total
Three Months Ended March 31, 2019
Oil sales		$	2,096			$	—			$	—			$	2,096
Natural-gas sales		320				—				—				320
Natural-gas liquids sales		240				—				—				240
Gathering, processing, and marketing sales ⁽¹⁾		1				672				(25		)		648
Other, net		9				—				25				34
Total Revenue from Customers		$	2,666			$	672			$	—			$	3,338
Gathering, processing, and marketing sales ⁽²⁾		—				—				(178		)		(178		)
Gains (losses) on divestitures, net		—				—				(5		)		(5		)
Other, net		(1		)		57				7				63
Total Revenue from Other than Customers		$	(1	)		$	57			$	(176	)		$	(120	)
Total Revenue and Other		$	2,665			$	729			$	(176	)		$	3,218

Three Months Ended March 31, 2018
Oil sales		$	2,127			$	—			$	—			$	2,127
Natural-gas sales		247				—				—				247
Natural-gas liquids sales		292				—				—				292
Gathering, processing, and marketing sales⁽¹⁾		—				502				46				548
Other, net		3				—				19				22
Total Revenue from Customers		$	2,669			$	502			$	65			$	3,236
Gathering, processing, and marketing sales⁽²⁾		—				(1		)		(187		)		(188		)
Gains (losses) on divestitures, net		(33		)		—				9				(24		)
Other, net		(12		)		44				(11		)		21
Total Revenue from Other than Customers		$	(45	)		$	43			$	(189	)		$	(191	)
Total Revenue and Other		$	2,624			$	545			$	(124	)		$	3,045

⁽¹⁾

The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of ~~$328~~$209 million and ~~intercompany~~intersegment eliminations of ~~$(312)~~$(223) million for the three months ended ~~September 30, 2018,~~March 31, 2019, and sales of third-party natural gas and NGLs of ~~$813~~$224 million and ~~intercompany~~intersegment eliminations of ~~$(715)~~$(163) million for the ~~nine~~three months ended ~~September 30,~~March 31, 2018.


⁽²⁾	The amount in Other and Intersegment Eliminations represents purchases of third-party natural gas and NGLs. Although these purchases are reported net in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income, they are shown separately on this table as the purchases are not considered revenue from customers.

1413 | APC 2019 FORM 10-Q



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~2. Revenue from Contracts with Customers(Continued)~~

2. Revenue from Contracts with Customers (Continued)

Contract Liabilities Contract liabilities primarily relate to midstream fees and capital reimbursements that are charged to customers for only a portion of the contract term and must be recognized as revenues over the expected period of benefit, fixed and variable fees that are received from customers but revenue recognition is deferred under midstream cost of service contracts, and hard-minerals bonus payments received from customers that must be recognized as revenue over the expected period of benefit. The following table summarizes the current period activity related to contract liabilities from contracts with customers:

millions
Balance at December 31, 2017 $ 37
Increase due to cumulative effect of adopting Topic 606 98
Increase due to cash received, excluding revenues recognized in the period ⁽¹⁾
46
Decrease due to revenue recognized ⁽²⁾
(30 )
Balance at September 30, 2018 $ 151

Contract liabilities at September 30, 2018
Other current liabilities $ 23
Other long-term liabilities - other 128
Total contract liabilities from contracts with customers $ 151



millions
Balance at December 31, 2018	$	150
Increase due to cash received, excluding revenues recognized in the period	21
Decrease due to revenue recognized	(18		)
Balance at March 31, 2019	$	153

Contract liabilities at March 31, 2019
Other current liabilities	$	23
Other long-term liabilities - other	130
Total contract liabilities from contracts with customers	$	153

~~__________________________________________________________________~~


⁽¹⁾	~~Includes $(6) million for the three months ended September 30, 2018.~~


⁽²⁾	~~Includes $(9) million for the three months ended September 30, 2018.~~

Transaction Price Allocated to Remaining Performance ObligationsRevenue expected to be recognized from certain performance obligations that are unsatisfied as of ~~September 30, 2018,~~March 31, 2019, is reflected in the table below. The Company applies the optional exemptions in Topic 606 and does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied performance obligations. Therefore, the following table represents only a small portion of Anadarko’s expected future consolidated revenues as future revenue from the sale of most products and services is dependent on future production or variable customer ~~volumes~~volume and variable commodity prices for ~~those volumes.~~that volume.


millions	Exploration & Production		WES Midstream		Other Midstream		Other and Intersegment Eliminations			Total		Exploration & Production			WES Midstream			Other and Intersegment Eliminations				Total
Remainder of 2018	$	27	$	124	$	31	$	(96	)	$	86
2019	104		480		204		(441		)	347
Remainder of 2019													$	80		$	533		$	(352	)		$	261
2020	103		545		293		(606		)	335			103			862			(622		)		343
2021	103		525		361		(672		)	317			103			912			(698		)		317
2022	7		529		417		(739		)	214			7			976			(770		)		213
2023													7			933			(770		)		170
Thereafter	65		2,192		3,107		(4,662		)	702			58			4,500			(4,009		)		549
Total	$	409	$	4,395	$	4,413	$	(7,216	)	$	2,001		$	358		$	8,716		$	(7,221	)		$	1,853

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~3. Commodity Inventories~~

3. Commodity Inventories

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


	September 30,		December 31,
millions	2018		2017		March 31, 2019			December 31, 2018
Oil	$	168	$	165		$	169		$	139
Natural gas	19		29			1			18
NGLs	131		122			84			78
Total commodity inventories	$	318	$	316		$	254		$	235

APC 2019 FORM 10-Q | 14

~~4. Divestitures~~



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

~~Divestitures~~

4. Divestitures

The following summarizes the proceeds received and gains (losses) recognized on divestitures:


	Nine Months Ended				Three Months Ended
	September 30,				March 31,
millions	2018		2017		2019			2018
Proceeds received, net of closing adjustments	$	393	$	3,480	$	7		$	371
Gains (losses) on divestitures, net ⁽¹⁾	31		815		(5		)	(24		)


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

2018 During the ~~nine~~three months ended ~~September 30,~~March 31, 2018, the Company divested of ~~the following U.S. onshore and Gulf of Mexico assets:~~

its Alaska nonoperated assets, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $370 million and net losses of $33 million in 2018 and $154 million in the fourth quarter of 2017.

~~Ram Powell nonoperated assets in the Gulf of Mexico, included in the Exploration and Production reporting segment, resulting in a net gain of $67 million.~~

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

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

~~Marcellus assets in Pennsylvania, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $758~~$383 million and net losses of ~~$56~~$30 million in ~~2017~~2018 and ~~$129~~$154 million in the fourth quarter of ~~2016~~

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

~~Utah CBM assets, included in the Exploration and Production and WES Midstream reporting segments, for net proceeds of $69 million and a net loss of $52 million~~

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

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~5. Impairments~~

~~Impairments of Long-Lived Assets~~

~~2018~~ ~~During the nine months ended September 30, 2018, the Company expensed $319 million primarily related to the following:~~

$145 million in the third quarter of 2018 related to hard-minerals properties due to the Company’s primary consumer of coal stating its intent to retire its existing coal-fired power generation plant earlier than expected, coupled with the outlook for limited new markets for the Company’s coal in the Rockies region. These coal assets had a post-impairment fair value of $15 million.

~~$126 million related to a gathering system in the DJ basin, included in the WES Midstream reporting segment that was permanently taken out of service in the second quarter of 2018.~~

~~2017~~ ~~During the nine months ended September 30, 2017, the Company expensed $383 million primarily related to the following:~~

$211 million related to oil and gas properties in the Gulf of Mexico, included in the Exploration and Production reporting segment, due to lower forecasted commodity prices at that time. The assets had a post-impairment fair value of $231 million.

$168 million related to U.S. onshore midstream properties, included in the WES Midstream reporting segment, primarily due to a reduced throughput fee as a result of a producer’s bankruptcy. The assets had a post-impairment fair value of $58 million.

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

~~Impairments of Unproved Properties~~Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. During the nine months ended September 30, 2018, the Company recognized $158 million of impairments of unproved Gulf of Mexico properties primarily related to blocks where the Company determined it would no longer pursue activities. The Company recognized $586 million of impairments of unproved Gulf of Mexico properties during the nine months ended September 30, 2017, of which $463 million related to the Shenandoah project. The unproved property balance related to the Shenandoah project originated from the purchase price allocated to the Gulf of Mexico exploration projects from the acquisition of Kerr-McGee Corporation in 2006.

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

~~6. Suspended Exploratory Well Costs~~

5. Suspended Exploratory Well Costs

The Company’s suspended exploratory well costs were ~~$510~~$460 million at ~~September 30, 2018,~~March 31, 2019, and ~~$525~~$444 million at December 31, ~~2017.~~2018. For exploratory wells, drilling costs are capitalized, or “suspended,” on the balance sheet when the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time. During the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, there was no exploration expense recorded for suspended exploratory well costs previously capitalized for greater than one year at December 31, ~~2017.~~2018.

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~7. Current Liabilities~~

6. Current Liabilities

Accounts PayableAccounts payable, trade included liabilities of ~~$205~~$248 million at ~~September 30, 2018,~~March 31, 2019, and ~~$219~~$180 million atDecember 31, ~~2017,~~2018, representing the amount by which checks issued but not presented to the Company’s banks for collection exceeded balances in applicable bank accounts. Changes in these liabilities are classified as cash flows from financing activities.

Other Current Liabilities The following summarizes the Company’s other current liabilities:


	September 30,		December 31,
millions	2018		2017		March 31, 2019			December 31, 2018
Accrued income taxes	$	79	$	71		$	211		$	167
Interest payable	169		246			159			267
Production, property, and other taxes payable	344		216			314			309
Accrued employee benefits	270		210			153			319
Derivatives	491		384			121			89
Operating lease liabilities						245			—
Other	149		183			137			144
Total other current liabilities	$	1,502	$	1,310		$	1,340		$	1,295

15 | APC 2019 FORM 10-Q

~~8. Derivative Instruments~~



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

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.

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 currently outstanding 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.

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~8. Derivative Instruments (Continued)~~

Oil and Natural-Gas Production/Processing Derivative Activities The oil prices listed below are a combination of NYMEX WTI and Intercontinental Exchange, Inc. (ICE) Brent Blend prices. The Company had no natural-gas ~~prices listed below are NYMEX Henry Hub prices.~~production/processing derivatives at March 31, 2019. The following is a summary of the Company’s oil derivative instruments ~~related to oil and natural-gas production/processing derivative activities~~ at ~~September 30, 2018:~~March 31, 2019:


	2018 Settlement		2019 Settlement		2019 Settlement
Oil
Two-Way Collars (MBbls/d)	108		—
Average price per barrel (WTI)
Ceiling sold price (call)	$	60.48	$	—
Floor purchased price (put)	$	50.00	$	—
Three-Way Collars (MBbls/d)	—		87		87
Average price per barrel (WTI and Brent)
Average price per barrel
Ceiling sold price (call)	$	—	$	72.98	$	72.98
Floor purchased price (put)	$	—	$	56.72	$	56.72
Floor sold price (put)	$	—	$	46.72	$	46.72
Fixed-Price Contracts (MBbls/d)	84		—
Average price per barrel (Brent)	$	61.45	$	—
Natural Gas
Three-Way Collars (thousand MMBtu/d)	250		—
Average price per MMBtu (Henry Hub)
Ceiling sold price (call)	$	3.54	$	—
Floor purchased price (put)	$	2.75	$	—
Floor sold price (put)	$	2.00	$	—
Fixed-Price Contracts (thousand MMBtu/d)	280		—
Average price per MMBtu (Henry Hub)	$	3.02	$	—

A two-way collar is a combination of two options: a sold call and a purchased put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes.

A three-way collar is a combination of three options: a sold call, a purchased put, and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity ~~volumes.~~volume. The purchased put establishes the minimum price that the Company will receive for the contracted ~~volumes~~volume 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.

19APC 2019 FORM 10-Q | 16



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

7. Derivative Instruments (Continued)

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

In August 2018, the Company amended an interest-rate swap with a notional principal amount of $200 million, extending the mandatory termination date from 2018 to 2023 in exchange for a cash payment of approximately $10 million.

At ~~September 30, 2018,~~March 31, 2019, the Company had outstanding interest-rate swaps with a notional amount of $1.6 billion due prior to or in September 2023 that manage interest-rate risk associated with potential future debt issuances. Depending on market conditions, liability-management actions, or other factors, the Company may enter into offsetting interest-rate swap positions or settle or amend certain or all of the currently outstanding interest-rate swaps. The Company had the following outstanding interest-rate swaps at ~~September 30, 2018:~~March 31, 2019:


millions except percentages	millions except percentages		Mandatory	Weighted-Average	millions except percentages		Mandatory	Weighted-Average
Notional Principal Amount	Notional Principal Amount	Reference Period	Termination Date	Interest Rate	Notional Principal Amount	Reference Period	Termination Date	Interest Rate
$	550	September 2016 - 2046	September 2020	6.418%	550	September 2016 - 2046	September 2020	6.418	%
$	250	September 2016 - 2046	September 2022	6.809%	250	September 2016 - 2046	September 2022	6.809	%
$	100	September 2017 - 2047	September 2020	6.891%	100	September 2017 - 2047	September 2020	6.891	%
$	250	September 2017 - 2047	September 2021	6.570%	250	September 2017 - 2047	September 2021	6.570	%
$	450	September 2017 - 2047	September 2023	6.445%	450	September 2017 - 2047	September 2023	6.445	%

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~~Anadarko’s portfolio contain an other-than-insignificant financing element, and therefore, any settlements, collateralization, or cash payments for amendments related to these extended interest-rate derivatives are classified as cash flows from financing activities. Net cash payments related to settlements and amendments of interest-rate swap agreements were ~~$101~~$41 million during the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, and ~~$118~~$46 million during the ~~nine~~three months ended ~~September 30, 2017.~~March 31, 2018.

WES Interest-Rate Derivatives WES entered into interest-rate swap agreements with an aggregate notional amount of $750 million in December 2018 and $375 million in March 2019 to manage interest-rate risk associated with anticipated 2019 debt issuances. WES exchanged a floating interest rate indexed to the three-month LIBOR for a fixed interest rate. Depending on market conditions, liability management actions, or other factors, WES may settle or amend certain or all of the currently outstanding interest-rate swaps. The following interest-rate swaps were outstanding at March 31, 2019:



millions except percentages			Mandatory	Weighted-Average
Notional Principal Amount		Reference Period	Termination Date	Interest Rate
$	375	December 2019 - 2024	December 2019	2.662	%
$	375	December 2019 - 2029	December 2019	2.802	%
$	375	December 2019 - 2049	December 2019	2.885	%

2017 | APC 2019 FORM 10-Q



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

7. Derivative Instruments (Continued)

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


	Gross Derivative Assets				Gross Derivative Liabilities						Gross Derivative Assets						Gross Derivative Liabilities
millions	September 30,		December 31,		September 30,			December 31,			March 31,			December 31,			March 31,				December 31,
Balance Sheet Classification	2018		2017		2018			2017				2019			2018			2019				2018
Commodity derivatives
Commodity derivatives - Anadarko
Other current assets												$	45		$	300		$	(27	)		$	(126	)
Other current liabilities												—			1			(2		)		(6		)
												45			301			(29		)		(132		)
Interest-rate derivatives - Anadarko⁽¹⁾
Other current assets	$	2	$	7	$	—		$	(1	)		21			22			—				—
Other assets	—		2		—			—				30			34			—				—
Other current liabilities	20		45		(440		)	(206		)		—			—			(83		)		(82		)
Other liabilities	15		—		(56		)	(2		)		—			—			(1,237		)		(1,156		)
	37		54		(496		)	(209		)		51			56			(1,320		)		(1,238		)
Interest-rate derivatives
Other current assets	21		14		—			—
Other assets	54		40		—			—
Interest-rate derivatives - WES
Other current liabilities	—		—		(80		)	(236		)		—			—			(44		)		(8		)
Other liabilities	—		—		(1,028		)	(1,183		)
	75		54		(1,108		)	(1,419		)
Total derivatives	$	112	$	108	$	(1,604	)	$	(1,628	)		$	96		$	357		$	(1,393	)		$	(1,378	)


⁽¹⁾	Excludes amounts related to WES interest-rate swap agreements.

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


	Three Months Ended					Nine Months Ended						Three Months Ended
millions	September 30,					September 30,						March 31,
Classification of (Gain) Loss Recognized	2018			2017		2018			2017				2019		2018
Commodity derivatives
Commodity derivatives - Anadarko
Gathering, processing, and marketing sales	$	1		$	—	$	3		$	—			$	2	$	1
(Gains) losses on derivatives, net	104			43		734			(164		)		149		162
Interest-rate derivatives
Interest-rate derivatives - Anadarko⁽¹⁾
(Gains) losses on derivatives, net													128		(127		)
Interest-rate derivatives - WES
(Gains) losses on derivatives, net	(72		)	39		(231		)	131				36		—
Total (gains) losses on derivatives, net	$	33		$	82	$	506		$	(33	)		$	315	$	36


⁽¹⁾	Excludes amounts related to WES interest-rate swap agreements.

21APC 2019 FORM 10-Q | 18



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

7. Derivative Instruments (Continued)

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

The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities and routinely exercises its contractual right to offset gains and losses when settling with derivative counterparties. In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and provide for contract termination and net settlement across derivative types.

The Company’s derivative instruments are subject to individually negotiated credit provisions that may require collateral of cash or letters of credit depending on the derivative’s portfolio valuation versus negotiated credit thresholds. These credit thresholds generally require full or partial collateralization of the Company’s obligations depending on certain credit-risk-related provisions, such as the Company’s credit rating from S&P and Moody’s. As of ~~September 30, 2018,~~March 31, 2019, the Company’s long-term debt was rated investment grade (BBB) by both S&P and Fitch and below investment grade (Ba1) by Moody’s. In January 2019, Moody’s changed its outlook with respect to its rating from stable to positive. The Company may be required to post additional collateral with respect to its derivative instruments if its credit ratings decline below current levels or if the liability associated with any such derivative instrument increases ~~substantially. For example, based on~~above the ~~derivative positions as of September 30, 2018, if Anadarko’s~~ credit ~~rating were to be downgraded one level by either S&P or Moody’s, the Company could be required to post additional collateral of up to approximately $124 million.~~threshold. 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 ~~$49~~$123 million of collateral) at ~~September 30, 2018,~~March 31, 2019, and ~~$1.4~~$1.1 billion (net of ~~$170~~$66 million of collateral) at December 31, ~~2017.~~2018.

2219 | APC 2019 FORM 10-Q



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

7. Derivative Instruments (Continued)

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

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

millions Level 1 Level 2 Level 3
Netting ⁽¹⁾
Collateral Total
September 30, 2018
Assets
Commodity derivatives $ —
$ 37
$ —
$ (35 ) $ —
$ 2
Interest-rate derivatives —
75
—
—
—
75
Total derivative assets $ —
$ 112
$ —
$ (35 ) $ —
$ 77
Liabilities
Commodity derivatives $ —
$ (496 ) $ —
$ 35
$ 6
$ (455 )
Interest-rate derivatives —
(1,108 ) —
—
49
(1,059 )
Total derivative liabilities $ —
$ (1,604 ) $ —
$ 35
$ 55
$ (1,514 )

December 31, 2017
Assets
Commodity derivatives $ 1
$ 53
$ —
$ (46 ) $ (1 ) $ 7
Interest-rate derivatives —
54
—
—
—
54
Total derivative assets $ 1
$ 107
$ —
$ (46 ) $ (1 ) $ 61
Liabilities
Commodity derivatives $ (1 ) $ (208 ) $ —
$ 46
$ 3
$ (160 )
Interest-rate derivatives —
(1,419 ) —
—
170
(1,249 )
Total derivative liabilities $ (1 ) $ (1,627 ) $ —
$ 46
$ 173
$ (1,409 )

~~__________________________________________________________________~~



millions	Level 1			Level 2			Level 3		Netting ⁽¹⁾			Collateral			Total
March 31, 2019
Assets
Anadarko ⁽²⁾
Commodity derivatives	$	—		$	45		$	—	$	(27	)		$	—	$	18
Interest-rate derivatives	—			51			—		—				—		51
Total derivative assets	$	—		$	96		$	—	$	(27	)		$	—	$	69
Liabilities
Anadarko ⁽²⁾
Commodity derivatives	$	—		$	(29	)	$	—	$	27			$	—	$	(2	)
Interest-rate derivatives	—			(1,320		)	—		—				123		(1,197		)
WES
Interest-rate derivatives	—			(44		)	—		—				—		(44		)
Total derivative liabilities	$	—		$	(1,393	)	$	—	$	27			$	123	$	(1,243	)

December 31, 2018
Assets
Anadarko ⁽²⁾
Commodity derivatives	$	1		$	300		$	—	$	(127	)		$	—	$	174
Interest-rate derivatives	—			56			—		—				—		56
Total derivative assets	$	1		$	356		$	—	$	(127	)		$	—	$	230
Liabilities
Anadarko ⁽²⁾
Commodity derivatives	$	(2	)	$	(130	)	$	—	$	127			$	2	$	(3	)
Interest-rate derivatives	—			(1,238		)	—		—				66		(1,172		)
WES
Interest-rate derivatives	—			(8		)	—		—				—		(8		)
Total derivative liabilities	$	(2	)	$	(1,376	)	$	—	$	127			$	68	$	(1,183	)


⁽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.


⁽²⁾	Excludes amounts related to WES interest-rate swap agreements.

23APC 2019 FORM 10-Q | 20



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~9. Tangible Equity Units~~

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

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

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

~~10. Debt~~

8. Debt

Debt Activity The following summarizes the Company’s borrowing activity, after eliminating the effect of intercompany transactions, during the ~~nine~~three months ended ~~September 30, 2018:~~March 31, 2019:


	Carrying Value													Carrying Value
millions	WES			WGP ⁽¹⁾		Anadarko ⁽²⁾			Anadarko Consolidated			Description	Anadarko ⁽¹⁾				WES				Anadarko Consolidated				Description
Balance at December 31, 2017	$	3,465		$	28	$	11,965		$	15,458
Issuances
Balance at December 31, 2018														$	11,354			$	4,815			$	16,169
Borrowings
	394			—		—			394			WES 4.500% Senior Notes due 2028		—				2,000				2,000			WES 364-Day Facility
	687			—		—			687			WES 5.300% Senior Notes due 2048
	396			—		—			396			WES 4.750% Senior Notes due 2028
	342			—		—			342			WES 5.500% Senior Notes due 2048
Borrowings
	320			—		—			320			WES RCF		—				420				420			WES RCF
Repayments
	(690		)	—		—			(690		)	WES RCF		(600		)		—				(600		)	8.700 % Senior Notes due 2019
	—			—		(114		)	(114		)	7.050% Debentures due 2018		(300		)		—				(300		)	6.950 % Senior Notes due 2019
	(350		)	—		—			(350		)	WES 2.600% Senior Notes due 2018		—				(28		)		(28		)	WGP RCF
	—			—		(17		)	(17		)	TEUs - senior amortizing notes
Other, net	2			—		39			41			Amortization of discounts, premiums, and debt issuance costs		12				1				13			Amortization of discounts, premiums, and debt issuance costs
Balance at September 30, 2018	$	4,566		$	28	$	11,873		$	16,467
Balance at March 31, 2019														$	10,466			$	7,208			$	17,674


⁽¹⁾	Excludes WES.

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



millions	Anadarko ⁽¹⁾				WES				Anadarko Consolidated
March 31, 2019
Total borrowings at face value		$	11,893			$	7,260			$	19,153
Net unamortized discounts, premiums, and debt issuance costs ⁽²⁾		(1,427		)		(52		)		(1,479		)
Total borrowings ⁽³⁾		10,466				7,208				17,674
Finance lease liabilities		250				—				250
Less short-term debt		21				2,000				2,021
Total long-term debt		$	10,695			$	5,208			$	15,903

December 31, 2018
Total borrowings at face value		$	12,793			$	4,868			$	17,661
Net unamortized discounts, premiums, and debt issuance costs ⁽²⁾		(1,439		)		(53		)		(1,492		)
Total borrowings ⁽³⁾		11,354				4,815				16,169
Finance lease liabilities		248				—				248
Less short-term debt		919				28				947
Total long-term debt		$	10,683			$	4,787			$	15,470


⁽¹⁾	Excludes WES.


⁽²⁾	~~Excludes WES and WGP.~~

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~10. Debt (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⁾
Consolidated
September 30, 2018
Total borrowings at face value $ 4,620
$ 28
$ 13,383
$ 18,031
Net unamortized discounts, premiums, and debt issuance costs ⁽³⁾
(54 ) —
(1,510 ) (1,564 )
Total borrowings ⁽⁴⁾
4,566
28
11,873
16,467
Capital lease obligations —
—
226
226
Less short-term debt —
28
910
938
Total long-term debt $ 4,566
$ —
$ 11,189
$ 15,755

December 31, 2017
Total borrowings at face value $ 3,490
$ 28
$ 13,514
$ 17,032
Net unamortized discounts, premiums, and debt issuance costs ⁽³⁾
(25 ) —
(1,549 ) (1,574 )
Total borrowings ⁽⁴⁾
3,465
28
11,965
15,458
Capital lease obligations —
—
231
231
Less short-term debt —
—
142
142
Total long-term debt $ 3,465
$ 28
$ 12,054
$ 15,547


⁽¹⁾	~~Excludes WES.~~


⁽²⁾	~~Excludes WES and WGP.~~


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


⁽⁴⁾⁽³⁾	The Company’s outstanding borrowings, except for borrowings under the WGP RCF, are senior unsecured.

21 | APC 2019 FORM 10-Q



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

8. Debt (Continued)

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 ~~$17.8~~$19.3 billion at ~~September 30, 2018,~~March 31, 2019, and ~~$17.7~~$16.8 billion at December 31, ~~2017.~~2018.

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~10. Debt (Continued)~~

Anadarko ~~Borrowings~~Debt (Excluding WES) In January ~~2018,~~2019, the ~~Company amended its $3.0 billion senior unsecured RCF to extend the maturity date to January 2022 (APC RCF) and amended its~~ $2.0 billion 364-day senior unsecured RCF ~~to extend~~(364-Day Facility) expired. At March 31, 2019, the ~~maturity date to~~Company had a $3.0 billion senior unsecured RCF maturing in January ~~2019 (364-Day Facility)~~2023 (APC RCF). At ~~September 30, 2018,~~March 31, 2019, Anadarko had no outstanding borrowings under the APC RCF ~~or the 364-Day Facility~~ and was in compliance with all covenants.

~~At September 30, 2018,~~In March 2019, Anadarko ~~had outstanding borrowings of~~repaid $600 million of 8.700% Senior Notes ~~due March 2019~~at maturity and redeemed its $300 million of 6.950% Senior Notes due June ~~2019 classified as short-term debt on the Company’s Consolidated Balance Sheet. Short-term debt also included the current portion of the Company’s capital lease obligations.~~2019.

Anadarko’s Zero Coupons can be put to the Company in October of each year, in whole or in part, for the then-accreted value of the outstanding Zero ~~Coupons. None of the Zero~~ Coupons, ~~were put to the Company in October 2018. The Zero Coupons can next be put to the Company in October 2019,~~ which, if put in whole, would be ~~$980 million.~~$942 million at the next put date in October 2019. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at March 31, 2019, as the Company has the ability and intent to refinance these obligations using long-term debt, should a put be exercised.

The Company also has notes payable related to its ownership of certain noncontrolling mandatorily redeemable interests that are not included in the Company’s reported debt balance and do not affect consolidated interest expense. See Note 8—9—Equity-Method Investments in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2017.~~2018.

WES and WGP ~~Borrowings~~Debt InEffective on February ~~2018,~~15, 2019, WES amended ~~its RCF to extend~~ the maturity date of its senior unsecured RCF from February ~~2020~~2023 to February ~~2023~~2024, and upon completion of the WES Merger, expanded the borrowing capacity from $1.5 billion to ~~$1.5~~$2.0 billion (WES RCF). ~~As part of the amendment, the WES RCF is expandable to a maximum of $2.0 billion.~~ During the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, WES borrowed ~~$320~~$420 million under its RCF, which was used for general partnership ~~purposes, and made repayments of $690 million.~~purposes. At ~~September 30, 2018,~~March 31, 2019, WES had no outstanding borrowings under its RCF of $640 million at an interest rate of 3.79%, outstanding letters of credit of $5 million, available borrowing capacity of ~~$1.495~~$1.4 billion, and was in compliance with all covenants.

In ~~August 2018,~~February 2019, WES ~~completed a public offering~~borrowed $2.0 billion under its 364-day senior unsecured credit facility (WES 364-Day Facility) to fund substantially all of ~~$400 million aggregate principal amount~~the cash portion of ~~4.750% Senior Notes due August 2028 and a public offering of $350 million aggregate principal amount of 5.500% Senior Notes due August 2048. The net proceeds from~~ the ~~public offerings were used to repay the maturing WES $350 million of 2.600% Senior Notes due August 2018, and amounts outstanding~~consideration under the WES ~~RCF.~~midstream asset contribution and sale and the payment of related transaction costs. The ~~remaining net~~WES 364-Day Facility will mature on February 27, 2020, the day prior to the one-year anniversary of the completion of the WES Merger. Net cash proceeds ~~were used for general partnership purposes, including to fund capital expenditures.~~

~~In March 2018,~~received from future asset sales and debt or equity offerings by WES completed a public offering of $400 million aggregate principal amount of 4.500% Senior Notes due March 2028 and a public offering of $700 million aggregate principal amount of 5.300% Senior Notes due March 2048. Net proceeds from the public offerings weremust be used to repay amounts outstanding under the WES ~~RCF and for general partnership purposes, including to fund capital expenditures.~~

~~In February 2018, WGP voluntarily reduced the aggregate commitments of the lenders under its senior secured RCF maturing in~~364-Day Facility. At March 31, 2019, from $250 million to $35 million (WGP RCF). Obligations under the WGP RCF are secured by a first priority lien on all of WGP’s assets (not including the consolidated assets of WES) as well as all equity interests owned by WGP. At September 30, 2018, WGPWES had outstanding borrowings under its WES 364-Day Facility of ~~$28 million~~$2.0 billion at an interest rate of ~~4.25%, classified as short-term debt~~3.87% and was in compliance with all covenants. WES intends to refinance the obligations under the 364-Day Facility prior to its maturity in February 2020.

In March 2019, the $35 million senior secured RCF (WGP RCF) matured following the completion of the WES Merger. During the three months ended March 31, 2019, WES made repayments of $28 million for the WGP RCF.

See Note 1—Summary of Significant Accounting Policies for additional information related to the WES Merger.

APC 2019 FORM 10-Q | 22



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

9. Leases

Operating LeasesAt March 31, 2019, total lease liabilities related to operating leases were $551 million and primarily related to offshore and onshore drilling rigs and real estate.

The operating lease liabilities included $216 million for three offshore drilling vessels and certain contracts for onshore drilling rigs expiring at various dates through 2021. Lease payments commonly vary based on activities being performed by the rig. To the extent that lease payments vary from amounts recognized on the Company’s balance sheet, the amount is included in variable lease cost.

Additionally, the Company has $193 million of operating lease liabilities for real estate, primarily related to the Company’s Denver corporate office lease expiring in 2033, with options to terminate the lease early.

Finance LeasesAt March 31, 2019, total lease liabilities related to finance leases were $250 million and primarily related to an FPSO for the Company’s TEN field in Ghana. The initial FPSO lease term ends in 2026 with annual renewal periods for an additional 10 years, annual purchase options that decrease over time, and no residual value guarantees.

The following table summarizes information related to the Company’s leases at March 31, 2019:



millions except lease term and discount rate	Operating Leases				Finance Leases
Assets
Other assets		$	534			$	—
Net properties and equipment		—				186
Total lease assets ⁽¹⁾		$	534			$	186

Liabilities
Current liabilities
Other current liabilities		$	245			$	—
Short-term debt - Anadarko		—				21
Long-term liabilities
Other		306				—
Long-term debt - Anadarko		—				229
Total lease liabilities ⁽¹⁾		$	551			$	250

Weighted-average remaining lease term (years)		5				16
Weighted-average discount rate ⁽²⁾		4.3		%		15.4		%


⁽¹⁾	Includes additions to ROU assets and lease liabilities of $60 million related to operating leases and $6 million related to finance leases for the three months ended March 31, 2019.


⁽²⁾	The FPSO finance lease commenced prior to the adoption of ASU 2016-02, Leases (Topic 842). In accordance with previous accounting guidance, the implied rate is based on the fair value of the underlying asset.

23 | APC 2019 FORM 10-Q



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

9. Leases (Continued)

The following table summarizes the Company’s lease cost before amounts recovered from partners:



	Three Months Ended
millions	March 31, 2019
Operating lease cost		$	78
Short-term lease cost		19
Variable lease cost		39
Finance lease cost
Amortization of ROU assets		10
Interest on lease liabilities		9
Total lease cost		$	155

The following table summarizes cash paid for amounts included in the measurement of lease liabilities:



	Three Months Ended
	March 31, 2019
millions	Operating Leases			Finance Leases
Operating cash flows		$	78		$	9
Investing cash flows		24			—
Financing cash flows		—			4

The following table reconciles the undiscounted cash flows to the operating and finance lease liabilities recorded on the Company’s Consolidated Balance Sheet at March 31, 2019:



millions	Operating Leases ⁽¹⁾			Finance Leases
Remainder of 2019		$	185		$	46
2020		166			51
2021		60			50
2022		43			46
2023		30			43
Thereafter		142			324
Total lease payments		$	626		$	560
Less portion representing imputed interest		75			310
Total lease liabilities		$	551		$	250


⁽¹⁾	For leases commencing prior to 2019, lease payments exclude payments to lessors for drilling rig services and real estate services, taxes, and common area maintenance.

APC 2019 FORM 10-Q | 24



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

9. Leases (Continued)

The following table summarizes future minimum lease payments related to the Company’s operating and ~~had available borrowing capacity~~finance leases as of ~~$7 million. At September 30, 2018, WGP was in compliance with all covenants.~~December 31, 2018:



millions	Operating Leases			Finance Leases
2019		$	264		$	58
2020		139			50
2021		57			48
2022		35			45
2023		24			43
Thereafter		135			323
Total lease payments		$	654		$	567
Less portion representing imputed interest		*			319
Total lease liabilities		*			$	248


*	Prior to the adoption of ASU 2016-02, Leases (Topic 842) on January 1, 2019, operating lease liabilities were not recognized on the Company’s Consolidated Balance Sheet. Refer to Note 1—Summary of Significant Accounting Policies for additional information.

2625 | APC 2019 FORM 10-Q



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~11.~~

10. Income Taxes

Upon enactment of the Tax Reform Legislation on December 22, 2017, the Company remeasured its U.S. deferred tax assets and liabilities based on the reduction of the U.S. corporate tax rate from 35% to 21%. During the third quarter of 2018, the Company recognized an additional net tax benefit of $5 million related to the adoption of the Tax Reform Legislation under Staff Accounting Bulletin 118. The Company expects to complete the accounting for the income tax effects related to the adoption of the Tax Reform Legislation, including its accounting policy related to Global Intangible Low Taxed Income, and record any remaining adjustments to provisional tax amounts, which could be material to income tax expense, before the end of the measurement period on December 21, 2018. See ~~Note 13—Income Taxes~~ ~~in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.~~

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


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
millions except percentages	2018			2017			2018			2017			2019			2018
Current income tax expense (benefit)	$	146		$	430		$	383		$	670		$	168		$	90
Deferred income tax expense (benefit)	110			(855		)	124			(1,036		)	(2		)	36
Total income tax expense (benefit)	$	256		$	(425	)	$	507		$	(366	)	$	166		$	126
Income (loss) before income taxes	683			(1,066		)	1,125			(1,616		)	262			300
Effective tax rate	37		%	40		%	45		%	23		%	63		%	42		%

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

The variance from the U.S. federal statutory rate of 21% for the three ~~and nine~~ months ended ~~September 30, 2018,~~March 31, 2019, was primarily attributable to the following items:


–	tax impact from foreign operations


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


–	income attributable to noncontrolling interests

~~tax impact from foreign operations~~

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

The Company reported a loss before income taxes for the three and nine months ended September 30, 2017. As a result, items that ordinarily increase or decrease the Company’s tax rate will have the opposite effect. The variance from the U.S. federal statutory rate of ~~35%~~21% for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2018, was primarily attributable to the following items:

~~tax impact from foreign operations~~

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

~~net changes in uncertain tax positions~~

~~income attributable to noncontrolling interests~~

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~11. Income Taxes (Continued)~~


–	state taxes, net of federal benefits


–	tax impact from foreign operations


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


–	net changes in uncertain tax positions


–	income attributable to noncontrolling interests.

The Company recognized a ~~net~~ tax benefit of $346 million as of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, related to the deduction of its 2015 settlement payment for the Tronox Adversary Proceeding. This benefit is net of uncertain tax positions of $1.2 billion as of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, due to uncertainty related to the deductibility of the settlement payment. Due to the deduction of the settlement payment on the Company’s 2015 tax return, the Company had a net operating loss carryback, ~~for 2015,~~ which resulted in a tentative tax refund of $881 million in 2016. The IRS has audited this position and, in April 2018, issued a final notice of proposed adjustment denying the deductibility of the settlement payment. In September 2018, the Company received a statutory notice of deficiency from the IRS disallowing the net operating loss carryback and rejecting the Company’s refund claim. As a result, the Company ~~intends to file~~filed a petition with the U.S. Tax Court to dispute the disallowances in November 2018 and, pursuant to standard U.S. Tax Court procedures, the Company is not required to repay the $881 million refund to dispute the IRS’s position. Accordingly, the Company has not revised its estimate of the benefit that will ultimately be realized. After the case is tried and briefed in the Tax Court, the court will issue an opinion and then enter a decision. If the Company does not prevail on the issue, the earliest ~~potential~~ date the Company might be required to repay the refund received, plus interest, would be 91 days after entry of the decision. At such time, the Company would reverse the portion of the $346 million net benefit previously recognized in its consolidated financial statements to the extent necessary to reflect the result of the Tax Court decision. It is reasonably possible the amount of uncertain tax position and/or tax benefit could materially change as the Company asserts its position in the Tax Court proceedings. Although management cannot predict the timing of a final resolution of the Tax Court proceedings, the Company does not currently anticipate a decision to be entered ~~within the next three years.~~before 2022.

APC 2019 FORM 10-Q | 26

~~12. Contingencies~~



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

11. Contingencies

LitigationThere are no material developments in previously reported contingencies nor are there any other material matters that have arisen since the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2017.~~2018.

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

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

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	2018			2017			2018			2017				2019			2018				2019			2018
Three Months Ended September 30
Three Months Ended March 31
Service cost	$	23		$	22		$	—		$	—			$	22		$	23			$	—		$	—
Interest cost	19			21			3			3				20			19				3			3
Expected (return) loss on plan assets	(20		)	(21		)	—			—				(21		)	(21		)		—			—
Amortization of net actuarial loss (gain)	6			7			—			—				4			7				—			—
Amortization of net prior service cost (credit)	—			(1		)	(6		)	(6		)		—			—				(1		)	(6		)
Settlement expense	9			22			—			—				4			—				—			—
Termination benefits expense	7			—			—			—
Net periodic benefit cost ⁽¹⁾	$	44		$	50		$	(3	)	$	(3	)		$	29		$	28			$	2		$	(3	)

Nine Months Ended September 30
Service cost	$	68		$	64		$	1		$	1
Interest cost	57			63			8			9
Expected (return) loss on plan assets	(61		)	(63		)	—			—
Amortization of net actuarial loss (gain)	19			20			—			—
Amortization of net prior service cost (credit)	—			(1		)	(18		)	(18		)
Settlement expense	9			80			—			—
Termination benefits expense	7			4			—			—
Net periodic benefit cost ⁽¹⁾	$	99		$	167		$	(9	)	$	(8	)


⁽¹⁾	The service cost component of net periodic benefit cost is included in G&A; oil and gas operating expense; gathering, processing, and marketing expense; and exploration expense, and all other components of net periodic benefit cost are included in other (income) expense on the Company’s Consolidated Statements of Income.

The Company contributed ~~$161~~$65 million to funded pension plans and ~~$36~~$21 million to unfunded pension plans during the ~~nine~~three months ended ~~September 30, 2018.~~March 31, 2019. The Company expects to contribute an additional $1$26 million to funded pension plans and $26 million to unfunded pension plans during ~~2018.~~2019.

2927 | APC 2019 FORM 10-Q



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~14. Stockholders’ Equity~~

13. Stockholders’ Equity

Earnings Per ShareThe Company’s basic earnings per share (EPS) is computed based on the average number of shares of common stock outstanding for the period and includes the effect of any participating securities and TEUs as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units, and TEUs, if the inclusion of these items is dilutive. All outstanding TEUs were settled in June 2018. ~~See~~ ~~Note 9—Tangible Equity Units~~ ~~for additional information.~~

The following provides a reconciliation between basic and diluted EPS attributable to common stockholders:

Three Months Ended Nine Months Ended
September 30, September 30,
millions except per-share amounts 2018 2017 2018 2017
Net income (loss)
Net income (loss) attributable to common stockholders $ 363
$ (699 ) $ 513
$ (1,432 )
Income (loss) effect of TEUs —
(2 ) (4 ) (6 )
Less distributions on participating securities 2
—
4
—
Less undistributed income allocated to participating securities 2
—
1
—
Basic $ 359
$ (701 ) $ 504
$ (1,438 )
Income (loss) effect of TEUs —
—
—
(1 )
Diluted $ 359
$ (701 ) $ 504
$ (1,439 )
Shares
Average number of common shares outstanding—basic 499
553
507
552
Dilutive effect of stock options 1
—
1
—
Average number of common shares outstanding—diluted 500
553
508
552
Excluded due to anti-dilutive effect 8
11
9
11
Net income (loss) per common share
Basic $ 0.72
$ (1.27 ) $ 0.99
$ (2.60 )
Diluted $ 0.72
$ (1.27 ) $ 0.99
$ (2.61 )

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~14. Stockholders’ Equity (Continued)~~



	Three Months Ended
	March 31,
millions except per-share amounts	2019			2018
Net income (loss)
Net income (loss) attributable to common stockholders	$	(15	)	$	121
Income (loss) effect of TEUs	—			(3		)
Less distributions on participating securities	2			1
Basic	$	(17	)	$	117
Income (loss) effect of TEUs	—			(1		)
Diluted	$	(17	)	$	116
Shares
Average number of common shares outstanding—basic	490			518
Dilutive effect of stock options	—			1
Average number of common shares outstanding—diluted	490			519
Excluded due to anti-dilutive effect	12			10
Net income (loss) per common share
Basic	$	(0.03	)	$	0.23
Diluted	$	(0.03	)	$	0.22
Dividends per common share	$	0.30		$	0.25

Common StockThe Company announced a $2.5 billion Share-Repurchase Program in September 2017, which was expanded to $3.0 billion in February 2018. In July 2018, the program was further expanded to $4.0 billion and extended through June 30, 2019. The Share-Repurchase Program authorizes the repurchase of the Company’s common stock in the open market or through private transactions. During 2018, the Share-Repurchase Program was expanded to $5.0 billionand extended through mid-year 2020. As of ~~the end of the third quarter of~~December 31, 2018, the Company had completed ~~$3.5~~$3.75 billion of the Share-Repurchase Program through ASR Agreements and open-market repurchases. These transactions were accounted for as equity transactions, with all of the repurchased shares classified as treasury stock. Additionally, the receipt of these shares reduced the average number of shares of common stock outstanding used to compute both basic and diluted EPS.

~~During~~ There were no additional repurchases of common stock under the ~~nine~~Share-Repurchase Program for the three months ended ~~September 30, 2018,~~March 31, 2019. No additional share repurchases under the ~~Company entered into and completed two ASR Agreements and open-market repurchases as presented below:~~

millions except per-share amounts
Agreement Date Settlement Date Amount Average Price per Share Initial Shares Delivered Additional Shares Delivered Total Shares Delivered
ASR Agreements
January 2018 February 2018 $ 500
$ 58.82
7.0
1.5
8.5
March 2018 June 2018 1,441
65.28
19.1
3.0
22.1
Total ASR Agreements 1,941
26.1
4.5
30.6
Open-market repurchases

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

~~Under each ASR Agreement,~~Share-Repurchase Program are anticipated pursuant to the ~~Company paid a specific amount in cash and received an initial delivery of shares~~terms of the ~~Company’s common stock. The initial delivery~~Chevron Merger Agreement. See Note 1—Summary of ~~shares represented~~Significant Accounting Policies for additional information on the minimum number of shares to be repurchased under the agreement. The final number of shares delivered upon settlement of each ASR Agreement was determined with reference to the volume-weighted average price of the shares during the term of the agreement less a negotiated settlement price adjustment.Chevron Merger Agreement.

31APC 2019 FORM 10-Q | 28



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~15. Noncontrolling Interests~~

14. Noncontrolling Interests

WES is a limited partnership formed by Anadarko in September 2012 and owns a 98% limited partner interest in WES Operating, a Delaware limited partnership formed by Anadarko in 2007 to acquire, own, develop and operate midstream ~~assets. During 2016, WES issued 22 million Series A Preferred units to private investors. Pursuant to an agreement between WES~~assets, and ~~the holders~~all of the ~~Series A Preferred units, 50%~~outstanding equity interests of WES Operating’s general partner, which holds the ~~Series A Preferred units converted into~~entire non-economic general partner interest in WES ~~common units on a one-for-one basis on March 1, 2017, and all remaining Series A Preferred units were converted on May 2, 2017.~~Operating.

WES Operating Class C units issued to Anadarko ~~will convert~~converted into WES Operating common units in a unit-for-unit, tax-free exchange immediately prior to the closing of the WES Merger on ~~a one-for-one basis on~~February 28, 2019. Prior to the ~~conversion date, which was extended in February 2017 from December 31, 2017, to March 1, 2020. The~~closing of the WES Merger, the Class C units ~~receive~~received quarterly distributions in the form of additional Class C ~~units until the March 1, 2020 conversion date, unless WES elects to convert the units to common units earlier or Anadarko elects to extend the conversion date.~~units. WES distributed ~~802~~309 thousand Class C units to Anadarko during the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, and ~~886 thousand~~1.1 million Class C units to Anadarko during ~~2017.~~

WGP is a limited partnership formed by Anadarko to own interests in WES. In June 2018, Anadarko settled 9.2 million outstanding TEUs, originally issued in 2015, in exchange for approximately 8.2 million WGP common units.2018. See Note ~~9—Tangible Equity Units~~1—Summary of Significant Accounting Policiesfor additional ~~information.~~ information on the WES Merger.

At ~~September 30, 2018,~~March 31, 2019, Anadarko’s ownership interest in ~~WGP~~WES consisted of a ~~77.8%~~55.5% limited partner interest and the entire non-economic general partner interest. The remaining ~~22.2% limited partner interest in WGP was owned by the public.~~

At September 30, 2018, WGP’s ownership interest in WES consisted of a 29.6% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At September 30, 2018, Anadarko also owned a 9.5% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 59.4%44.5% limited partner interest in WES was owned by the public.

At March 31, 2019, Anadarko’s ownership interest in WES Operating consisted of a 2% limited partner interest.

3229 | APC 2019 FORM 10-Q



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~16. Variable Interest Entities~~

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~~is considered ~~VIEs.~~a VIE. Anadarko, through its ownership of the general partner interest in ~~WGP,~~WES, has the power to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to ~~WGP and~~ WES; therefore, Anadarko is considered the primary beneficiary and consolidates ~~WGP,~~ WES and all of ~~their~~its consolidated subsidiaries. For additional information on ~~WGP and~~ WES, see Note ~~15—~~14—Noncontrolling Interests.

~~The following tables present selected financial data from the consolidated financial statements of WGP:~~

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

Nine Months Ended
September 30,
millions 2018 2017
Statement of Cash Flows Data
Net cash provided by (used in) operating activities $ 749
$ 642
Net cash provided by (used in) investing activities (1,161 ) (515 )
Net cash provided by (used in) financing activities 465
(334 )

September 30, December 31,
millions 2018 2017
Balance Sheet Data
Cash and cash equivalents $ 133
$ 80
Net property, plant, and equipment 6,419
5,731
Total assets 9,034
8,016
Long-term debt 4,566
3,493
Total liabilities 5,417
4,071
Total equity and partners’ capital 3,617
3,945

Assets and Liabilities of VIEs The assets of ~~WGP,~~ WES and ~~their~~its subsidiaries cannot be used by Anadarko for general corporate purposes and are included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets. The carrying amounts of liabilities related to ~~WGP,~~ WES and ~~their~~its subsidiaries for which the creditors do not have recourse to other Anadarko assets ~~of the Company~~ are included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets.

All outstanding debt for WES at ~~September 30, 2018,~~March 31, 2019, and December 31, ~~2017,~~2018, including any borrowings under the WES RCF and WES 364-Day Facility, is recourse to ~~WES’s~~WES Operating’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, 2018, and December 31, 2017, including any borrowings under the WGP RCF, is recourse to WGP’s general partner, which is a wholly owned subsidiary of the Company. See Note ~~10—~~8—Debt for additional information on ~~WGP and~~ WES short-term and long-term debt balances.

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~16. Variable Interest Entities (Continued)~~

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

VIE Distributions The following table presents WES distributions:



	Three Months Ended
	March 31,
millions	2019		2018
WES distributions to Anadarko ⁽¹⁾	$	105	$	100
WES distributions to third parties	130		118


⁽¹⁾	WES distributions to Anadarko are eliminated upon consolidation.

Financial Support Provided to VIEs Concurrent with the closing of its May 2008 IPO, WES Operating 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 Operating was ~~$13~~$4 million for the ~~nine~~three months ended ~~September 30, 2018~~March 31, 2019 and ~~2017.~~2018. The note receivable and related interest income are eliminated in consolidation.

To reduce WES’s exposure to a majority of the commodity-price risk inherent in certain of its contracts, Anadarko ~~has~~had commodity price swap agreements in place with WES ~~expiring~~Operating that expired without renewal on December 31, ~~2018.~~2018 and final settlement occurred in the first quarter of 2019. WES recorded a capital contribution from Anadarko in its Consolidated Statement of Equity and Partners’ Capital for an amount equal to (i) the amount by which the swap price for product sales exceeds the applicable market price, minus (ii) the amount by which the swap price for product purchases exceeds the market price. WES recorded a capital contribution from Anadarko of ~~$41~~$7 million for the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, and ~~$47~~$14 million for the ~~nine~~three months ended ~~September 30, 2017.~~March 31, 2018.

34APC 2019 FORM 10-Q | 30



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~17. Supplemental Cash Flow Information~~

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						Three Months Ended
	September 30,						March 31,
millions	2018			2017			2019		2018
Cash paid (received)
Interest, net of amounts capitalized	$	813		$	764		$	371	$	326
Income taxes, net of refunds	48			169			18		12
Non-cash investing activities
Fair value of properties and equipment acquired	$	8		$	619		$	—	$	2
Asset retirement cost additions	261			228			71		63
Accruals of property, plant, and equipment	886			786			781		965
Net liabilities assumed (divested) in acquisitions and divestitures	(97		)	(115		)	—		(25		)
Non-cash investing and financing activities
Deferred drilling lease liability	$	—		$	14
Non-cash financing activities
Settlement of tangible equity units	$	300		$	—
Finance leases							$	6	$	—

The following table provides a reconciliation of Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents as reported in the Consolidated Statement of Cash Flows to the line items within the Consolidated Balance Sheets:


	September 30,		December 31,
millions	2018		2017		March 31, 2019			December 31, 2018
Cash and cash equivalents	$	1,883	$	4,553		$	2,026		$	1,295
Restricted cash and restricted cash equivalents included in Other Assets	110		121			134			134
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	$	1,993	$	4,674		$	2,160		$	1,429

Included in cash and cash equivalents is restricted cash and restricted cash equivalents of ~~$134~~$100 million at ~~September 30, 2018,~~March 31, 2019, and ~~$255~~$139 million at December 31, ~~2017.~~2018. Total restricted cash and restricted cash equivalents are primarily associated with certain international joint venture operations, payments of future hard-minerals royalty revenues conveyed, like-kind exchanges of property, and a judicially-controlled account related to a Brazilian tax dispute. See Note ~~17—~~18—Contingencies in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2017.~~2018.

3531 | APC 2019 FORM 10-Q



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~18.~~

17. Segment Information

Anadarko’s business segments are separately managed due to distinct operational differences. On February 28, 2019, Anadarko ~~has three~~completed the previously announced contribution and sale of substantially all of its remaining midstream assets to WES. Due to this contribution and sale, the Company will no longer report an Other Midstream segment and will now have two reporting segments: Exploration and Production ~~WES Midstream,~~ and ~~Other~~WES Midstream, which include their respective marketing results. ~~The Company has~~Prior period amounts have been reclassified ~~prior-period amounts~~ to conform to the ~~current-period~~current period’s presentation.

The Exploration and Production reporting segment is engaged in the exploration, development, production, and sale of oil, natural gas, and NGLs and in advancing its Mozambique LNG project toward FID. The WES Midstream ~~and Other Midstream~~ reporting ~~segments engage~~segment is engaged in gathering, compressing, treating, processing, and transporting of natural gas; gathering, stabilizing, and transporting of oil and NGLs; and gathering and disposing of produced water. ~~The WES Midstream segment consists of WES midstream assets, and the Other Midstream segment consists of the Company’s other midstream assets.~~

To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes; interest expense; DD&A; exploration expense; gains (losses) on divestitures, net; impairments; total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives; ~~restructuring charges;~~certain items not related to the Company’s normal operations; and less net income (loss) attributable to noncontrolling interests.

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

Management believes Adjusted EBITDAX provides information useful in assessing the Company’s operating and financial performance across periods. Adjusted EBITDAX as defined by Anadarko may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures, such as operating income. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes:


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
millions	2018			2017			2018			2017			2019		2018
Income (loss) before income taxes	$	683		$	(1,066	)	$	1,125		$	(1,616	)	$	262	$	300
Interest expense	240			230			705			682			253		228
DD&A	1,130			1,083			3,123			3,235			1,081		990
Exploration expense ⁽¹⁾	118			750			380			2,366			49		168
(Gains) losses on divestitures, net	(3		)	194			(31		)	(815		)	5		24
Impairments	172			—			319			383			—		19
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	(167		)	98			73			(12		)	316		(27		)
Restructuring charges	13			3			13			20
Reorganization-related charges													18		—
Less net income (loss) attributable to noncontrolling interests	64			58			105			182			111		53
Consolidated Adjusted EBITDAX	$	2,122		$	1,234		$	5,602		$	4,061		$	1,873	$	1,649

~~__________________________________________________________________~~

APC 2019 FORM 10-Q | 32



	⁽¹⁾FINANCIAL STATEMENTS FOOTNOTES	~~Includes restructuring charges~~ Table of ~~$20 million for the three and nine months ended September 30, 2018.~~Contents

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~18.~~

17. Segment Information (Continued)

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

millions
Exploration
& Production
WES Midstream Other Midstream
Other and
Intersegment
Eliminations
Total
Three Months Ended September 30, 2018
Sales revenues $ 3,161
$ 394
$ 39
$ 13
$ 3,607
Intersegment revenues 25
114
78
(217 ) —
Other 1
52
11
23
87
Total revenues and other ⁽¹⁾
3,187
560
128
(181 ) 3,694
Operating costs and expenses ⁽²⁾
1,059
245
55
(67 ) 1,292
Net cash from settlement of commodity derivatives —
—
—
199
199
Other (income) expense, net ⁽³⁾
—
—
—
17
17
Net income (loss) attributable to noncontrolling interests —
—
—
64
64
Total expenses and other 1,059
245
55
213
1,572
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement —
—
—
—
—
Adjusted EBITDAX $ 2,128
$ 315
$ 73
$ (394 ) $ 2,122

Three Months Ended September 30, 2017
Sales revenues $ 2,097
$ 445
$ 53
$ 15
$ 2,610
Intersegment revenues 4
119
43
(166 ) —
Other 6
39
7
28
80
Total revenues and other ⁽¹⁾
2,107
603
103
(123 ) 2,690
Operating costs and expenses ⁽²⁾
956
345
62
49
1,412
Net cash from settlement of commodity derivatives —
—
—
(16 ) (16 )
Other (income) expense, net —
—
—
2
2
Net income (loss) attributable to noncontrolling interests —
—
—
58
58
Total expenses and other 956
345
62
93
1,456
Adjusted EBITDAX $ 1,151
$ 258
$ 41
$ (216 ) $ 1,234

~~__________________________________________________________________~~



millions	Exploration & Production				WES Midstream				Other and Intersegment Eliminations				Total
Three Months Ended March 31, 2019
Sales revenues		$	2,606			$	499			$	21		$	3,126
Intersegment revenues		51				172				(223		)	—
Other		8				58				31			97
Total revenues and other ⁽¹⁾		2,665				729				(171		)	3,223
Operating costs and expenses ⁽²⁾		992				337				(89		)	1,240
Net cash from settlement of commodity derivatives		—				—				(6		)	(6		)
Other (income) expense, net ⁽³⁾		—				(36		)		38			2
Net income (loss) attributable to noncontrolling interests		—				—				111			111
Total expenses and other		992				301				54			1,347
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement		—				—				(3		)	(3		)
Adjusted EBITDAX		$	1,673			$	428			$	(228	)	$	1,873

Three Months Ended March 31, 2018
Sales revenues		$	2,656			$	355			$	15		$	3,026
Intersegment revenues		10				153				(163		)	—
Other		(9		)		37				15			43
Total revenues and other ⁽¹⁾		2,657				545				(133		)	3,069
Operating costs and expenses ⁽²⁾		870				233				214			1,317
Net cash from settlement of commodity derivatives		—				—				68			68
Other (income) expense, net		—				—				(12		)	(12		)
Net income (loss) attributable to noncontrolling interests		—				—				53			53
Total expenses and other		870				233				323			1,426
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement		—				—				6			6
Adjusted EBITDAX		$	1,787			$	312			$	(450	)	$	1,649


⁽¹⁾	Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.


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


⁽³⁾	Other (income) expense, net excludes ~~restructuring charges since these expenses are excluded from Adjusted EBITDAX.~~

~~Table of Contents~~

A~~NADARKO PETROLEUM CORPORATION~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~18. Segment Information (Continued)~~

millions
Exploration
& Production
WES Midstream Other Midstream
Other and
Intersegment
Eliminations
Total
Nine Months Ended September 30, 2018
Sales revenues $ 8,589
$ 1,063
$ 73
$ 76
$ 9,801
Intersegment revenues 49
369
188
(606 ) —
Other (5 ) 113
30
63
201
Total revenues and other ⁽¹⁾
8,633
1,545
291
(467 ) 10,002
Operating costs and expenses ⁽²⁾
2,840
687
134
195
3,856
Net cash from settlement of commodity derivatives —
—
—
437
437
Other (income) expense, net ⁽³⁾
—
—
—
9
9
Net income (loss) attributable to noncontrolling interests —
—
—
105
105
Total expenses and other 2,840
687
134
746
4,407
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement —
—
—
7
7
Adjusted EBITDAX $ 5,793
$ 858
$ 157
$ (1,206 ) $ 5,602

Nine Months Ended September 30, 2017
Sales revenues $ 6,500

$ 1,213
$ 134
$ 80

$ 7,927
Intersegment revenues 10

387
125
(522 )
—
Other 16

124
20
77

237
Total revenues and other ⁽¹⁾
6,526

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

936
168
135

3,918
Net cash from settlement of commodity derivatives —

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

—
—
24

24
Net income (loss) attributable to noncontrolling interests —

—
—
182

182
Total expenses and other 2,679

936
168
318

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

—
—
(2 )
(2 )
Adjusted EBITDAX $ 3,847

$ 788
$ 111
$ (685 )
$ 4,061

~~__________________________________________________________________~~


⁽¹⁾	~~Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.~~


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


⁽³⁾	~~Other (income) expense, net excludes restructuring~~reorganization-related charges since these expenses are excluded from Adjusted EBITDAX.

33 | APC 2019 FORM 10-Q



	FINANCIAL STATEMENTS FOOTNOTES	Table of Contents

17. Segment Information (Continued)

The following summarizes selected financial information for Anadarko’s reporting segments:



millions	Exploration & Production			WES Midstream			Other and Intersegment Eliminations			Total
March 31, 2019
Net properties and equipment		$	18,342		$	8,630		$	1,964		$	28,936
Capital expenditures ⁽¹⁾		$	922		$	315		$	59		$	1,296
Goodwill		$	4,343		$	446		$	—		$	4,789

December 31, 2018
Net properties and equipment		$	18,267		$	8,410		$	1,938		$	28,615
Capital expenditures ⁽¹⁾		$	4,103		$	1,912		$	170		$	6,185
Goodwill		$	4,343		$	446		$	—		$	4,789


⁽¹⁾	WES Midstream includes $49 million at March 31, 2019, and $734 million at December 31, 2018, of capitalized costs incurred prior to the contribution and sale of midstream assets to WES.

APC 2019 FORM 10-Q | 34



	MANAGEMENT’S DISCUSSION AND ANALYSIS INDEX	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.

~~the Company’s assumptions about energy markets~~

~~production and sales volume levels~~

~~levels of oil, natural-gas, and NGLs reserves~~

~~operating results~~

~~competitive conditions~~

~~technology~~

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

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

~~volatility in the commodity-futures market~~

~~weather~~

~~inflation~~

~~availability of goods and services, including unexpected changes in costs~~

~~drilling and other operational risks~~

~~processing volumes, pipeline throughput, and produced water disposal~~

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

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

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

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

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

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

~~the Company’s ability to successfully monetize select assets, repay or refinance its debt, meet its debt-reduction expectations, and the impact of changes in the Company’s credit ratings~~

~~the Company’s ability to successfully complete its Share-Repurchase Program~~

the Company’s ability to successfully plan, secure additional government approvals, enter into additional long-term sales contracts, take FID and the timing thereof, finance, build, and operate the necessary infrastructure and LNG park in Mozambique

~~uncertainties and liabilities associated with acquired and divested properties and businesses~~

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

~~physical, digital, internal, and external security breaches~~

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

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

other factors discussed below and elsewhere in “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017, this Form 10-Q, and in the Company’s other public filings, press releases, and discussions with Company management

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Form 10-Q in Part I, Item 1; the information set forth in the Risk Factors under Part II, Item 1A; the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Part II, Item 8 of the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2017;~~2018; 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, ~~2017.~~2018.



Index	Page
Management Overview	36
Financial Results	38
Liquidity and Capital Resources	49
Recent Accounting Developments	52

35 | APC 2019 FORM 10-Q



	MANAGEMENT’S DISCUSSION AND ANALYSIS MANAGEMENT OVERVIEW	Table of Contents

MANAGEMENT OVERVIEW

Anadarko’s ~~strategy is~~strategic objectives are to explore for, develop, and commercialize resources globally; ensure health, safety, and environmental excellence; ~~and~~ focus on financial discipline, flexibility, and value creation; ~~while demonstrating~~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 commodity prices, which ~~determine~~affect the value the Company receives from its sales of oil, natural gas, and NGLs.

On April 11, 2019, the Company entered into the Chevron Merger Agreement pursuant to which, and subject to the conditions of the agreement, all outstanding shares of Anadarko will be acquired by Chevron in a stock and cash transaction valued at $33 billion, or $65.00 per share, as of the announcement date. Under the terms of the Chevron Merger Agreement, Anadarko stockholders will receive 0.3869 of a share of Chevron common stock and $16.25 in cash for each Anadarko share. The transaction was approved by the Boards of Directors of both companies. On May 6, 2019, Anadarko announced that the Board unanimously determined that the Occidental Proposal constituted a “Superior Proposal” as defined in the Chevron Merger Agreement. Under the terms of the Occidental Proposal, Occidental would acquire Anadarko for consideration consisting of $59.00 in cash and 0.2934 of a share of Occidental common stock per share of Anadarko common stock. Anadarko has notified Chevron that (i) the Board has unanimously determined that the Occidental Proposal constitutes a "Superior Proposal" and (ii) after complying with its obligations to Chevron under the Chevron Merger Agreement, Anadarko intends to terminate the Chevron Merger Agreement in order to enter into a definitive merger agreement with Occidental in connection with the Occidental Proposal. Pursuant to the Chevron Merger Agreement, Chevron has the right, during the four business day period ending on May 10, 2019, which may be extended in accordance with the terms of the Chevron Merger Agreement, to propose revisions to the terms of the Chevron Merger Agreement, or to make another proposal. If Anadarko terminates the Chevron Merger Agreement in order to enter into a definitive agreement with respect to the Occidental Proposal, Anadarko will pay Chevron a $1.0 billion termination fee as required by the Chevron Merger Agreement. The Chevron Merger Agreement remains in effect unless and until terminated, and accordingly, the Board reaffirms its existing recommendation of the transaction with Chevron at this time. Either transaction would be subject to Anadarko stockholder approval, regulatory approvals, and other customary closing conditions.

On February 28, 2019, Anadarko completed the previously announced contribution and sale of substantially all of its midstream assets, which consisted of oil infrastructure assets in the DJ basin and oil and water infrastructure assets in the Delaware basin, to WES Operating for $4.0 billion, with $2.0 billion of cash proceeds and $2.0 billion in WES Operating common units. This transaction is expected to increase cash distributions paid by WES to Anadarko in 2019 and reduce Anadarko’s future midstream capital funding requirements. Immediately after the asset contribution and sale, a wholly owned subsidiary of WES merged with and into WES Operating, with WES Operating continuing as the surviving entity and a subsidiary of WES. The merger is expected to simplify the midstream structure, lower the weighted-average cost of capital for WES through the elimination of incentive distribution rights, and increase the overall trading liquidity of WES.

The Company ~~continues~~remains committed to ~~leverage its foundational principle of efficient capital allocation to generate attractive returns on, and of, capital while~~ investing within cash ~~flow.~~flow in a $50 oil-price environment. Anadarko ~~also continues to focus~~is focused on ~~cash-margin improvement~~capital efficiency and maximizing cash flow generation, and has actively managed its portfolio to focus on higher-return, oil-levered opportunities in areas where it possesses both scale and competitive advantages, namely in the Delaware and DJ basins in the U.S. onshore and in the deepwater Gulf of Mexico. The Company ~~expects~~plans to ~~use excess~~deploy a portion of its cash flow generated from its Gulf of Mexico, Algeria, Ghana, and DJ basin assets to fund ~~the growth of its~~investments in other ~~unconventional~~ assets ~~in the U.S. onshore and improve returns to shareholders.~~

In the third quarter of 2018, the Company expanded the Share-Repurchase Program from $3.0 billion to $4.0 billion and completed the repurchase of $500 million of the Company’s common stock, bringing the total repurchases to $3.5 billion. The Company also announced a $500 million increase to its debt-reduction expectations, bringing the total planned debt reduction to $1.5 billion. As of September 30, 2018, the Company had repaid $114 million of debt at maturity and plans to retire $900 million of fixed-rate debt maturing in the first half of 2019. These actions demonstrate the strength of the Company’s portfolio and commitment to capital efficiency.that generate attractive cash returns.

In the Delaware basin, ~~located in Texas,~~ the Company continues to build out one of the most expansive and integrated infrastructure positions in the region ~~and is transitioning to~~as it transitions toward multi-well pad development, primarily in Reeves and Loving counties. The first ROTF in Reeves County was completed and brought online during the second quarter of 2018. During the third quarter of 2018, final commissioning activities were completed for the second ROTF in Loving County. New wells in the area were brought online and flowed into these ROTFs during the third quarter of 2018. Additionally, the WES-operated Mentone I processing train at the DBM Complex is expected to commence operations in the fourth quarter of 2018, which will facilitate incremental production growth of the asset. As of the end of the third quarter of 2018, Anadarko had secured sufficient takeaway capacity with approximately 50% of its Delaware basin operated oil volumes being sold at Gulf Coast markets via the Enterprise pipeline to Houston. This capacity is expected to increase to approximately 100% in 2019, when the Plains Cactus II pipeline to Corpus Christi is brought online. The Company ended the third quarter of 2018 with 7 operated drilling rigs and 5 completion crews in the Delaware basin, which compares to 13 operated drilling rigs and 6 completion crews at the end of the third quarter of 2017.

~~In the DJ basin, located in Colorado, the Company~~also continues to leverage its minerals-interest ownership and extensive infrastructure position in the DJ basin to deliver development wells with attractive rates of return. ~~The Company ended~~In the third quarter of 2018 with four operated drilling rigs and two completion crews in the DJ basin, which compares to six operated drilling rigs and four completion crews at the end of the third quarter of 2017. The Colorado general election ballot in November 2018 will include Proposition 112, which, if passed, would amend the Colorado Revised Statutes to require that new oil and gas development on non-federal lands take place a minimum distance of 2,500 feet from occupied buildings such as homes, schools, and hospitals, and other areas designated as vulnerable. Such setbacks would effectively ban new oil and gas drilling and hydraulic fracturing on a substantial portion of Colorado’s non-federal lands. If Proposition 112 passes, and is not amended or repealed by the state legislature, resulting in more stringent limitations on the production and development of oil and natural gas in Colorado, the Company will be limited or precluded in the drilling of wells or in the volumes that are ultimately able to be produced from assets in Colorado. Given the depth and quality of the Company’s portfolio, if this occurs, the Company would expect to reallocate capital in order to continue to focus on higher-return, oil-levered opportunities in areas where it possesses both scale and competitive advantages, namely in the Delaware basin and in the deepwater Gulf of Mexico, ~~and accelerate investments in~~ the ~~emerging oil play in Wyoming’s Powder River basin.~~

~~In the deepwater Gulf of Mexico, Anadarko has two floating drillships and one platform rig available to conduct~~Company is conducting operations that are focused toward high-return oil development opportunities near the Company’s expansive infrastructure. ~~Internationally, drilling continues~~

The Company has returned capital directly to its investors through its quarterly cash dividend, its authorized Share-Repurchase Program, and its debt-reduction program. Since the Share-Repurchase Program was announced in ~~offshore Ghana with new development activities at the TEN and Jubilee fields.~~

~~In order to reduce commodity-price risk and increase the predictability of 2018 cash flows,~~2017, the Company has ~~strategic derivative positions covering approximately 50%~~repurchased 65 million shares of its ~~anticipated oil sales volumes and approximately 55% of its anticipated natural-gas sales volumes~~common stock for $3.75 billion. In the ~~remainder of 2018. See~~ ~~Note 8—Derivative Instruments~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Part I, Item 1 of this Form 10-Q.~~

~~Significant operating and financial activities for the third~~first quarter of ~~2018 include the following:~~

~~Total Company~~

~~The Company’s overall sales-volume product mix increased to 58% oil in the third quarter~~2019, Anadarko repaid $600 million of ~~2018, compared to 56% in the third quarter of 2017.~~

~~The Company’s third-quarter oil sales volumes averaged 397 MBbls/d, representing a 13% increase over the third quarter of 2017.~~

~~U.S. Onshore~~

~~U.S. onshore oil sales volumes increased by 35 MBbls/d, representing a 26% increase from the third quarter of 2017.~~

~~Sales volumes for the Delaware basin increased by 32 MBbls/d, representing an 83% increase from the third quarter of 2017, primarily due to continued drilling~~debt at maturity and ~~completion activities and midstream infrastructure additions in 2018.~~

In the Delaware basin, the second ROTF was completed in Loving County, with 47 wells flowing into the facility by the end of the third quarter. Additionally, 23 new wells were brought online at the Reeves County ROTF during the quarter.

~~International~~

~~Ghana~~

In the TEN fields of Ghana, the operator resumed drilling operations in early 2018, with one well completed and brought online in the third quarter. Subsequent to quarter end, drilling began on a second well.

~~In the Jubilee field of Ghana, the operator drilled two wells during the second quarter of 2018, with the first of these wells completed and brought online in the third quarter.~~

~~At the end of the third quarter, a second drillship was mobilized for drilling operations in the TEN and Jubilee fields.~~

~~Mozambique~~

~~The Company continues to make progress converting non-binding commitments to fully termed Sales and Purchase Agreements as required to support project financing arrangements and progress to FID.~~

~~Recommendations for award of the offshore contractor and equipment providers are awaiting Government of Mozambique approval.~~

Site preparation activities are fully underway at the Afungi onshore site, as major infrastructure and resettlement projects are proceeding as planned, positioning the area for construction of the LNG facilities.

~~In the third quarter, Offshore Area 4, which is owned and operated by third parties, joined the Anadarko-led resettlement and airstrip projects as a 50% participant.~~

~~The Company remains on track for FID consideration in the first half of 2019.~~

~~Financial~~

~~The Company generated $1.6 billion of cash flows from operations and ended the third quarter with $1.9 billion of cash.~~

~~In the third quarter, the Company completed the repurchase of~~redeemed an additional ~~$500~~$300 million of debt prior to maturity, bringing total repayments under the ~~Company’s common stock~~debt-reduction program to $1.5 billion. No additional share repurchases under the Share-Repurchase ~~Program.~~Program or debt retirements are anticipated pursuant to the terms of the Chevron Merger Agreement.

~~FINANCIAL RESULTS~~

APC 2019 FORM 10-Q | 36



	MANAGEMENT’S DISCUSSION AND ANALYSIS MANAGEMENT OVERVIEW	Table of Contents

Three Months Ended Nine Months Ended
September 30, September 30,
millions except per-share amounts 2018 2017 2018 2017
Oil, natural-gas, and NGLs sales $ 3,186
$ 2,101
$ 8,638
$ 6,510
Gathering, processing, and marketing sales 421
509
1,163
1,417
Gains (losses) on divestitures and other, net 90
(114 ) 232
1,052
Revenues and other $ 3,697
$ 2,496
$ 10,033
$ 8,979
Costs and expenses 2,718
3,245
7,684
9,895
Other (income) expense 296
317
1,224
700
Income tax expense (benefit) 256
(425 ) 507
(366 )
Net income (loss) attributable to common stockholders $ 363
$ (699 ) $ 513
$ (1,432 )
Net income (loss) per common share attributable to common stockholders—diluted $ 0.72
$ (1.27 ) $ 0.99
$ (2.61 )
Average number of common shares outstanding—diluted 500
553
508
552

Significant First Quarter 2019 Operating and Financial Activities

Total Company


–	The Company’s oil sales volume averaged 412 MBbls/d in the first quarter of 2019, representing an 11% increase from the first quarter of 2018, primarily due to increased sales volume from the Delaware basin and the Gulf of Mexico.


–	The Company’s overall sales-volume product mix in the first quarter of 2019 is 58% oil and 73% liquids.

U.S. Onshore


–	Total sales volume averaged 465 MBOE/d in the first quarter of 2019, representing a 15% increase from the first quarter of 2018, and oil sales volume averaged 195 MBbls/d in the first quarter of 2019, representing a 22% increase from the first quarter of 2018, primarily due to continued drilling and completion activities and midstream infrastructure additions.


–	The second train at the WES-owned Mentone natural-gas processing plant in the Delaware basin was placed in service, adding 200 MMcf/d of natural-gas processing capacity to the West Texas Complex.

Gulf of Mexico


–	Oil sales volume averaged 138 MBbls/d in the first quarter of 2019, representing a 9% increase from the first quarter of 2018, primarily due to new wells coming online at Horn Mountain and Holstein, planned downtime at various platforms in 2018, and lower-than-expected downtime at various platforms in 2019, partially offset by natural production declines.

Ghana


–	In the TEN field, drilling operations concluded on a production well, and a previously drilled well was completed and brought online.


–	In the Jubilee field, the operator drilled a water injector well and drilling operations are ongoing for an additional production well.

Mozambique

–

Anadarko and its Area 1 co-venturers executed two additional long-term sale and purchase agreements with Bharat Gas Resources Ltd., a wholly owned subsidiary of Bharat Petroleum Corporation Ltd. of India, and Pertamina, the state-owned oil and gas company of Indonesia, each for 1.0 MTPA, bringing total contracted volume to approximately 9.5 MTPA, which satisfies the contracted offtake volume required for FID.


–	Anadarko and its Area 1 co-venturers were designated first mover by the Government of Mozambique for the onshore LNG project. This enables Anadarko, as operator of Area 1, to construct the shared marine facilities, on behalf of the Area 1 and Area 4 projects.


–	The Company is working to finalize project finance arrangements and has received commitments from the majority of lenders. Additionally, final partner and government-related approvals are progressing as the Company expects to announce a final investment decision on June 18, 2019.

Financial


–	The Company generated $1.1 billion of cash flow from operations and ended the first quarter of 2019 with $2.0 billion of cash.


–	The Company retired $900 million of debt during the first quarter of 2019.

37 | APC 2019 FORM 10-Q



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents

FINANCIAL RESULTS



	Three Months Ended
	March 31,
millions except per-share amounts	2019			2018
Oil, natural-gas, and NGL sales	$	2,656		$	2,666
Gathering, processing, and marketing sales	470			360
Gains (losses) on divestitures and other, net	92			19
Revenues and other	$	3,218		$	3,045
Costs and expenses	2,384			2,494
Other (income) expense	572			251
Income tax expense (benefit)	166			126
Net income (loss) attributable to common stockholders	$	(15	)	$	121
Net income (loss) per common share attributable to common stockholders—diluted	$	(0.03	)	$	0.22
Average number of common shares outstanding—diluted	490			519

The following discussion pertains to Anadarko’s results of operations, financial condition, and changes in financial condition. Any increases or decreases “for the three months ended ~~September 30, 2018,~~March 31, 2019,” refer to the comparison of the three months ended ~~September 30, 2018,~~March 31, 2019, to the three months ended September 30, 2017, and any increases or decreases “for the nine months ended September 30, 2018,” refer to the comparison of the nine months ended September 30, 2018, to the nine months ended September 30, 2017.March 31, 2018. The primary factors that affect the Company’s results of operations include commodity prices for oil, natural gas, and NGLs; sales ~~volumes;~~volume; the cost of finding and developing such reserves; and operating costs.

~~Revenues and Sales Volumes~~

APC 2019 FORM 10-Q | 38



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents

Three Months Ended
September 30,
millions except percentages Oil Natural Gas NGLs Total
2017 sales revenues $ 1,567
$ 269
$ 265
$ 2,101
Changes associated with prices 806
(33 ) 78
851
Changes associated with sales volumes 199
(4 ) 39
234
2018 sales revenues $ 2,572
$ 232
$ 382
$ 3,186
Increase (decrease) vs. 2017 64 % (14 )% 44 % 52 %

Nine Months Ended
September 30,
millions except percentages Oil Natural Gas NGLs Total
2017 sales revenues $ 4,652
$ 1,090
$ 768
$ 6,510
Changes associated with prices 1,949
(143 ) 227
2,033
Changes associated with sales volumes 363
(265 ) (3 ) 95
2018 sales revenues $ 6,964
$ 682
$ 992
$ 8,638
Increase (decrease) vs. 2017 50 % (37 )% 29 % 33 %

REVENUES AND SALES VOLUME

E&P Sales Revenues by Product

The ~~above~~ table below illustrates the effects of changes in prices and sales ~~volumes. The~~volume. Price changes for the three months ended March 31, 2019 were due to lower oil and NGL prices in ~~sales volumes~~2019. Sales volume changes for the three months ended March 31, 2019 primarily ~~include~~included increases associated with continued drilling and completion activities in the Delaware and DJ ~~basins and decreases associated with U.S. onshore asset divestitures in 2017 and 2018.~~basins.

Total E&P Sales Revenues

The following provides Anadarko’s sales ~~volumes~~volume for the three ~~and nine~~ months ended ~~September 30:~~March 31:

Three Months Ended Nine Months Ended
September 30, September 30,
2018 Inc (Dec) vs. 2017 2017 2018 Inc (Dec) vs. 2017 2017
Barrels of Oil Equivalent
(MMBOE except percentages)
United States 53
7 % 50
153
(5 )% 161
International 10
18
8
26
(3 ) 26
Total barrels of oil equivalent 63
9
58
179
(4 ) 187

Barrels of Oil Equivalent per Day
(MBOE/d except percentages)
United States 575
7 % 535
560
(5 )% 587
International 107
18
91
94
(3 ) 96
Total barrels of oil equivalent per day 682
9
626
654
(4 ) 683



	Barrels of Oil Equivalent (MMBOE)		Barrels of Oil Equivalent per Day (MBOE/d)
	2019	2018	2019	2018
United States	56	50	631	555
International	8	8	84	88
Total	64	58	715	643

Sales ~~volumes represent~~volume represents actual production ~~volumes~~volume adjusted for changes in commodity inventories as well as natural-gas production ~~volumes~~volume provided to satisfy a commitment under the Jubilee development plan in Ghana. The Company has derivative instruments in place to reduce the price risk associated with future production. For additional information, see Note 8—7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. Production of oil, natural gas, and NGLs is usually not affected by seasonal swings in demand.

39 | APC 2019 FORM 10-Q



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents

Oil Sales Revenues, Volume, and Average Prices

Oil Sales Revenues ~~Average Prices, and Volumes~~

Three Months Ended Nine Months Ended
September 30, September 30,
2018 Inc (Dec) vs. 2017 2017 2018 Inc (Dec) vs. 2017 2017
Oil sales revenues (millions)
$ 2,572
64 % $ 1,567
$ 6,964
50 % $ 4,652

United States
Sales volumes—MMBbls 26
12 % 25
78
12 % 71
MBbls/d 296
12
266
288
12
259
Price per barrel $ 68.25
46
$ 46.89
$ 65.96
38
$ 47.63

International
Sales volumes—MMBbls 10
16 % 8
25
(3 )% 25
MBbls/d 101
16
87
89
(3 ) 91
Price per barrel $ 76.55
46
$ 52.61
$ 72.85
41
$ 51.59

Total
Sales volumes—MMBbls 36
13 % 33
103
8 % 96
MBbls/d 397
13
353
377
8
350
Price per barrel $ 70.37
46
$ 48.31
$ 67.57
39
$ 48.66

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

millions
Change in
Revenues

Due to Change
in Prices

Due to Change
in Volumes
Three months ended September 30, 2018 vs. 2017 $ 1,005
$ 806
$ 199
Nine months ended September 30, 2018 vs. 2017 2,312
1,949
363



	Three Months Ended
	March 31,
	2019		2018
Oil sales revenues (millions)	$	2,096	$	2,127

Average price per barrel
United States	$	55.14	$	62.58
International	62.33		67.39
Total	$	56.51	$	63.66

Sales volume (MMBbls)
United States	29		25
International	8		8
Total	37		33

Sales volume per day (MBbls/d)
United States	333		288
International	79		83
Total	412		371

Oil Prices

The average oil price received ~~increased~~decreased for the three ~~and nine~~ months ended ~~September 30, 2018,~~March 31, 2019, primarily due to concerns of oil demand weakness from a ~~supply shortfall as a result of reductions in output from Iran as the U.S. reimposes sanctions as well as decreased production from Venezuela.~~slowing global economy.

APC 2019 FORM 10-Q | 40



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents

Oil Sales ~~Volumes~~Volume

~~2018~~2019 vs. ~~2017~~2018 The Company’s oil sales ~~volumes~~volume increased by 4441 MBbls/d for the three months ended ~~September 30, 2018, and 27 MBbls/d for the nine months ended September 30, 2018,~~March 31, 2019, primarily due to the following:

U.S. Onshore

Sales volumes for the Delaware basin increased by 32 MBbls/d for the three months ended September 30, 2018, and 27 MBbls/d for the nine months ended September 30, 2018, due to continued drilling and completion activities and midstream infrastructure additions in 2018.

Sales volumes for the DJ basin increased by 13 MBbls/d for the three months ended September 30, 2018, and 19 MBbls/d for the nine months ended September 30, 2018, primarily due to continued drilling and completion activities in 2018.

Divestitures resulted in decreased sales volumes of 12 MBbls/d for the three months ended September 30, 2018, and 18 MBbls/d for the nine months ended September 30, 2018, primarily related to the sale of the Alaska nonoperated assets in the first quarter of 2018 and the Eagleford and West Chalk assets in the first half of 2017.


–	Sales volume for the Delaware basin increased by 30 MBbls/d for the three months ended March 31, 2019, primarily due to continued drilling and completion activities and midstream infrastructure additions in 2019.

Gulf of Mexico

Sales volumes for the Gulf of Mexico decreased by 5 MBbls/d for the three months ended September 30, 2018, and remained flat for the nine months ended September 30, 2018, primarily due to natural production declines and planned downtime at various platforms, partially offset by continued tie-back activity at Horn Mountain and Marlin.


–	Sales volume for the Gulf of Mexico increased by 10 MBbls/d for the three months ended March 31, 2019, primarily due to new wells coming online at Horn Mountain and Holstein, planned downtime at various platforms in 2018, and lower-than-expected downtime at various platforms in 2019, partially offset by natural production declines.

International


–	Sales volume for Algeria increased by 6 MBbls/d for the three months ended March 31, 2019, primarily due to the size and timing of liftings.


–	Sales volume for Ghana decreased by 10 MBbls/d for the three months ended March 31, 2019, primarily due to the timing of liftings.

Sales volumes for Algeria increased by 6 MBbls/d for the three months ended September 30, 2018, primarily due to the timing of liftings. Sales volumes decreased by 5 MBbls/d for the nine months ended September 30, 2018, primarily due to the timing of liftings and a decrease in production driven by facility downtime for statutory maintenance in early 2018.

~~Sales~~41 ~~volumes~~| APC ~~for~~2019 FORM 10-Q ~~Ghanaincreased~~by8~~MBbls/dfor the three months ended September 30, 2018, and3 MBbls/d for the nine months ended September 30, 2018, primarily due to increased field performance at the TEN field, which resulted in an additional lifting in the third quarter of 2018.~~



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents

Natural-Gas Sales Revenues, Volume, and Average Prices

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

Three Months Ended Nine Months Ended
September 30, September 30,
2018 Inc (Dec) vs. 2017 2017 2018 Inc (Dec) vs. 2017 2017
Natural-gas sales revenues (millions)
$ 232
(14 )% $ 269
$ 682
(37 )% $ 1,090

United States
Sales volumes—Bcf 98
(1 )% 100
287
(24 )% 380
MMcf/d 1,071
(1 ) 1,086
1,053
(24 ) 1,392
Price per Mcf $ 2.35
(13 ) $ 2.69
$ 2.37
(17 ) $ 2.87

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

millions
Change in
Revenues

Due to Change
in Prices

Due to Change
in Volumes
Three months ended September 30, 2018 vs. 2017 $ (37 ) $ (33 ) $ (4 )
Nine months ended September 30, 2018 vs. 2017 (408 ) (143 ) (265 )

~~Natural-Gas Prices~~

The average natural-gas price received decreased for the three and nine months ended September 30, 2018, primarily due to increased U.S. natural-gas production, partially offset by increased weather-driven consumer demand coupled with an increase in natural-gas exports to Mexico and LNG exports.

~~Natural-Gas Sales Volumes~~

~~2018 vs. 2017~~The Company’s natural-gas sales volumes remained relatively flat for the three months ended September 30, 2018. Natural-gas sales volumes decreased by 339 MMcf/d for the nine months ended September 30, 2018, primarily due to the sale of the Marcellus, Eagleford, and Utah CBM assets in the first half of 2017 and the Moxa assets in the second half of 2017.

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

Three Months Ended Nine Months Ended
September 30, September 30,
2018 Inc (Dec) vs. 2017 2017 2018 Inc (Dec) vs. 2017 2017
Natural-gas liquids sales revenues (millions)
$ 382
44 % $ 265
$ 992
29 % $ 768

Total
Sales volumes—MMBbls ⁽¹⁾
10
15 % 9
28
— % 28
MBbls/d ⁽¹⁾
106
15
92
101
—
101
Price per barrel $ 39.16
26
$ 31.15
$ 36.00
30
$ 27.77

~~_______________________________________________________________________________~~



	Three Months Ended
	March 31,
	2019		2018
Natural-gas sales revenues (millions)	$	320	$	247

Average price per Mcf	$	3.09	$	2.61

Sales volume (Bcf) ⁽¹⁾	104		95
Sales volume per day (MMcf/d) ⁽¹⁾	1,151		1,051


⁽¹⁾	~~The percentage of total and daily NGLs~~ Natural-gas sales ~~volumes from~~volume primarily originates in the ~~U.S. was approximately 95% for three and nine months ended September 30, 2018, and 2017.~~United States.

NGLs sales represent revenues from the sale of product derived from the processing of Anadarko’s natural-gas production. The following summarizes primary drivers for the change in NGLs sales revenues:

millions
Change in
Revenues

Due to Change
in Prices

Due to Change
in Volumes
Three months ended September 30, 2018 vs. 2017 $ 117
$ 78
$ 39
Nine months ended September 30, 2018 vs. 2017 224
227
(3 )

~~NGLs~~Natural-Gas Prices

The average ~~NGLs~~natural-gas price received increased for the three ~~and nine~~ months ended ~~September 30, 2018,~~March 31, 2019, primarily due to increased residential and commercial demand from colder than normal temperatures and improved price differentials in the DJ basin.

Natural-Gas Sales Volume

2019 vs. 2018The Company’s natural-gas sales volume increased by 100 MMcf/d for ~~ethane~~the three months ended March 31, 2019, primarily due to ~~supply newly-constructed ethane cracker facilities~~continued drilling and completion activities in the Delaware and DJ basins in 2019.

APC 2019 FORM 10-Q | 42



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents

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

Natural-Gas Liquids Sales Revenues



	Three Months Ended
	March 31,
	2019		2018
Natural-gas liquids sales revenues (millions)	$	240	$	292

Average price per barrel	$	24.11	$	33.63

Sales volume (MMBbls) ⁽¹⁾	10		9
Sales volume (MBbls/d) ⁽¹⁾	111		97


⁽¹⁾	Approximately 95% of NGL sales volume was from the United States.

NGL Prices

The average NGL price received decreased for the three months ended March 31, 2019, primarily due to higher overall NGL production as ~~well as higher propane~~a result of infrastructure additions and lower consumption stemming from both reduced chemical plant utilization and stagnant LPG exports.

~~NGLs~~NGL Sales ~~Volumes~~Volume

~~2018~~2019 vs. ~~2017~~2018 The Company’s ~~NGLs~~NGL sales ~~volumes~~volume increased by 14 MBbls/d for the three months ended ~~September 30, 2018, and remained flat for the nine months ended September 30, 2018, primarily due to the following:~~

~~U.S. Onshore~~

~~Sales volumes for the Delaware basin increased by 14 MBbls/d for the three months ended September 30, 2018, and 9 MBbls/d for the nine months ended September 30, 2018,~~March 31, 2019, primarily due to continued drilling and completion activities and midstream infrastructure additions in ~~2018.~~

~~Sales volumes for other U.S. onshore assets decreased by 8 MBbls/d for~~ the ~~nine months ended September 30, 2018, primarily due to the sale of the Eagleford and West Chalk assets~~Delaware basin in ~~the first half of 2017 and the Moxa assets in the second half of 2017.~~2019.

~~Gathering, Processing, and Marketing~~

43 | APC 2019 FORM 10-Q

Three Months Ended Nine Months Ended
September 30, September 30,
millions except percentages 2018 Inc (Dec) vs. 2017 2017 2018 Inc (Dec) vs. 2017 2017
Gathering, processing, and marketing sales ⁽¹⁾
$ 421
(17 )% $ 509
$ 1,163
(18 )% $ 1,417
Gathering, processing, and marketing expense ⁽¹⁾
256
(35 ) 396
745
(32 ) 1,101
Gathering, processing, and marketing, net $ 165
46
$ 113
$ 418
32
$ 316

~~__________________________________________________________________~~



	⁽¹⁾MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	~~As a result~~Table of ~~adopting ASU 2014-09,~~ Contents~~Revenue from Contracts with Customers (Topic 606)~~, as of January 1, 2018, gathering, processing, and marketing sales decreased by $296 million for the three months ended September 30, 2018, and $781 million for the nine months ended September 30, 2018, and gathering, processing, and marketing expenses decreased by $295 million for the three months ended September 30, 2018, and $775 million for the nine months ended September 30, 2018. Refer to ~~Note 2—Revenue from Contracts with Customersin the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Part I, Item 1 of this Form 10-Q for further information.~~

Gathering, Processing, and Marketing



	Three Months Ended
	March 31,
millions	2019		2018
Gathering, processing, and marketing sales	$	470	$	360
Gathering, processing, and marketing expense	256		237
Gathering, processing, and marketing, net	$	214	$	123

Gathering and processing sales include fee revenue earned by providing gathering, processing, compression, and treating services to third parties as well as revenue from the sale of NGLs and remaining residue gas extracted from natural gas purchased from third parties and processed by ~~Anadarko.~~WES. The net margin from the sale of NGLs and residue gas for service customers when ~~Anadarko~~WES is acting as an agent is also included. Gathering and processing expense includes the cost of third-party natural gas purchased and processed by ~~Anadarko~~WES as well as transportation and other operating expenses related to ~~the Company’s~~WES’s costs to perform gathering and processing activities.

Marketing sales include the margin earned from purchasing and selling third-party oil and natural gas. Marketing expense includes transportation and other operating expenses related to the Company’s costs to perform third-party marketing activities.

Total gathering, processing, and marketing, net increased by ~~$52~~$91 million for the three months ended ~~September 30, 2018, and by $102 million for the nine months ended September 30, 2018,~~March 31, 2019, primarily due to increased throughput ~~volumes~~volume at the ~~DBM~~West Texas Complex ~~which were partially~~and the DJ Basin Complex, coupled with an increase in oil marketing margins primarily due to increased ~~capacity from~~third-party oil volume purchased and transported to the ~~200 MMcf/d cryogenic train that commenced service in December 2017, and increased throughput volumes at the DJ Basin Complex.~~Gulf Coast.

Gains (Losses) on Divestitures and Other, net


	Three Months Ended							Nine Months Ended						Three Months Ended
	September 30,							September 30,						March 31,
millions except percentages	2018		Inc (Dec) vs. 2017		2017			2018		Inc (Dec) vs. 2017		2017
millions														2019			2018
Gains (losses) on divestitures, net	$	3	102	%	$	(194	)	$	31	(96	)%	$	815	$	(5	)	$	(24	)
Other	87		9		80			201		(15	)	237		97			43
Gains (losses) on divestitures and other, net	$	90	179		$	(114	)	$	232	(78	)	$	1,052	$	92		$	19

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

Earnings (losses) from equity investments increased $43 million for the three months ended March 31, 2019, primarily related to the Company’s investments in midstream joint ventures. During the ~~nine~~three months ended ~~September 30,~~March 31, 2018, ~~and 2017,~~ Anadarko divested certain non-core U.S. onshore ~~and Gulf of Mexico~~ assets. See Note 4—Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information.

~~Costs and Expenses~~

APC 2019 FORM 10-Q | 44



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents

COSTS AND EXPENSES

The following provides Anadarko’s total costs and expenses for the three ~~and nine~~ months ended ~~September 30:~~March 31:


	Three Months Ended				Nine Months Ended				Three Months Ended
	September 30,				September 30,				March 31,
millions	2018		2017		2018		2017		2019		2018
Oil and gas operating	$	294	$	253	$	845	$	738	$	289	$	276
Oil and gas transportation	228		220		633		698		222		196
Exploration	118		750		380		2,366		49		168
Gathering, processing, and marketing ⁽¹⁾	256		396		745		1,101		256		237
G&A	248		261		814		768		267		278
DD&A	1,130		1,083		3,123		3,235		1,081		990
Production, property, and other taxes	246		159		637		449		199		190
Impairments	172		—		319		383		—		19
Other operating expense	26		123		188		157		21		140
Total	$	2,718	$	3,245	$	7,684	$	9,895	$	2,384	$	2,494


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

~~Oil and Gas Operating and Transportation Expenses~~

Three Months Ended
Nine Months Ended
September 30,
September 30,
2018 Inc (Dec) vs. 2017 2017 2018 Inc (Dec) vs. 2017 2017
Oil and gas operating (millions)
$ 294
16 % $ 253
$ 845
14 % $ 738
Oil and gas operating—per BOE 4.69
7
4.40
4.73
20
3.95
Oil and gas transportation (millions)
228
4
220
633
(9 ) 698
Oil and gas transportation—per BOE 3.63
(5 ) 3.82
3.54
(5 ) 3.74

Oil and Gas Operating Expenses

~~Oil and Gas Operating Expense~~



	Three Months Ended
	March 31,
	2019		2018
Oil and gas operating (millions)	$	289	$	276
Oil and gas operating—per BOE	4.50		4.77

Oil and gas operating expense increased by ~~$107~~$13 million for the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, primarily due to the following:

higher operating costs of $97 million, primarily related to increased activity in the DJ and Delaware basins, partially offset by lower expenses of $63 million as a result of U.S. onshore asset divestitures

~~higher non-operating costs of $55 million in Ghana, primarily due to the Jubilee turret repair in 2018 and cost adjustment credits received from the operator in 2017~~


–	higher U.S. onshore costs of $34 million, primarily related to increased operated and nonoperated activity in the DJ and Delaware basins


–	higher operated costs of $20 million, primarily related to increased workover activity in the Gulf of Mexico


–	lower nonoperated costs of $36 million in Ghana, primarily due to insurance reimbursement credits received in 2019 related to Jubilee turret repair


–	lower costs of $11 million as a result of U.S. onshore and Gulf of Mexico asset divestitures

The related costs per BOE ~~increased~~decreased by ~~$0.78~~$0.27 for the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, primarily due to insurance reimbursement credits received in 2019 related to Jubilee turret repair, partially offset by increased production in the Delaware basin and higher operated costs ~~as a result of shifting to a higher-return, oil-levered portfolio that includes~~in the Gulf of Mexico ~~and the DJ and Delaware basins, which operate at a higher cost compared~~related to ~~the divested lower-return, gas-levered assets.~~increased workover activity.

~~Oil and Gas Transportation Expense~~

45 | APC 2019 FORM 10-Q



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents

Oil and Gas Transportation Expenses



	Three Months Ended
	March 31,
	2019		2018
Oil and gas transportation (millions)	$	222	$	196
Oil and gas transportation—per BOE	3.46		3.38

Oil and gas transportation expense ~~decreased~~increased by ~~$65~~$26 million for the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, primarily due to ~~U.S. onshore divestitures.~~increased sales volumes in the Delaware basin being transported and sold at Gulf Coast markets. Oil and gas transportation expense per BOE decreased by $0.20 for the nine months ended September 30, 2018, primarily due to divestitures and lower transportation expense per BOE in the DJ basin. After significant investment in its midstream infrastructure, the Company has increased the use of its midstream facilities resulting in lower transportation costs for its DJ sales volumes. These decreases are partially offset by higher third-party transportation costs in the Delaware basin.remained relatively flat.

~~Exploration Expense~~

Three Months Ended Nine Months Ended
September 30, September 30,
millions 2018 2017 2018 2017
Dry hole expense $ —
$ 565
$ 55
$ 1,408
Impairments of unproved properties 64
113
158

736
Geological and geophysical, exploration overhead, and other expense 54
72
167
222
Total $ 118
$ 750
$ 380
$ 2,366

Exploration Expense



	Three Months Ended
	March 31,
millions	2019		2018
Dry hole expense	$	—	$	53
Impairments of unproved properties	—		53
Geological and geophysical, exploration overhead, and other expense	49		62
Total exploration expense	$	49	$	168

Dry Hole Expense

Dry hole expense for the ~~nine~~three months ended ~~September 30,~~March 31, 2018, primarily related to the following:

~~$49 million related to unsuccessful drilling activities in the Gulf of Mexico during the first quarter of 2018~~

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

$438 million related to the Shenandoah project, $221 million related to the Phobos project, and $110 million related to the Warrior project in the Gulf of Mexico due to insufficient quantities of oil pay to justify development

~~$325 million related to certain wells in Côte d’Ivoire, where the Company relinquished its interest in its Côte d’Ivoire blocks~~

~~$243 million related to certain wells in the Grand Fuerte area in Colombia due to insufficient progress on contractual and fiscal reforms needed for deepwater natural-gas development~~


–	$49 million related to unsuccessful drilling activities in the Gulf of Mexico

~~Impairments of Unproved Properties~~

~~For discussion related to impairments of unproved properties, see~~ ~~Note 5—Impairmentsin the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Part I, Item 1 of this Form 10-Q.~~

~~G&A~~

Three Months Ended Nine Months Ended
September 30, September 30,
millions except percentages 2018 Inc (Dec) vs. 2017 2017 2018 Inc (Dec) vs. 2017 2017
G&A $ 248
(5 )% $ 261
$ 814
6 % $ 768

G&A



	Three Months Ended
	March 31,
millions	2019		2018
G&A	$	267	$	278

G&A ~~increased~~decreased by ~~$46~~$11 million for the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, primarily due to ~~an increase~~a decrease in the fair value of performance-based unit ~~awards.~~ awards, partially offset by an increase in reorganization-related expenses.

The fair value of the performance-based unit awards is calculated using a Monte Carlo simulation that incorporates several variables, including Anadarko’s historical share price and share prices of a predetermined group of peer companies to estimate the future total shareholder returns of each. Accordingly, future G&A could be higher or lower based on the outputs from the Monte Carlo simulation for the performance-based unit awards.

~~Impairments~~

APC 2019 FORM 10-Q | 46



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents

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

During the nine months ended September 30, 2018, the Company recorded asset impairments related to its hard-minerals properties and a gathering system in the DJ basin. During the nine months ended September 30, 2017, the Company recorded asset impairments related to various oil and gas properties in the Gulf of Mexico and a U.S. onshore midstream property. For additional information, see ~~Note 5—Impairments~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Part I, Item 1 of this Form 10-Q.~~

~~Other Operating Expense~~

DD&A

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



	Three Months Ended
	March 31,
millions	2019		2018
DD&A	$	1,081	$	990

DD&A expense increased by $91 million for the three months ended March 31, 2019, primarily due to the following:


–	$48 million increase, primarily due to increased production in the Delaware and DJ basins and the Gulf of Mexico, partially offset by a lower DD&A rate in 2019 primarily driven by increased proved developed reserves in Ghana


–	$33 million increase in straight line depreciation related to additional midstream infrastructure in the Delaware and DJ basins

Other Operating Expense



	Three Months Ended
	March 31,
millions	2019		2018
Other operating expense	$	21	$	140

Other operating expense includes adjustments to contingency accruals, charges for drilling rig idle time, adjustments to drilling rig termination fees, and surface owner payments.

Other (Income) Expense

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


	Three Months Ended				Nine Months Ended					Three Months Ended
	September 30,				September 30,					March 31,
millions	2018		2017		2018		2017			2019		2018
Interest expense	$	240	$	230	$	705	$	682		$	253	$	228
(Gains) losses on derivatives, net ⁽¹⁾	32		82		503		(33		)	313		35
Other (income) expense, net	24		5		16		51			6		(12		)
Total	$	296	$	317	$	1,224	$	700		$	572	$	251


⁽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 8—7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

~~Income Tax Expense (Benefit)~~

47 | APC 2019 FORM 10-Q



	MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS	Table of Contents

Three Months Ended Nine Months Ended
September 30, September 30,
millions except percentages 2018 2017 2018 2017
Income tax expense (benefit) $ 256
$ (425 ) $ 507
$ (366 )
Income (loss) before income taxes 683
(1,066 ) 1,125
(1,616 )
Effective tax rate 37 % 40 % 45 % 23 %

Income Tax Expense (Benefit)



	Three Months Ended
	March 31,
millions except percentages	2019			2018
Income tax expense (benefit)	$	166		$	126
Income (loss) before income taxes	262			300
Effective tax rate	63		%	42		%

Upon enactment of the Tax Reform Legislation on December 22, 2017, the Company remeasured its U.S. deferred tax assets and liabilities based on the reduction of the U.S. corporate tax rate from 35% to 21%. During the third quarter of 2018, the Company recognized an additional net tax benefit of $5 million related to the adoption of the Tax Reform Legislation. The Company expects to complete the accounting for the income tax effects related to the adoption of the Tax Reform Legislation and record any remaining adjustments to provisional tax amounts, which could be material to income tax expense, before the end of the measurement period on December 21, 2018.

The Company’s effective tax rate is impacted each year by the relative pre-tax income (loss) earned by the Company’s operations in the U.S., Algeria, and the rest of the world. The Company is subject to statutory tax rates of 38% in Algeria and 35% in Ghana. These higher-taxed foreign operations as well as non-deductible Algerian exceptional profits tax for Algerian income tax purposes generally cause the Company’s effective tax rate to vary significantly from the U.S. corporate tax rate. Additionally, the Company’s effective tax rate is typically impacted by net changes in uncertain tax positions, income attributable to noncontrolling interests, state income taxes (net of federal benefit), and dispositions of non-deductible goodwill.

The Company received an $881 million tentative refund in 2016 related to its $5.2 billion Tronox settlement payment in 2015. In April 2018, the IRS issued a final notice of proposed adjustment denying the deductibility of the settlement payment. In September 2018, the Company received a statutory notice of deficiency from the IRS disallowing the net operating loss carryback and rejecting the Company’s refund claim. As a result, the Company ~~intends to file~~filed a petition with the U.S. Tax Court to dispute the disallowances in November 2018, and pursuant to standard U.S. Tax Court procedures, is not required to repay the $881 million refund to dispute the IRS’s position. Accordingly, the Company has not revised its estimate of the benefit that will ultimately be realized. After the case is tried and briefed in the Tax Court, the court will issue an opinion and then enter a decision. If the Company does not prevail on the issue, the earliest ~~potential~~ date the Company might be required to repay the refund received, plus interest, would be 91 days after entry of the decision. At such time, the Company would reverse the portion of the $346 million net benefit previously recognized in its consolidated financial statements to the extent necessary to reflect the result of the Tax Court decision. It is reasonably possible the amount of uncertain tax position and/or tax benefit could materially change as the Company asserts its position in the Tax Court proceedings. Although management cannot predict the timing of a final resolution of the Tax Court proceedings, the Company does not currently anticipate a decision to be entered ~~within the next three years.~~before 2022.

For additional information on income taxes, see Note ~~11—~~10—Income Taxes in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

APC 2019 FORM 10-Q | 48



	MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES	Table of Contents

Nine Months Ended
September 30,
millions 2018 2017
Net cash provided by (used in) operating activities $ 4,302
$ 2,619
Net cash provided by (used in) investing activities (4,659 ) (28 )
Net cash provided by (used in) financing activities (2,306 ) (527 )

LIQUIDITY AND CAPITAL RESOURCES



	Three Months Ended
	March 31,
millions	2019			2018
Net cash provided by (used in) operating activities	$	1,129		$	1,430
Net cash provided by (used in) investing activities	(1,528		)	(1,113		)
Net cash provided by (used in) financing activities	1,129			(1,507		)

~~Overview~~

Overview

The Company has a variety of funding sources available, including cash, an asset portfolio that provides ongoing cash-flow-generating capacity, ~~opportunities for liquidity enhancement through divestitures~~ and ~~joint-venture arrangements that reduce future capital expenditures,~~ the Company’s credit facilities, and access to both debt and equity capital markets. In addition, an effective registration statement is available to Anadarko covering the sale of WGP common units owned by the Company. WGP and WES function with capital structures that are separate from Anadarko, consisting of their own debt instruments and publicly traded common units.facility.

During the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, Anadarko ~~paid $2.4 billion to repurchase shares under the Share-Repurchase Program and received net proceeds~~retired $900 million of ~~$393 million from divestitures, primarily related to the sale of the Company’s nonoperated interest in Alaska. As of September 30, 2018,~~debt. Anadarko had ~~$1.9~~$2.0 billion of cash ~~plus $5.0~~at March 31, 2019 and following the expiration of the 364-Day facility in January 2019, the Company has $3.0 billion of borrowing capacity under ~~its~~the APC ~~RCF and 364-Day Facility.~~RCF. Anadarko believes that its current available cash and future operating cash flows will be sufficient to fund the Company’s ~~projected long-term~~ operational and capital programs and its quarterly ~~dividends, the planned debt retirements, and the repurchase of $500 million of the Company’s common stock remaining under the Share-Repurchase Program.~~dividends. The Company continuously monitors its liquidity position and evaluates available funding alternatives in light of current and expected conditions.

Operating Activities

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

Cash flows from operating activities were ~~$4.3~~$1.1 billion for the ~~nine~~three months ended ~~September 30, 2018, $1.7 billion higher than~~March 31, 2019, $301 million lower compared to the same period in ~~2017,~~2018, primarily due to ~~higher~~lower oil and NGL sales revenues resulting from lower prices as well as higher ~~commodity prices and a higher oil composition of sales volumes.~~operating costs.

49 | APC 2019 FORM 10-Q



	MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES	Table of Contents

Investing Activities

Capital Expenditures The following presents the Company’s capital expenditures:

Nine Months Ended
September 30,
millions 2018 2017
Cash Flows from Investing Activities
Additions to properties and equipment ⁽¹⁾
$ 4,891
$ 3,538
Adjustments for capital expenditures
Changes in capital accruals 61
237
Other (7 ) 21
Total capital expenditures $ 4,945
$ 3,796

Exploration and Production and other capital expenditures $ 3,367
$ 2,876
WES Midstream capital expenditures 920
662
Other Midstream capital expenditures 658
258

~~________________________________________________________________________________________~~



	Three Months Ended
	March 31,
millions	2019			2018
Cash Flows from Investing Activities
Additions to properties and equipment ⁽¹⁾	$	1,389		$	1,547
Adjustments for capital expenditures
Changes in capital accruals	(42		)	142
Other	(51		)	15
Total capital expenditures	$	1,296		$	1,704

Exploration and Production and other capital expenditures	$	981		$	1,116
WES Midstream capital expenditures ⁽²⁾	315			588


⁽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⁾	WES Midstream includes $49 million at March 31, 2019, and $260 million at March 31, 2018, of capitalized costs incurred prior to the contribution and sale of midstream assets to WES.

The Company’s capital expenditures ~~increased~~decreased by ~~$1.1 billion~~$408 million for the ~~nine~~three months ended ~~September 30, 2018.~~March 31, 2019. Exploration and Production capital expenditures ~~increased~~decreased primarily due to ~~higher~~lower development costs of ~~$850~~$120 million driven by ~~increased~~decreased drilling ~~and completion~~ activities ~~primarily~~ in ~~the DJ and Delaware basins and~~ the Gulf of Mexico. Exploration costs decreased by $396 million primarily related to decreased exploration drilling in the Gulf of Mexico, Côte d’Ivoire, and Colombia partially offset by higher exploration drilling in the U.S. onshore. Other Midstream capital expenditures increased $400 million due to asset development primarily in the Delaware basin. WES Midstream capital expenditures ~~increased $258~~decreased by $273 million primarily ~~related~~due to ~~the~~reduced development ~~of assets~~activity in the Delaware ~~and DJ basins.~~basin following the completion of significant infrastructure projects in 2018.

Investments During the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, the Company made capital contributions of ~~$235~~$130 million for equity investments, which are presented as cash flows from investing activities as a component of Other, net. These contributions were primarily associated with joint ventures for the ~~Midland-to-Sealy~~Red Bluff and Cactus II pipelines in West Texas.

~~Divestitures~~APC 2019 FORM 10-Q | 50



	MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES	Table of Contents

Financing Activities



millions except percentages	March 31, 2019				December 31, 2018
Anadarko		$	10,716			$	11,602
WES		7,208				4,815
Total debt		$	17,924			$	16,417
Total equity		10,533				10,943
Consolidated debt to total capitalization ratio		63.0		%		60.0		%

Debt-Reduction Program The Company commenced a $2.0 billion debt-reduction program in 2018. During the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, Anadarko ~~received net proceeds~~retired $900 million of ~~$393 million from divestitures, primarily related~~debt, bringing total repayments under the debt-reduction program to $1.5 billion. No additional debt retirements are anticipated pursuant to the ~~sale~~terms of the Chevron Merger Agreement.

Credit Facilities

APC RCFs The Company has a $3.0 billion senior unsecured RCF that matures in January 2023. The Company’s ~~nonoperated~~$2.0 billion 364-day senior unsecured RCF expired in January 2019. At March 31, 2019, Anadarko had no outstanding borrowings under the APC RCF and was in compliance with all covenants.

WES RCFs Effective on February 15, 2019, WES amended the maturity date of its senior unsecured RCF from February 2023 to February 2024, and upon completion of the WES Merger, expanded the borrowing capacity from $1.5 billion to $2.0 billion (WES RCF). At March 31, 2019, WES had outstanding borrowings under its RCF of $640 million at an interest rate of 3.79%, outstanding letters of credit of $5 million, available borrowing capacity of $1.4 billion, and was in ~~Alaska.~~compliance with all covenants.

In February 2019, WES borrowed $2.0 billion under its 364-day senior unsecured credit facility (WES 364-Day Facility) to fund substantially all of the cash portion of the consideration under the WES midstream asset contribution and sale and the payment of related transaction costs. The WES 364-Day Facility will mature on February 27, 2020, the day prior to the one-year anniversary of the completion of the WES Merger. Net cash proceeds received from future asset sales and debt or equity offerings by WES must be used to repay amounts outstanding under the WES 364-Day Facility. At March 31, 2019, WES had outstanding borrowings under its WES 364-Day Facility of $2.0 billion at an interest rate of 3.87% and was in compliance with all covenants. WES intends to refinance the obligations under the 364-Day Facility prior to its maturity in February 2020. See Note ~~4—Divestitures~~1—Summary of Significant Accounting Policiesin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form ~~10-Q.~~10-Q for additional information related to the WES Merger.

WGP RCF In March 2019, the $35 million senior secured RCF (WGP RCF) matured following the completion of the WES Merger. 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 additional information related to the WES Merger.

~~Financing Activities~~

51 | APC 2019 FORM 10-Q



	MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES	Table of Contents

Debt Activity Amounts in the table below do not include finance lease activity and are presented at face value.

September 30, December 31,
millions except percentages 2018 2017
Anadarko $ 12,099
$ 12,196
WES 4,566
3,465
WGP 28
28
Total debt $ 16,693
$ 15,689
Total equity 11,237
13,790
Consolidated debt to total capitalization ratio 59.8 % 53.2 %

~~Debt Activity~~

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



		Three Months Ended
millions	Company	March 31, 2019		Description
Borrowings	WES	2,000		WES 364-Day Facility ⁽¹⁾
	WES	420		WES RCF ⁽²⁾
Repayments	Anadarko	(600	)	8.700% Senior Notes due 2019
	Anadarko	(300	)	6.950% Senior Notes due 2019
	WES	(28	)	WGP RCF


⁽¹⁾	Borrowings were used to fund substantially all of the cash portion of the consideration for the WES midstream asset contribution and sale and the payment of related transaction costs.


⁽²⁾	Borrowings were used for general partnership purposes, including capital expenditures.

~~Anadarko RCFs~~ In January 2018, the Company amended its $3.0 billion senior unsecured RCF to extend the maturity date to January 2022 (APC RCF) and amended its $2.0 billion 364-day senior unsecured RCF to extend the maturity date to January 2019 (364-Day Facility). At September 30, 2018, Anadarko had no outstanding borrowings under the APC RCF or the 364-Day Facility and was in compliance with all covenants.

~~WES Senior Notes~~ In August 2018, WES completed a public offering of $400 million aggregate principal amount of 4.750% Senior Notes due August 2028 and a public offering of $350 million aggregate principal amount of 5.500% Senior Notes due August 2048. The net proceeds from the public offerings were used to repay the maturing $350 million of 2.600% Senior Notes due August 2018 and amounts outstanding under the WES RCF. The remaining net proceeds were used for general partnership purposes, including to fund capital expenditures.

In March 2018, WES completed a public offering of $400 million aggregate principal amount of 4.500% Senior Notes due March 2028 and a public offering of $700 million aggregate principal amount of 5.300% Senior Notes due March 2048. Net proceeds from the public offerings were used to repay amounts outstanding under the WES RCF. The remaining net proceeds were used for general partnership purposes, including to fund capital expenditures.

~~WES and WGP RCFs~~ In February 2018, WES amended its RCF to extend the maturity date from February 2020 to February 2023 and expanded the borrowing capacity to $1.5 billion (WES RCF). As part of the amendment, the WES RCF is expandable to a maximum of $2.0 billion. During the nine months ended September 30, 2018, WES borrowed $320 million under its RCF, which was used for general partnership purposes, and made repayments of $690 million. At September 30, 2018, WES had no outstanding borrowings under its RCF, outstanding letters of credit of $5 million, available borrowing capacity of $1.495 billion, and was in compliance with all covenants.

In February 2018, WGP voluntarily reduced the aggregate commitments of the lenders under its senior secured RCF maturing in March 2019 from $250 million to $35 million (WGP RCF). At September 30, 2018, WGP had outstanding borrowings of $28 million at an interest rate of 4.25% classified as short-term debt on the Company’s Consolidated Balance Sheet, and had available borrowing capacity of $7 million.

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

Debt MaturitiesAt September 30, 2018, Anadarko had outstanding borrowings of $600 million of 8.700% Senior Notes due March 2019 and $300 million of 6.950% Senior Notes due June 2019 classified as short-term debt on the Company’s Consolidated Balance Sheet.

Anadarko’s Zero Coupons can be put to the Company in October of each year, in whole or in part, for the then-accreted value of the outstanding Zero ~~Coupons. None of the Zero~~ Coupons, ~~were put to the Company in October 2018. The Zero Coupons can next be put to the Company in October 2019,~~ which, if put in whole, ~~would~~will be ~~$980 million.~~$942 million at the next put date in October 2019. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at March 31, 2019, as the Company has the ability and intent to refinance these obligations using long-term debt, should a put be exercised.

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

~~Equity Transactions~~ In February 2018, as part of the Share-Repurchase Program, the Company completed the repurchase of 8.5 million shares of its common stock for $500 million (average price of $58.82 per share) under an ASR Agreement. In March 2018, the Company entered into an additional ASR Agreement, which was completed in June 2018 and resulted in the repurchase of 22.1 million shares of its common stock for $1.4 billion (average price of $65.28 per share). In July 2018, the Share-Repurchase Program was expanded to $4.0 billion and extended through June 30, 2019. In the third quarter of 2018, the Company completed the repurchase of 7.7 million shares of its common stock for $500 million through open-market repurchases. For additional information, see ~~Note 14—Stockholders’ Equity~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Part I, Item 1 of this Form 10-Q.~~

In July 2017, WES filed a registration statement with the SEC for the issuance of up to an aggregate of $500 million of WES common units pursuant to a continuous offering program that has not yet been initiated.

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

Common Stock DividendsAnadarko paid dividends to its common stockholders of ~~$380~~$150 million during the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, and ~~$84~~$127 million during the ~~nine~~three months ended ~~September 30, 2017.~~March 31, 2018. In February 2018, the Company ~~announced an increase to~~increased the quarterly dividend to $0.25 per share. As part of the Company’s focus on increasing shareholder returns, the quarterly dividend increased again in November 2018 to $0.30 per share. Anadarko has paid a dividend to its common stockholders quarterly since becoming a public company in 1986.

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

Distributions to Noncontrolling Interest OwnersDistributions to noncontrolling interest owners primarily relate to WES distributions to third parties of $130 million for the ~~following:~~three months ended March 31, 2019, and $118 million for the three months ended March 31, 2018.

Nine Months Ended
September 30,
millions 2018 2017
WES distributions to unitholders (excluding Anadarko and WGP) ⁽¹⁾
$ 282
$ 235
WES distributions to Series A Preferred unitholders ⁽²⁾
—
22
WGP distributions to unitholders (excluding Anadarko) ⁽³⁾
73
60


⁽¹⁾	WES has made quarterly distributions to its unitholders since its IPO in the second quarter of 2008 and has increased its distribution from $0.30 per common unit for the third quarter of 2008 to $0.965 per common unit for the third quarter of 2018 (to be paid in November 2018).

⁽²⁾

WES made quarterly distributions of $0.68 per unit, prorated based on issuance date, to its Series A Preferred unitholders since the unit issuances in March and April 2016. As of June 30, 2017, all Series A Preferred units had converted into WES common units; see ~~Note 15—Noncontrolling Interests~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Part I, Item 1 of this Form 10‑Q.~~


⁽³⁾	WGP has made quarterly distributions to its unitholders since its IPO in December 2012 and has increased its distribution from $0.17875 per common unit for the first quarter of 2013 to $0.59500 per unit for the third quarter of 2018 (to be paid in November 2018).

~~RECENT ACCOUNTING DEVELOPMENTS~~

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.

APC 2019 FORM 10-Q | 52



	MARKET RISK QUANTITATIVE AND QUALITATIVE DISCLOSURES	Table of Contents

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

~~COMMODITY-PRICE RISK~~

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 4924 MMBbls of oil ~~and 49 Bcf of natural gas~~ at ~~September 30, 2018,~~March 31, 2019, with a net derivative ~~liability~~asset position of ~~$458~~$16 million. Based on actual derivative contractual ~~volumes,~~volume, a 10% increase in underlying commodity prices would ~~increase~~reduce the ~~net derivative liability~~fair value of these derivatives by ~~$308~~$51 million, while a 10% decrease in underlying commodity prices would ~~decrease~~increase the ~~net derivative liability~~fair value of these derivatives by ~~$270~~$50 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.

~~INTEREST-RATE RISK~~

INTEREST-RATE RISK

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

At ~~September 30, 2018,~~March 31, 2019, the Company had a net derivative liability position of ~~$1.0~~$1.3 billion related to interest-rate swaps. A 10% increase (decrease) in the LIBOR interest-rate curve would decrease (increase) the aggregate fair value of outstanding interest-rate swap agreements by ~~$103~~$117 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 8—7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

53 | APC 2019 FORM 10-Q



	CONTROLS AND PROCEDURES	Table of Contents

Item 4. Controls and Procedures

~~Evaluation of Disclosure Controls and Procedures~~

EVALUATION AND 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, 2018.~~March 31, 2019.

~~Changes in Internal Control over Financial Reporting~~

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes in Anadarko’s internal control over financial reporting during the ~~third~~first quarter of ~~2018~~2019 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

~~PART II.~~

APC 2019 FORM 10-Q | 54



	OTHER INFORMATION	Table of Contents

PART II

Item 1. Legal Proceedings

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

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

In September 2018, Anadarko E&P Onshore LLC, a subsidiary of the Company, entered into a final consent assessment with the Pennsylvania Department of Environmental Protection resolving issues concerning a produced water release in Pennsylvania in 2015 and agreed to pay a penalty of $350,000.

Kerr-McGee Oil and Gas Onshore, LP, a 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 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.~~complex in Colorado. 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.

In May 2018, Delaware Basin Midstream, LLC, a subsidiary of the Company, entered into a consent agreement and final order with the EPA with respect to alleged noncompliance with certain Risk Management Plan regulations under the Clean Air Act at its Ramsey Gas Plant and agreed to pay a penalty of $226,000.

The Company continues to work cooperatively with Colorado state regulators and others following a home explosion that occurred in Firestone, Colorado in April 2017. The Company also is cooperating with the NTSB at the federal level in its investigation related to the accident.

See Note ~~12—~~11—Contingencies in the ~~the~~NotestoConsolidatedFinancialStatementsunderPartI,Item1ofthisForm10-Q, which is incorporated herein by reference, for a discussion of material legal proceedings to which the Company is a party.

55 | APC 2019 FORM 10-Q



	OTHER INFORMATION	Table of Contents

Item 1A. Risk Factors

~~Consider carefully~~

Due to the Company’s proposed combination with Chevron, there have been material changes to 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, ~~2017.~~2018.

For a complete discussion of the Company’s risk factors, refer to the risk factors included under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 and the following risk factors relating to the proposed combination with Chevron:

~~Our operations in Colorado involve risks that~~We will be subject to business uncertainties while the Chevron Merger is pending, which could ~~increase our costs of doing business, result in additional operating restrictions or delays, limit the areas in which we can operate, and~~ adversely affect our ~~production.~~businesses.

Uncertainty about the effect of the Chevron Merger on employees and those that do business with us may have an adverse effect on Anadarko. These uncertainties may impair our ability to attract, retain and motivate key personnel until the Chevron Merger is completed and for a period of time thereafter, and could cause those that deal with us to seek to change their existing business relationships with us. Employee retention at Anadarko may be challenging during the pendency of the Chevron Merger, as employees may experience uncertainty about their roles. In addition, the Chevron Merger Agreement restricts us from entering into certain corporate transactions, entering into certain material contracts, making certain changes to our capital budget, incurring certain indebtedness and taking other specified actions without the consent of Chevron, and generally requires us to continue our operations in the ordinary course of business during the pendency of the Chevron Merger. These restrictions may prevent us from pursuing attractive business opportunities or adjusting our capital plan prior to the completion of the Chevron Merger.

We ~~have significant operations~~may be subject to lawsuits relating to the Chevron Merger, which could adversely affect our business, financial condition and operating results.

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

Completion of the Chevron Merger is subject to a number of conditions, and if these conditions are not satisfied or waived, the Chevron Merger will not be completed. Failure to complete, or significant delays in completing, the Chevron Merger could negatively affect the trading prices of our common stock and our future business and financial results.

Completion of the Chevron Merger is subject to satisfaction or waiver of certain closing conditions, including (1) the adoption of the Chevron Merger Agreement by Anadarko stockholders, (2) the expiration or termination of the waiting period under the Hart-Scott-Rodino Act, as amended, applicable to the Chevron Merger, (3) the absence of any order or law prohibiting consummation of the Chevron Merger, (4) the effectiveness of the Registration Statement on Form S-4 to be filed by Chevron pursuant to which the shares of Chevron common stock to be issued in connection with the Chevron Merger will be registered with the Securities and Exchange Commission and (5) the authorization for listing on the New York Stock Exchange of the shares of Chevron common stock to be issued in connection with the Chevron Merger. There can be no assurance that the conditions to the completion of the Chevron Merger will be satisfied or waived or that the Chevron Merger will be completed.

If the Chevron Merger is not completed, or if there are significant delays in completing the Chevron Merger, the trading prices of our common stock and our future business and financial results could be negatively affected, and we may be subject to several risks, including the following:


–	the requirement that we pay Chevron a termination fee of $1.0 billion under certain circumstances provided in the Chevron Merger Agreement;


–	negative reactions from the financial markets, including declines in the prices of our common stock due to the fact that current prices may reflect a market assumption that the Chevron Merger will be completed;


–	having to pay certain significant costs relating to the Chevron Merger; and


–	the attention of our management will have been diverted to the Chevron Merger rather than our own operations and pursuit of other opportunities that could have been beneficial to us.

APC 2019 FORM 10-Q | 56



	OTHER INFORMATION	Table of Contents

The Chevron Merger Agreement limits our ability to pursue alternatives to the Chevron Merger.

The Chevron Merger Agreement contains provisions that may discourage a third party from submitting a competing proposal that might result in greater value to our stockholders than the Chevron Merger, or may result in a potential competing acquirer of the Company proposing to pay a lower per share price to acquire us than it might otherwise have proposed to pay. These provisions include a general prohibition on us from soliciting or, subject to certain exceptions relating to the exercise of fiduciary duties by our Board, entering into discussions with any third party regarding any competing proposal or offer for a competing transaction.

Because the exchange ratio in the Chevron Merger Agreement is fixed and because the market price of Chevron common stock will fluctuate prior to the completion of the Chevron Merger, our stockholders cannot be sure of the market value of the Chevron common stock they will receive as consideration in the Chevron Merger.

Under the terms of the Chevron Merger Agreement, our stockholders will receive consideration consisting of a combination of 0.3869 of a share of Chevron common stock and $16.25 of cash for each share of Anadarko common stock. Based on the closing price of Chevron common stock on April 11, 2019, the last trading day prior to the announcement of the Chevron Merger, the merger consideration was valued at $65.00 per share. The exchange ratio for the stock component of the merger consideration is fixed, and there will be no adjustment to the merger consideration for changes in the market price of Chevron common stock or our common stock prior to the completion of the Chevron Merger.

If the Chevron Merger is completed, there will be a time lapse between the date of signing of the Chevron Merger Agreement and the date on which our stockholders who are entitled to receive the merger consideration actually receive the merger consideration. The respective market values of Chevron common stock and our common stock have fluctuated and may continue to fluctuate during this period as a result of a variety of factors, including general market and economic conditions, changes in each company’s business, operations and prospects, commodity prices, regulatory considerations, and the market’s assessment of Chevron’s business and the Chevron Merger. Such factors are difficult to predict and in many cases may be beyond the control of Chevron and us. The actual value of the stock component of any merger consideration received by our stockholders at the completion of the Chevron Merger will depend on the market value of Chevron common stock at that time. This market value may differ, possibly materially, from the market value of Chevron common stock at the time the Chevron Merger Agreement was entered into or at any other time.

We may terminate the Chevron Merger Agreement in order to enter into a definitive merger agreement with Occidental.

On May 6, 2019, we announced that our Board has determined that the Occidental Proposal constitutes a “Superior Proposal” as defined in the Chevron Merger Agreement and that, after complying with its obligations to Chevron under the Chevron Merger Agreement, the Company intends to terminate the Chevron Merger Agreement in order to enter into a definitive merger agreement with Occidental in connection with the Occidental Proposal. Pursuant to the Chevron Merger Agreement, Chevron has the right, during the four business day period ending on May 10, 2019, which may be extended in accordance with the terms of the Chevron Merger Agreement, to propose revisions to the terms of the Chevron Merger Agreement, or to make another proposal. The Company is required to, and will, make its representatives reasonably available to negotiate with Chevron during this period with respect to such proposed revisions or other proposal, if any. If the Company terminates the Chevron Merger Agreement in order to enter into a definitive agreement with respect to the Occidental Proposal, the Company will pay Chevron a $1.0 billion termination fee as required by the Chevron Merger Agreement. However, there can be no assurance that a definitive agreement between the Company and Occidental will be executed or that a transaction between the Company and Occidental will be consummated. The Chevron Merger Agreement remains in effect unless and until terminated, and accordingly, our Board reaffirms its existing recommendation of the transaction with Chevron at this time.

The risk factors set forth above regarding the Chevron Merger would apply correlatively to the merger transaction with Occidental in the event the Company terminates the Chevron Merger Agreement and enters into a definitive agreement with respect to the Occidental Proposal.

57 | APC 2019 FORM 10-Q



	OTHER INFORMATION	Table of Contents

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

The following sets forth information with respect to repurchases made by the Company of its shares of common stock during the ~~third~~first quarter of ~~2018:~~2019:

Period
Total number of shares purchased ⁽¹⁾
Average price paid per share
Total number of shares purchased as part of publicly announced plans or programs ⁽²⁾

Approximate dollar value of shares that may yet be purchased under the plans or programs ⁽²⁾⁽³⁾
July 1 - 31, 2018 2,591
$ 72.92
—
$ 1,000,000,000
August 1 - 31, 2018 ⁽²⁾
3,782,348
$ 66.14
3,781,259
$ 749,924,384
September 1 - 30, 2018 ⁽²⁾
4,002,869
$ 63.11
3,960,089
$ 500,000,003
Total 7,787,808
$ 64.58
7,741,348

~~____________________________________________________________~~



Period	Total number of shares purchased ⁽¹⁾	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs ⁽²⁾	Approximate dollar value of shares that may yet be purchased under the plans or programs ⁽²⁾⁽³⁾
January 1 - 31, 2019	24,942	$	48.39	—		$	1,250,000,064
February 1 - 28, 2019	2,299	$	43.67	—		$	1,250,000,064
March 1 - 31, 2019	344,288	$	44.62	—		$	1,250,000,064
Total	371,529	$	44.87	—

⁽¹⁾

During the ~~third~~first quarter of ~~2018, (i) 7.7 million shares were repurchased under the Share-Repurchase Program and (ii) 46~~2019, 372 thousand shares were repurchased related to stock received by the Company for the payment of withholding taxes due on employee share issuances under share-based compensation plans. ~~For additional information, see~~ ~~Note 14—Stockholders’ Equity~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~under Part I, Item 1 of this Form 10‑Q.~~


⁽²⁾	~~During the third quarter of 2018, the Company repurchased 7.7 million shares of common stock for $500 million through open-market repurchases.~~ For additional information, see Note ~~14—~~13—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10‑Q.

⁽³⁾

The Company announced a $2.5 billion Share-Repurchase Program in September 2017, which was expanded to $3.0 billion in February 2018 and $4.0 billion in July 2018.In ~~July~~November 2018, the ~~Share-Repurchase Program~~program was further expanded to ~~$4.0~~$5.0 billion and extended through June 30, ~~2019.~~2020. No additional share repurchases are anticipated pursuant to the terms of the Chevron Merger Agreement. For additional information, see Note 13—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10‑Q.

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	OTHER INFORMATION	Table of Contents

Item 6. Exhibits

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



Exhibit Number			Description
†	2	(i)	Agreement and Plan of Merger, dated as of April 11, 2019, by and among Chevron Corporation, Justify Merger Sub 1 Inc., Justify Merger Sub 2 Inc. and Anadarko Petroleum Corporation, filed as Exhibit 2.1 to Form 8-K Filed on April 17, 2019
	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 ~~November 14, 2017,~~April 11, 2019, filed as Exhibit 3.1 to Form 8-K filed on ~~November 16, 2017~~April 17, 2019
*	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


†	Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request

59 | APC 2019 FORM 10-Q

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 30, 2018~~May 8, 2019	By:	/s/ ~~ROBERT G. GWIN~~BENJAMIN M. FINK
		~~Robert G. Gwin~~Benjamin M. Fink Executive Vice President, Finance and Chief Financial Officer

64APC 2019 FORM 10-Q | 60



CONSOLIDATED BALANCE SHEET	Impact of Change in Accounting Policy
millions	As Reported		Without Adoption of Topic 606		Effect of Change Increase/(Decrease)
September 30, 2018
Assets
Other current assets	$	397	$	395	$	2
Net properties and equipment	28,744		28,697		47
Other assets	2,292		2,282		10
Liabilities
Other current liabilities	1,502		1,494		8
Deferred income taxes	2,455		2,461		(6		)
Other	4,043		3,932		111
Equity
Total equity	11,237		11,291		(54		)



CONSOLIDATED STATEMENT OF INCOME	Impact of Change in Accounting Policy
millions	As Reported		Without Adoption of Topic 606		Effect of Change Increase/(Decrease)
Three Months Ended September 30, 2018
Revenues
Gathering, processing, and marketing sales	$	421	$	717	$	(296	)
Gains (losses) on divestitures and other, net	90		89		1
Expenses
Gathering, processing, and marketing	256		551		(295		)
Income tax expense (benefit)	256		254		2
Net income (loss) attributable to noncontrolling interests	64		71		(7		)
Net Income (Loss) Attributable to Common Stockholders	$	363	$	358	$	5

Nine Months Ended September 30, 2018
Revenues
Gathering, processing, and marketing sales	$	1,163	$	1,944	$	(781	)
Gains (losses) on divestitures and other, net	232		233		(1		)
Expenses
Gathering, processing, and marketing	745		1,520		(775		)
Income tax expense (benefit)	507		507		—
Net income (loss) attributable to noncontrolling interests	105		111		(6		)
Net Income (Loss) Attributable to Common Stockholders	$	513	$	514	$	(1	)



millions
Balance at December 31, 2017	$	37
Increase due to cumulative effect of adopting Topic 606	98
Increase due to cash received, excluding revenues recognized in the period ⁽¹⁾	46
Decrease due to revenue recognized ⁽²⁾	(30		)
Balance at September 30, 2018	$	151

Contract liabilities at September 30, 2018
Other current liabilities	$	23
Other long-term liabilities - other	128
Total contract liabilities from contracts with customers	$	151



millions except per-share amounts
Agreement Date	Settlement Date	Amount		Average Price per Share		Initial Shares Delivered	Additional Shares Delivered	Total Shares Delivered
ASR Agreements
January 2018	February 2018	$	500	$	58.82	7.0	1.5	8.5
March 2018	June 2018	1,441		65.28		19.1	3.0	22.1
Total ASR Agreements		1,941				26.1	4.5	30.6
Open-market repurchases
August 2018	August 2018	250		66.14		N/A	N/A	3.8
September 2018	September 2018	250		63.11		N/A	N/A	3.9
Total open-market repurchases		500						7.7
Total		$	2,441					38.3



millions	Change in Revenues		Due to Change in Prices		Due to Change in Volumes
Three months ended September 30, 2018 vs. 2017	$	1,005	$	806	$	199
Nine months ended September 30, 2018 vs. 2017	2,312		1,949		363