Edgar Filing: ANADARKO PETROLEUM CORP

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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2018

[ ] 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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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

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

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

The number of shares outstanding of the Company’s common stock at July 19, 2018, is shown below:



Title of Class		Number of Shares Outstanding
Common Stock, par value $0.10 per share		512,075,063

TABLE OF CONTENTS



PART I		Page
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three and Six Months Ended June 30, 2018 and 2017	4
	Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2018 and 2017	5
	Consolidated Balance Sheets at June 30, 2018, and December 31, 2017	6
	Consolidated Statement of Equity for the Six Months Ended June 30, 2018	7
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2018 and 2017	8
	Notes to Consolidated Financial Statements	9
	Note 1—Summary of Significant Accounting Policies	9
	Note 2—Revenue from Contracts with Customers	12
	Note 3—Commodity Inventories	16
	Note 4—Divestitures	16
	Note 5—Impairments	17
	Note 6—Suspended Exploratory Well Costs	17
	Note 7—Current Liabilities	18
	Note 8—Derivative Instruments	18
	Note 9—Tangible Equity Units	24
	Note 10—Debt	24
	Note 11—Income Taxes	27
	Note 12—Contingencies	28
	Note 13—Pension Plans and Other Postretirement Benefits	28
	Note 14—Stockholders’ Equity	29
	Note 15—Noncontrolling Interests	30
	Note 16—Variable Interest Entities	31
	Note 17—Supplemental Cash Flow Information	33
	Note 18—Segment Information	34
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
	Cautionary Statement About Forward-Looking Statements	37
	Management Overview	39
	Financial Results	41
	Liquidity and Capital Resources	52
	Recent Accounting Developments	55
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	56
Item 4.	Controls and Procedures	57
PART II
Item 1.	Legal Proceedings	58
Item 1A.	Risk Factors	58
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	59
Item 6.	Exhibits	60

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

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

BOE - Barrels of oil equivalent

CBM - Coalbed methane

DBJV - Delaware Basin JV Gathering LLC

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

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

DD&A - Depreciation, depletion, and amortization

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

FID - Final investment decision

Fitch - Fitch Ratings

FPSO - Floating production, storage, and offloading unit

G&A - General and administrative expenses

IPO - Initial public offering

LIBOR - London Interbank Offered Rate

LNG - Liquefied natural gas

MBbls/d - Thousand barrels per day

MBOE/d - Thousand barrels of oil equivalent per day

Mcf - Thousand cubic feet

MMBbls - Million barrels

MMBOE - Million barrels of oil equivalent

MMBtu - Million British thermal units

MMBtu/d - Million British thermal units per day

MMcf/d - Million cubic feet per day

Moody’s - Moody’s Investors Service

NGLs - Natural gas liquids

NM - Not meaningful

NTSB - National Transportation Safety Board

NYMEX - New York Mercantile Exchange

Oil - Includes crude oil and condensate

OPEC - Organization of the Petroleum Exporting Countries

RCF - Revolving credit facility

ROTF - Regional oil treating facility

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

TEUs - Tangible equity units

VIE or VIEs - Variable interest entity

WES - Western Gas Partners, LP, a publicly traded limited partnership, which is a consolidated subsidiary of Anadarko

WES RCF - WES’s $1.5 billion senior unsecured RCF

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

WGP RCF - WGP’s $35 million senior secured RCF

WTI - West Texas Intermediate

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

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
millions except per-share amounts	2018			2017			2018			2017
Revenues and Other
Oil sales	$	2,265		$	1,422		$	4,392		$	3,085
Natural-gas sales	203			319			450			821
Natural-gas liquids sales	318			214			610			503
Gathering, processing, and marketing sales	382			464			742			908
Gains (losses) on divestitures and other, net	123			297			142			1,166
Total	3,291			2,716			6,336			6,483
Costs and Expenses
Oil and gas operating	275			229			551			485
Oil and gas transportation	209			229			405			478
Exploration	94			532			262			1,616
Gathering, processing, and marketing	252			355			489			705
General and administrative	288			244			566			507
Depreciation, depletion, and amortization	1,003			1,037			1,993			2,152
Production, property, and other taxes	201			135			391			290
Impairments	128			10			147			383
Other operating expense	22			12			162			34
Total	2,472			2,783			4,966			6,650
Operating Income (Loss)	819			(67		)	1,370			(167		)
Other (Income) Expense
Interest expense	237			229			465			452
(Gains) losses on derivatives, net	436			32			471			(115		)
Other (income) expense, net	4			44			(8		)	46
Total	677			305			928			383
Income (Loss) Before Income Taxes	142			(372		)	442			(550		)
Income tax expense (benefit)	125			(38		)	251			59
Net Income (Loss)	17			(334		)	191			(609		)
Net income (loss) attributable to noncontrolling interests	(12		)	81			41			124
Net Income (Loss) Attributable to Common Stockholders	$	29		$	(415	)	$	150		$	(733	)

Per Common Share
Net income (loss) attributable to common stockholders—basic	$	0.05		$	(0.76	)	$	0.28		$	(1.34	)
Net income (loss) attributable to common stockholders—diluted	$	0.05		$	(0.76	)	$	0.28		$	(1.34	)
Average Number of Common Shares Outstanding—Basic	504			552			511			552
Average Number of Common Shares Outstanding—Diluted	505			552			512			552
Dividends (per common share)	$	0.25		$	0.05		$	0.50		$	0.10

See accompanying Notes to Consolidated Financial Statements.

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
millions	2018			2017			2018			2017
Net Income (Loss)	$	17		$	(334	)	$	191		$	(609	)
Other Comprehensive Income (Loss)
Adjustments for derivative instruments
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	—			1			1			2
Income taxes on reclassification of previously deferred derivative losses	—			(1		)	—			(1		)
Total adjustments for derivative instruments, net of taxes	—			—			1			1
Adjustments for pension and other postretirement plans
Net gain (loss) incurred during period	—			19			—			15
Income taxes on net gain (loss) incurred during period	—			(6		)	—			(5		)
Amortization of net actuarial (gain) loss to other (income) expense, net	6			62			13			71
Income taxes on amortization of net actuarial (gain) loss	(1		)	(23		)	(3		)	(26		)
Amortization of net prior service (credit) cost to other (income) expense, net	(6		)	(6		)	(12		)	(12		)
Income taxes on amortization of net prior service (credit) cost	1			2			2			4
Total adjustments for pension and other postretirement plans, net of taxes	—			48			—			47
Total	—			48			1			48
Comprehensive Income (Loss)	17			(286		)	192			(561		)
Comprehensive income (loss) attributable to noncontrolling interests	(12		)	81			41			124
Comprehensive Income (Loss) Attributable to Common Stockholders	$	29		$	(367	)	$	151		$	(685	)

See accompanying Notes to Consolidated Financial Statements.

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30,			December 31,
millions except per-share amounts	2018			2017
ASSETS
Current Assets
Cash and cash equivalents ($55 and $80 related to VIEs)	$	2,321		$	4,553
Accounts receivable (net of allowance of $13 and $14)
Customers ($143 and $106 related to VIEs)	1,238			1,222
Others ($16 and $19 related to VIEs)	671			607
Other current assets	402			380
Total	4,632			6,762
Net Properties and Equipment (net of accumulated depreciation, depletion, and amortization of $35,229 and $34,107) ($6,214 and $5,731 related to VIEs)	28,502			27,451
Other Assets ($768 and $579 related to VIEs)	2,301			2,211
Goodwill and Other Intangible Assets ($1,177 and $1,191 related to VIEs)	5,646			5,662
Total Assets	$	41,081		$	42,086

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable
Trade ($301 and $305 related to VIEs)	$	2,246		$	1,894
Other	200			266
Short-term debt - Anadarko⁽¹⁾	910			142
Short-term debt - WGP/WES	28			—
Current asset retirement obligations	344			294
Other current liabilities	1,699			1,310
Total	5,427			3,906
Long-term Debt
Long-term debt - Anadarko⁽¹⁾	11,178			12,054
Long-term debt - WGP/WES	4,177			3,493
Total	15,355			15,547
Other Long-term Liabilities
Deferred income taxes	2,317			2,234
Asset retirement obligations ($151 and $143 related to VIEs)	2,456			2,500
Other	4,031			4,109
Total	8,804			8,843

Equity
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 576.1 million and 574.2 million shares issued)	57			57
Paid-in capital	12,306			12,000
Retained earnings	1,054			1,109
Treasury stock (74.5 million and 43.4 million shares)	(4,105		)	(2,132		)
Accumulated other comprehensive income (loss)	(410		)	(338		)
Total Stockholders’ Equity	8,902			10,696
Noncontrolling interests	2,593			3,094
Total Equity	11,495			13,790
Total Liabilities and Equity	$	41,081		$	42,086

__________________________________________________________________

Parenthetical references reflect amounts as of June 30, 2018, and December 31, 2017.

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


⁽¹⁾	Excludes WES and WGP.

See accompanying Notes to Consolidated Financial Statements.

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)



	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)	—		—			150			—			—			41			191
Common stock issued	—		6			—			—			—			—			6
Share-based compensation expense	—		84			—			—			—			—			84
Dividends—common stock	—		—			(254		)	—			—			—			(254		)
Repurchases of common stock	—		—			—			(1,973		)	—			—			(1,973		)
Subsidiary equity transactions	—		(14		)	—			—			—			19			5
Settlement of tangible equity units	—		230			—			—			—			(300		)	(70		)
Distributions to noncontrolling interest owners	—		—			—			—			—			(238		)	(238		)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	—		—			—			—			1			—			1
Cumulative effect of accounting change ⁽¹⁾	—		—			49			—			(73		)	(23		)	(47		)
Balance at June 30, 2018	$	57	$	12,306		$	1,054		$	(4,105	)	$	(410	)	$	2,593		$	11,495

__________________________________________________________________

⁽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 for further information.

See accompanying Notes to Consolidated Financial Statements.

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended
	June 30,
millions	2018			2017
Cash Flows from Operating Activities
Net income (loss)	$	191		$	(609	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	1,993			2,152
Deferred income taxes	27			(172		)
Dry hole expense and impairments of unproved properties	149			1,466
Impairments	147			383
(Gains) losses on divestitures, net	(28		)	(1,009		)
Total (gains) losses on derivatives, net	473			(115		)
Operating portion of net cash received (paid) in settlement of derivative instruments	(234		)	5
Other	139			159
Changes in assets and liabilities
(Increase) decrease in accounts receivable	(91		)	7
Increase (decrease) in accounts payable and other current liabilities	91			(278		)
Other items, net	(202		)	(9		)
Net cash provided by (used in) operating activities	2,655			1,980
Cash Flows from Investing Activities
Additions to properties and equipment	(3,277		)	(2,296		)
Divestitures of properties and equipment and other assets	384			3,460
Other, net	(163		)	55
Net cash provided by (used in) investing activities	(3,056		)	1,219
Cash Flows from Financing Activities
Borrowings, net of issuance costs	1,333			159
Repayments of debt	(764		)	(31		)
Financing portion of net cash received (paid) for derivative instruments	55			(125		)
Increase (decrease) in outstanding checks	34			(32		)
Dividends paid	(254		)	(56		)
Repurchases of common stock	(1,973		)	(37		)
Issuances of common stock	6			—
Distributions to noncontrolling interest owners	(238		)	(214		)
Payments of future hard-minerals royalty revenues conveyed	(25		)	(25		)
Other financing activities	—			(11		)
Net cash provided by (used in) financing activities	(1,826		)	(372		)
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and restricted cash equivalents	(15		)	(1		)
Net Increase (Decrease) in Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	(2,242		)	2,826
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at Beginning of Period	4,674			3,308
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at End of Period	$	2,432		$	6,134

See accompanying Notes to Consolidated Financial Statements.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

General Anadarko Petroleum Corporation is engaged in the exploration, development, production, and sale of oil, natural gas, and NGLs and in advancing 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 Presentation The accompanying unaudited consolidated financial statements have been prepared in accordance 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.

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. Anadarko is considered the primary beneficiary and consolidates WGP and WES. WGP and WES function with capital structures that are separate from Anadarko, consisting of their own debt instruments and publicly traded common units. All intercompany transactions have been eliminated. Undivided interests in oil and natural-gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in noncontrolled entities 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.

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 $69 million for the six months ended June 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 Information for additional information.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies (Continued)

ASU 2014-09, Revenue from Contracts with Customers (Topic 606), 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.

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ANADARKO 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), requires lessees to recognize a lease liability and a right-of-use (ROU) asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. 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 to make certain elections allowing the Company not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for land easements, and not to recognize ROU assets or lease liabilities for short-term leases. Anadarko continues to review contracts in its portfolio of leased assets to assess the impact of adopting this ASU. The Company expects the adoption of this ASU to primarily impact other assets and other liabilities and does not expect a material impact on its consolidated results of operations. To facilitate compliance with this ASU, Anadarko is implementing new accounting software and continuing to evaluate its systems, processes, and internal controls during 2018. Anadarko will adopt this ASU on January 1, 2019. As permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements, the Company does not expect to adjust comparative-period financial statements.

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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. See Note 1—Summary of Significant Accounting Policies for additional information.

Impacts on Financial Statements

Exploration and Production There were no significant changes to the timing or valuation of revenue recognized for sales of production by the Exploration and Production segment.

WES Midstream and Other Midstream Gathering and processing revenues decreased for contracts where the Company is acting as an agent for its processing customer in the sale 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 do not impact net earnings.

The following tables summarize the impacts of adopting Topic 606 on the Company’s consolidated financial statements:



CONSOLIDATED BALANCE SHEET	Impact of Change in Accounting Policy
millions	As Reported		Without Adoption of Topic 606		Effect of Change Increase/(Decrease)
June 30, 2018
Assets
Net properties and equipment	$	28,502	$	28,454	$	48
Other assets	2,301		2,289		12
Liabilities
Other current liabilities	1,699		1,692		7
Deferred income taxes	2,317		2,325		(8		)
Other	4,031		3,918		113
Equity
Total equity	11,495		11,547		(52		)

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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 June 30, 2018
Revenues
Gathering, processing, and marketing sales	$	382		$	650		$	(268	)
Gains (losses) on divestitures and other, net	123			123			—
Expenses
Gathering, processing, and marketing	252			518			(266		)
Income tax expense (benefit)	125			126			(1		)
Net income (loss) attributable to noncontrolling interests	(12		)	(14		)	2
Net Income (Loss) Attributable to Common Stockholders	$	29		$	32		$	(3	)

Six Months Ended June 30, 2018
Revenues
Gathering, processing, and marketing sales	$	742		$	1,227		$	(485	)
Gains (losses) on divestitures and other, net	142			144			(2		)
Expenses
Gathering, processing, and marketing	489			969			(480		)
Income tax expense (benefit)	251			253			(2		)
Net income (loss) attributable to noncontrolling interests	41			40			1
Net Income (Loss) Attributable to Common Stockholders	$	150		$	156		$	(6	)

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(Unaudited)

2. Revenue from Contracts with Customers (Continued)

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 June 30, 2018
Product Type
Oil sales	$	2,265		$	—		$	—	$	—		$	2,265
Natural-gas sales	203			—			—		—			203
Natural-gas liquids sales	318			—			—		—			318
Gathering, processing, and marketing sales ⁽¹⁾	—			438			107		58			603
Other, net	4			—			—		21			25
Total Revenue from Customers	$	2,790		$	438		$	107	$	79		$	3,414
Gathering, processing, and marketing sales ⁽²⁾	—			(2		)	1		(220		)	(221		)
Gains (losses) on divestitures, net	52			—			—		—			52
Other, net	(1		)	32			8		7			46
Total Revenue from Other than Customers	$	51		$	30		$	9	$	(213	)	$	(123	)
Total Revenue and Other	$	2,841		$	468		$	116	$	(134	)	$	3,291

Six Months Ended June 30, 2018
Product Type
Oil sales	$	4,392		$	—		$	—	$	—		$	4,392
Natural-gas sales	450			—			—		—			450
Natural-gas liquids sales	610			—			—		—			610
Gathering, processing, and marketing sales ⁽¹⁾	—			876			193		82			1,151
Other, net	7			—			—		40			47
Total Revenue from Customers	$	5,459		$	876		$	193	$	122		$	6,650
Gathering, processing, and marketing sales ⁽²⁾	—			(3		)	3		(409		)	(409		)
Gains (losses) on divestitures, net	19			—			9		—			28
Other, net	(13		)	61			18		1			67
Total Revenue from Other than Customers	$	6		$	58		$	30	$	(408	)	$	(314	)
Total Revenue and Other	$	5,465		$	934		$	223	$	(286	)	$	6,336

__________________________________________________________________


⁽¹⁾	The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $261 million and intercompany eliminations of $(207) million for the three months ended June 30, 2018, and sales of third-party natural gas and NGLs of $485 million and intercompany eliminations of $(403) million for the six months ended June 30, 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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⁾	52
Decrease due to revenue recognized ⁽²⁾	(21		)
Balance at June 30, 2018	$	166

Contract liabilities at June 30, 2018
Other current liabilities	$	37
Other long-term liabilities - other	129
Total contract liabilities from contracts with customers	$	166

__________________________________________________________________


⁽¹⁾	Includes $12 million for the three months ended June 30, 2018.


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

Transaction Price Allocated to Remaining Performance Obligations Revenue expected to be recognized from certain performance obligations that are unsatisfied as of June 30, 2018, 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 and variable commodity prices for those volumes.



millions	Exploration & Production		WES Midstream		Other Midstream		Other and Intersegment Eliminations			Total
Remainder of 2018	$	51	$	220	$	25	$	(129	)	$	167
2019	102		493		136		(390		)	341
2020	103		542		207		(516		)	336
2021	103		527		248		(562		)	316
2022	7		527		289		(610		)	213
Thereafter	65		2,168		1,761		(3,288		)	706
Total	$	431	$	4,477	$	2,666	$	(5,495	)	$	2,079

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

3. Commodity Inventories

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



	June 30,		December 31,
millions	2018		2017
Oil	$	221	$	165
Natural gas	14		29
NGLs	114		122
Total commodity inventories	$	349	$	316

4. Divestitures

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



	Six Months Ended
	June 30,
millions	2018		2017
Proceeds received, net of closing adjustments	$	384	$	3,460
Gains (losses) on divestitures, net ⁽¹⁾	28		1,009

__________________________________________________________________


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

2018 During the six months ended June 30, 2018, the Company divested of the following U.S. onshore and Gulf of Mexico assets:


•	Alaska nonoperated assets, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $383 million and net losses of $37 million in 2018 and $154 million in the fourth quarter of 2017. During the second quarter of 2018, all necessary regulatory approvals were obtained and finalized for this transaction.


•	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 six months ended June 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 $729 million


•	Marcellus assets in Pennsylvania, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $758 million and net losses of $54 million in 2017 and $129 million in the fourth quarter of 2016


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


•	Utah CBM assets, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $70 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

5. Impairments

Impairments of Long-Lived Assets

2018 During the three months ended June 30, 2018, the Company expensed $128 million primarily 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 six months ended June 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 a U.S. onshore midstream property, included in the WES Midstream reporting segment, due to a reduced throughput fee as a result of a producer’s bankruptcy. The asset 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 six months ended June 30, 2018, the Company recognized $94 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 $555 million of impairments of unproved Gulf of Mexico properties during the six months ended June 30, 2017, of which $463 million related to the Shenandoah project. The unproved property balance related to the Shenandoah project originated from the purchase price allocated to the Gulf of Mexico exploration projects from the acquisition of Kerr-McGee Corporation in 2006.

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

The Company’s suspended exploratory well costs were $498 million at June 30, 2018, and $525 million at December 31, 2017. 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 six months ended June 30, 2018, there was no exploration expense recorded for suspended exploratory well costs previously capitalized for greater than one year at December 31, 2017.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Current Liabilities

Accounts Payable Accounts payable, trade included liabilities of $253 million at June 30, 2018, and $219 million at December 31, 2017, 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:



	June 30,		December 31,
millions	2018		2017
Accrued income taxes	$	40	$	71
Interest payable	265		246
Production, property, and other taxes payable	303		216
Accrued employee benefits	194		210
Derivatives	707		384
Other	190		183
Total other current liabilities	$	1,699	$	1,310

8. 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 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.

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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 natural-gas prices listed below are NYMEX Henry Hub prices. The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at June 30, 2018:



	2018 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
Average price per barrel (WTI and Brent)
Ceiling sold price (call)	$	—	$	72.98
Floor purchased price (put)	$	—	$	56.72
Floor sold price (put)	$	—	$	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. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (e.g., NYMEX) plus the excess of the purchased put strike price over the sold put strike price.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Derivative Instruments (Continued)

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

At June 30, 2018, 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 June 30, 2018:



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

Derivative settlements and collateralization are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements and collateralization are classified as cash flows from financing activities. As a result of prior extensions of reference-period start dates without settlement of the related interest-rate derivative obligations, the interest-rate derivatives in the Company’s portfolio contain an other-than-insignificant financing element, and therefore, any settlements, collateralization, or 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 $48 million during the six months ended June 30, 2018, and $65 million during the six months ended June 30, 2017.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. 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
millions	June 30,		December 31,		June 30,			December 31,
Balance Sheet Classification	2018		2017		2018			2017
Commodity derivatives
Other current assets	$	3	$	7	$	—		$	(1	)
Other assets	1		2		—			—
Other current liabilities	34		45		(552		)	(206		)
Other liabilities	55		—		(95		)	(2		)
	93		54		(647		)	(209		)
Interest-rate derivatives
Other current assets	19		14		—			—
Other assets	40		40		—			—
Other current liabilities	—		—		(205		)	(236		)
Other liabilities	—		—		(1,011		)	(1,183		)
	59		54		(1,216		)	(1,419		)
Total derivatives	$	152	$	108	$	(1,863	)	$	(1,628	)

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



	Three Months Ended						Six Months Ended
millions	June 30,						June 30,
Classification of (Gain) Loss Recognized	2018			2017			2018			2017
Commodity derivatives
Gathering, processing, and marketing sales	$	1		$	—		$	2		$	—
(Gains) losses on derivatives, net	468			(72		)	630			(207		)
Interest-rate derivatives
(Gains) losses on derivatives, net	(32		)	104			(159		)	92
Total (gains) losses on derivatives, net	$	437		$	32		$	473		$	(115	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. 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 June 30, 2018, 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. The Company may be required to post additional collateral with respect to its derivative instruments if its credit ratings decline below current levels. For example, based on the derivative positions as of June 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 $153 million. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.6 billion (net of $67 million of collateral) at June 30, 2018, and $1.4 billion (net of $170 million of collateral) at December 31, 2017.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Derivative Instruments (Continued)

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

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



millions	Level 1			Level 2			Level 3		Netting ⁽¹⁾			Collateral			Total
June 30, 2018
Assets
Commodity derivatives	$	—		$	93		$	—	$	(89	)	$	—		$	4
Interest-rate derivatives	—			59			—		—			—			59
Total derivative assets	$	—		$	152		$	—	$	(89	)	$	—		$	63
Liabilities
Commodity derivatives	$	—		$	(647	)	$	—	$	89		$	10		$	(548	)
Interest-rate derivatives	—			(1,216		)	—		—			67			(1,149		)
Total derivative liabilities	$	—		$	(1,863	)	$	—	$	89		$	77		$	(1,697	)

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	)

__________________________________________________________________


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

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

Debt Activity The following summarizes the Company’s borrowing activity, after eliminating the effect of intercompany transactions, during the six months ended June 30, 2018:



	Carrying Value
millions	WES			WGP ⁽¹⁾		Anadarko ⁽²⁾			Anadarko Consolidated			Description
Balance at December 31, 2017	$	3,465		$	28	$	11,965		$	15,458
Issuances
	394			—		—			394			WES 4.500% Senior Notes due 2028
	687			—		—			687			WES 5.300% Senior Notes due 2048
Borrowings
	260			—		—			260			WES RCF
Repayments
	(630		)	—		—			(630		)	WES RCF
	—			—		(114		)	(114		)	7.050% Debentures due 2018
	—			—		(17		)	(17		)	TEUs - senior amortizing notes
Other, net	1			—		25			26			Amortization of discounts, premiums, and debt issuance costs
Balance at June 30, 2018	$	4,177		$	28	$	11,859		$	16,064

__________________________________________________________________


⁽¹⁾	Excludes WES.


⁽²⁾	Excludes WES and WGP.

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ANADARKO 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
June 30, 2018
Total borrowings at face value	$	4,220		$	28	$	13,383		$	17,631
Net unamortized discounts, premiums, and debt issuance costs ⁽³⁾	(43		)	—		(1,524		)	(1,567		)
Total borrowings ⁽⁴⁾	4,177			28		11,859			16,064
Capital lease obligations	—			—		229			229
Less short-term debt	—			28		910			938
Total long-term debt	$	4,177		$	—	$	11,178		$	15,355

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

Fair Value The Company uses a market approach to determine the fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was $17.5 billion at June 30, 2018, and $17.7 billion at December 31, 2017.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10. Debt (Continued)

Anadarko Borrowings 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 June 30, 2018, Anadarko had no outstanding borrowings under the APC RCF or the 364-Day Facility and was in compliance with all covenants.

At June 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. Short-term debt also included the current portion of the Company’s capital lease obligations.

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, which, if put in whole, will be $930 million at the next put date in October 2018. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at June 30, 2018, as the Company has the ability and intent to refinance these obligations using long-term debt, should the 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—Equity-Method Investments in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

WES and WGP Borrowings 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 six months ended June 30, 2018, WES borrowed $260 million under its RCF, which was used for general partnership purposes, and made repayments of $630 million. At June 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. WES’s $350 million 2.600% Senior Notes due August 2018 were classified as long-term debt on the Company’s Consolidated Balance Sheet at June 30, 2018, as WES has the ability and intent to refinance these obligations using long-term debt.

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 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 March 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 June 30, 2018, WGP had outstanding borrowings of $28 million at an interest rate of 4.10%, classified as short-term debt on the Company’s Consolidated Balance Sheet, and had available borrowing capacity of $7 million. At June 30, 2018, WGP was in compliance with all covenants.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. 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%. 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 necessary adjustments to provisional tax amounts 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						Six Months Ended
	June 30,						June 30,
millions except percentages	2018			2017			2018			2017
Current income tax expense (benefit)	$	147		$	(522	)	$	237		$	240
Deferred income tax expense (benefit)	(22		)	484			14			(181		)
Total income tax expense (benefit)	$	125		$	(38	)	$	251		$	59
Income (loss) before income taxes	142			(372		)	442			(550		)
Effective tax rate	88		%	10		%	57		%	(11		)%

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 six months ended June 30, 2018, was primarily attributable to the following items:


•	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 six months ended June 30, 2017. As a result, items that ordinarily increase or decrease tax rate will have the opposite effect. The variance from the U.S. federal statutory rate of 35% for the three and six months ended June 30, 2017 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

The Company recognized a net tax benefit of $346 million as of June 30, 2018 and December 31, 2017, 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 June 30, 2018 and December 31, 2017, due to uncertainty related to the deductibility of the settlement payment. Due to the deduction of the settlement payment, 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. The Company disagrees and is defending its tax position. Accordingly, the Company has not revised its estimate of the benefit that will ultimately be realized. It is reasonably possible the amount of uncertain tax position and/or tax benefit could materially change as the Company defends its tax position through the appeals process and other available avenues. The Company could be required to repay all or a portion of the tentative refund received, with interest, prior to determining the final outcome of its position either upon IRS request or litigation of the matter in District or Federal Claims Court. If the payment is ultimately determined not to be deductible, the Company would be required to repay the tentative refund received, plus interest, and reverse the net benefit of $346 million previously recognized in its consolidated financial statements.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. Contingencies

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

13. 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
millions	2018			2017			2018			2017
Three Months Ended June 30
Service cost	$	22		$	21		$	1		$	1
Interest cost	19			21			2			3
Expected (return) loss on plan assets	(20		)	(21		)	—			—
Amortization of net actuarial loss (gain)	6			7			—			—
Amortization of net prior service cost (credit)	—			—			(6		)	(6		)
Settlement expense	—			55			—			—
Net periodic benefit cost ⁽¹⁾	$	27		$	83		$	(3	)	$	(2	)

Six Months Ended June 30
Service cost	$	45		$	42		$	1		$	1
Interest cost	38			42			5			6
Expected (return) loss on plan assets	(41		)	(42		)	—			—
Amortization of net actuarial loss (gain)	13			13			—			—
Amortization of net prior service cost (credit)	—			—			(12		)	(12		)
Settlement expense	—			58			—			—
Termination benefits expense	—			4			—			—
Net periodic benefit cost ⁽¹⁾	$	55		$	117		$	(6	)	$	(5	)

__________________________________________________________________


⁽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 $151 million to funded pension plans and $23 million to unfunded pension plans during the six months ended June 30, 2018. The Company expects to contribute an additional $11 million to funded pension plans and $19 million to unfunded pension plans during 2018.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14. Stockholders’ Equity

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

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
millions except per-share amounts	2018			2017			2018			2017
Net income (loss)
Net income (loss) attributable to common stockholders	$	29		$	(415	)	$	150		$	(733	)
Income (loss) effect of TEUs	(1		)	(2		)	(4		)	(4		)
Less distributions on participating securities	1			—			2			—
Basic	$	27		$	(417	)	$	144		$	(737	)
Income (loss) effect of TEUs	—			(1		)	(1		)	(1		)
Diluted	$	27		$	(418	)	$	143		$	(738	)
Shares
Average number of common shares outstanding—basic	504			552			511			552
Dilutive effect of stock options	1			—			1			—
Average number of common shares outstanding—diluted	505			552			512			552
Excluded due to anti-dilutive effect	9			11			9			11
Net income (loss) per common share
Basic	$	0.05		$	(0.76	)	$	0.28		$	(1.34	)
Diluted	$	0.05		$	(0.76	)	$	0.28		$	(1.34	)

Common Stock The 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. As of the end of the second quarter of 2018, the Company had completed $3.0 billion of the Share-Repurchase Program.

During the six months ended June 30, 2018, the Company entered into and completed two ASR Agreements 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
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		$	1,941			26.1	4.5	30.6

Under each ASR Agreement, the Company paid a specific amount in cash and received an initial delivery of shares of the Company’s common stock. The initial delivery of shares represented 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. 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.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15. Noncontrolling Interests

WES is a limited partnership formed by Anadarko to acquire, own, develop, and operate midstream assets. During 2016, WES issued 22 million Series A Preferred units to private investors. Pursuant to an agreement between WES and the holders of the Series A Preferred units, 50% of the Series A Preferred units converted into WES common units on a one-for-one basis on March 1, 2017, and all remaining Series A Preferred units were converted on May 2, 2017.

WES Class C units issued to Anadarko will convert into WES common units on a one-for-one basis on the conversion date, which was extended in February 2017 from December 31, 2017, to March 1, 2020. The Class C units receive quarterly distributions in the form of additional Class C units until the March 1, 2020 conversion date, unless WES elects to convert the units to common units earlier or Anadarko elects to extend the conversion date. WES distributed 534 thousand Class C units to Anadarko during the six months ended June 30, 2018, and 886 thousand 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. See Note 9—Tangible Equity Units for additional information. At June 30, 2018, Anadarko’s ownership interest in WGP consisted of a 77.8% 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 June 30, 2018, WGP’s ownership interest in WES consisted of a 29.7% limited partner interest, the entire 1.5% general partner interest, and all of the WES incentive distribution rights. At June 30, 2018, Anadarko also owned a 9.3% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 59.5% limited partner interest in WES was owned by the public.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

16. Variable Interest Entities

Consolidated VIEs The Company determined that the partners in WGP and WES with equity at risk lack the power, through voting rights or similar rights, to direct the activities that most significantly impact WGP’s and WES’s economic performance; therefore, WGP and WES are considered VIEs. Anadarko, through its ownership of the general partner interest in WGP, has the power to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to WGP and WES; therefore, Anadarko is considered the primary beneficiary and consolidates WGP, WES, and all of their consolidated subsidiaries. For additional information on WGP and WES, see Note 15—Noncontrolling Interests.

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



	Three Months Ended				Six Months Ended
	June 30,				June 30,
millions	2018		2017		2018		2017
Statement of Operations Data
Total revenues and other	$	436	$	525	$	873	$	1,042
Operating income (loss)	74		207		261		345
Net income (loss)	35		174		185		277



	Six Months Ended
	June 30,
millions	2018			2017
Statement of Cash Flows Data
Net cash provided by (used in) operating activities	$	513		$	431
Net cash provided by (used in) investing activities	(827		)	(363		)
Net cash provided by (used in) financing activities	289			(238		)



	June 30,		December 31,
millions	2018		2017
Balance Sheet Data
Cash and cash equivalents	$	55	$	80
Net property, plant, and equipment	6,214		5,731
Total assets	8,669		8,016
Long-term debt	4,177		3,493
Total liabilities	4,993		4,071
Total equity and partners’ capital	3,676		3,945

Assets and Liabilities of VIEs The assets of WGP, WES, and their 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 subsidiaries for which the creditors do not have recourse to other assets of the Company are included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets.

All outstanding debt for WES at June 30, 2018 and December 31, 2017, including any borrowings under the WES RCF, is recourse to WES’s general partner, which in turn has been indemnified in certain circumstances by certain wholly owned subsidiaries of the Company for such liabilities. All outstanding debt for WGP at June 30, 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—Debt for additional information on WGP and WES short-term and long-term debt balances.

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ANADARKO 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 RCF, the issuance of additional partnership units, and debt offerings. See Note 10—Debt and Note 15—Noncontrolling Interests for additional information on WGP and WES financing activity.

Financial Support Provided to VIEs Concurrent with the closing of its May 2008 IPO, WES loaned the Company $260 million in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The related interest income for WES was $4 million for each of the three months ended June 30, 2018 and 2017, and $8 million for each of the six months ended June 30, 2018 and 2017. 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 commodity price swap agreements in place with WES expiring on December 31, 2018. 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 $28 million for the six months ended June 30, 2018, and $29 million for the six months ended June 30, 2017.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

17. Supplemental Cash Flow Information

Additions to properties and equipment as presented within Anadarko’s cash flows from investing activities include cash payments for cost of properties, equipment, and facilities. The cost of properties includes the initial capitalization of drilling costs associated with all exploratory wells whether or not they were deemed to have a commercially sufficient quantity of proved reserves.

The following summarizes cash paid (received) for interest and income taxes as well as non-cash investing and financing activities:



	Six Months Ended
	June 30,
millions	2018			2017
Cash paid (received)
Interest, net of amounts capitalized	$	471		$	449
Income taxes, net of refunds	53			162
Non-cash investing activities
Fair value of properties and equipment acquired	$	7		$	553
Asset retirement cost additions	162			138
Accruals of property, plant, and equipment	1,036			696
Net liabilities assumed (divested) in acquisitions and divestitures	(97		)	(100		)
Non-cash investing and financing activities
Deferred drilling lease liability	$	—		$	13
Non-cash financing activities
Settlement of tangible equity units	$	300		$	—

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:



	June 30,		December 31,
millions	2018		2017
Cash and cash equivalents	$	2,321	$	4,553
Restricted cash and restricted cash equivalents included in Other Assets	111		121
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	$	2,432	$	4,674

Included in cash and cash equivalents is restricted cash and restricted cash equivalents of $139 million at June 30, 2018, and $255 million at December 31, 2017. 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—Contingencies in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

18. Segment Information

Anadarko’s business segments are separately managed due to distinct operational differences. Anadarko has three reporting segments: Exploration and Production, WES Midstream, and Other Midstream, which include their respective marketing results. The Company has reclassified prior-period amounts to conform to the current-period 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 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; 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						Six Months Ended
	June 30,						June 30,
millions	2018			2017			2018			2017
Income (loss) before income taxes	$	142		$	(372	)	$	442		$	(550	)
Interest expense	237			229			465			452
DD&A	1,003			1,037			1,993			2,152
Exploration expense	94			532			262			1,616
(Gains) losses on divestitures, net	(52		)	(205		)	(28		)	(1,009		)
Impairments	128			10			147			383
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	267			45			240			(110		)
Restructuring charges	—			18			—			17
Less net income (loss) attributable to noncontrolling interests	(12		)	81			41			124
Consolidated Adjusted EBITDAX	$	1,831		$	1,213		$	3,480		$	2,827

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

18. 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 June 30, 2018
Sales revenues	$	2,772	$	308	$	49	$	39		$	3,168
Intersegment revenues	14		128		58		(200		)	—
Other	3		32		9		27			71
Total revenues and other ⁽¹⁾	2,789		468		116		(134		)	3,239
Operating costs and expenses ⁽²⁾	905		196		77		69			1,247
Net cash from settlement of commodity derivatives	—		—		—		170			170
Other (income) expense, net	—		—		—		4			4
Net income (loss) attributable to noncontrolling interests	—		—		—		(12		)	(12		)
Total expenses and other	905		196		77		231			1,409
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—		—		—		1			1
Adjusted EBITDAX	$	1,884	$	272	$	39	$	(364	)	$	1,831

Three Months Ended June 30, 2017
Sales revenues	$	1,952	$	402	$	45	$	20		$	2,419
Intersegment revenues	3		117		40		(160		)	—
Other	8		55		7		22			92
Total revenues and other ⁽¹⁾	1,963		574		92		(118		)	2,511
Operating costs and expenses ⁽²⁾	800		299		56		55			1,210
Net cash from settlement of commodity derivatives	—		—		—		(13		)	(13		)
Other (income) expense, net	—		—		—		20			20
Net income (loss) attributable to noncontrolling interests	—		—		—		81			81
Total expenses and other	800		299		56		143			1,298
Adjusted EBITDAX	$	1,163	$	275	$	36	$	(261	)	$	1,213

__________________________________________________________________


⁽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.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

18. Segment Information (Continued)



millions	Exploration & Production			WES Midstream		Other Midstream		Other and Intersegment Eliminations			Total
Six Months Ended June 30, 2018
Sales revenues	$	5,428		$	618	$	85	$	63		$	6,194
Intersegment revenues	24			255		110		(389		)	—
Other	(6		)	61		19		40			114
Total revenues and other ⁽¹⁾	5,446			934		214		(286		)	6,308
Operating costs and expenses ⁽²⁾	1,781			390		131		262			2,564
Net cash from settlement of commodity derivatives	—			—		—		238			238
Other (income) expense, net	—			—		—		(8		)	(8		)
Net income (loss) attributable to noncontrolling interests	—			—		—		41			41
Total expenses and other	1,781			390		131		533			2,835
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		—		7			7
Adjusted EBITDAX	$	3,665		$	544	$	83	$	(812	)	$	3,480

Six Months Ended June 30, 2017
Sales revenues	$	4,403		$	768	$	81	$	65		$	5,317
Intersegment revenues	6			268		82		(356		)	—
Other	10			85		13		49			157
Total revenues and other ⁽¹⁾	4,419			1,121		176		(242		)	5,474
Operating costs and expenses ⁽²⁾	1,723			591		106		86			2,506
Net cash from settlement of commodity derivatives	—			—		—		(7		)	(7		)
Other (income) expense, net	—			—		—		22			22
Net income (loss) attributable to noncontrolling interests	—			—		—		124			124
Total expenses and other	1,723			591		106		225			2,645
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—		—		(2		)	(2		)
Adjusted EBITDAX	$	2,696		$	530	$	70	$	(469	)	$	2,827

__________________________________________________________________


⁽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.

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

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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

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


•	the Company’s assumptions about energy markets


•	production and sales volume levels


•	levels of oil, natural-gas, and 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

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•	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, successfully complete its debt-reduction program, 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; 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.

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MANAGEMENT OVERVIEW

Anadarko’s strategy is 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 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 affect the value the Company receives from its sales of oil, natural gas, and NGLs.

The Company continues to leverage its foundational principle of efficient capital allocation to generate attractive returns on, and of, capital while investing within cash flow. Anadarko also continues to focus on cash-margin improvement 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 to use excess cash generated from its Gulf of Mexico, international producing, and DJ basin assets to fund the growth of its other unconventional assets in the U.S. onshore and return cash to stakeholders.

In the second quarter of 2018, the Company completed the repurchase of $1.4 billion of the Company’s common stock, bringing the total repurchases to $3.0 billion. In July 2018, Anadarko expanded the Share-Repurchase Program from $3.0 billion to $4.0 billion. The Company also announced a $500 million increase to its debt-reduction program, bringing the total planned debt reduction to $1.5 billion. In the second quarter of 2018, the Company repaid $114 million of debt at maturity and has 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.

In the Delaware basin, the Company continues to build out one of the most expansive and integrated infrastructure positions in the region and is transitioning to 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. Subsequent to quarter end, final commissioning activities were completed for the ROTF in Loving County where new wells in the area are expected to be brought online and flow into this ROTF during the third quarter of 2018. The completion of these facilities supports the more cost-effective and environmentally beneficial tankless battery design field-wide and also secures necessary gathering, processing, and takeaway capacity. This comprehensive build-out plan and phased development approach in the Delaware basin is expected to deliver incremental oil sales volumes during the second half of 2018. The Company ended the second quarter of 2018 with 7 operated drilling rigs in the Delaware basin, which compares to 10 operated drilling rigs at year-end 2017.

In the DJ basin, the Company continues to leverage its minerals-interest ownership and extensive infrastructure position to deliver development wells with attractive rates of return. The Company ended the second quarter of 2018 with four operated drilling rigs in the DJ basin, which compares to six operated drilling rigs at year-end 2017. The Company plans to operate at this level for the remainder of 2018.

In the deepwater Gulf of Mexico, Anadarko has two floating drillships and one platform rig available to conduct operations that are focused toward high-return oil development opportunities near the Company’s expansive infrastructure. Internationally, drilling continues in offshore Ghana with new development activities planned at the TEN and Jubilee fields.

In order to reduce commodity-price risk and increase the predictability of 2018 cash flows, the Company has strategic derivative positions covering approximately 50% of its anticipated oil sales volumes for 2018, including approximately 85% of its expected Brent-levered sales volumes. The Company also has strategic derivative positions covering slightly more than 50% of its anticipated 2018 natural-gas sales volumes. See Note 8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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Significant operating and financial activities for the second quarter of 2018 include the following:

Total Company


•	Anadarko’s overall sales-volume product mix increased to 57% oil in the second quarter of 2018, compared to 52% in the second quarter of 2017, which improved margins and returns.

U.S. Onshore


•	U.S. onshore oil sales volumes increased by 39 MBbls/d, representing a 30% increase from the second quarter of 2017, primarily due to continued drilling and completion activities.


•	In the Delaware basin, the first ROTF was completed in Reeves County, with 30 wells online at the end of the second quarter.

International

Ghana


•	In the TEN fields of Ghana, the operator resumed drilling operations in the first quarter of 2018 and began completion operations in the second quarter of 2018.


•	In the second quarter of 2018, the operator of the FPSO at the Jubilee field in Ghana completed the second of three shutdown periods expected to occur in 2018 to effectively stabilize the turret and rotate the FPSO to its permanent heading. In addition, the operator drilled two wells during the quarter with completion operations and first production anticipated in the second half of 2018.

Mozambique


•	Anadarko and its co-venturers in Mozambique Area 1 signed a Heads of Agreement with Tokyo Gas Co., Ltd. and Centrica LNG Company for long-term LNG off-take of 2.6 million tonnes per annum. The Company is now focused on converting all non-binding commitments to fully termed Sales and Purchase Agreements.


•	The resettlement and onshore site preparation activities continue to progress in order to position the area for construction of the LNG facilities.


•	With the continued progress in marketing, project finance, contracts, and site improvement activities, Anadarko and its co-venturers expect to take FID in the first half of 2019.

Financial


•	The Company generated $1.2 billion of cash flow from operations and ended the quarter with $2.3 billion of cash.


•	In June 2018, the Company completed the repurchase of an additional $1.4 billion of the Company’s common stock under the Share-Repurchase Program.


•	In July 2018, the Company expanded the Share-Repurchase Program to $4.0 billion and extended the program through June 30, 2019.


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

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FINANCIAL RESULTS



	Three Months Ended					Six Months Ended
	June 30,					June 30,
millions except per-share amounts	2018		2017			2018		2017
Oil, natural-gas, and NGLs sales	$	2,786	$	1,955		$	5,452	$	4,409
Gathering, processing, and marketing sales	382		464			742		908
Gains (losses) on divestitures and other, net	123		297			142		1,166
Revenues and other	$	3,291	$	2,716		$	6,336	$	6,483
Costs and expenses	2,472		2,783			4,966		6,650
Other (income) expense	677		305			928		383
Income tax expense (benefit)	125		(38		)	251		59
Net income (loss) attributable to common stockholders	$	29	$	(415	)	$	150	$	(733	)
Net income (loss) per common share attributable to common stockholders—diluted	$	0.05	$	(0.76	)	$	0.28	$	(1.34	)
Average number of common shares outstanding—diluted	505		552			512		552

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

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Revenues and Sales Volumes



	Three Months Ended
	June 30,
millions except percentages	Oil			Natural Gas			NGLs			Total
2017 sales revenues	$	1,422		$	319		$	214		$	1,955
Changes associated with prices	703			(64		)	89			728
Changes associated with sales volumes	140			(52		)	15			103
2018 sales revenues	$	2,265		$	203		$	318		$	2,786
Increase (decrease) vs. 2017	59		%	(36		)%	49		%	43		%

	Six Months Ended
	June 30,
millions except percentages	Oil			Natural Gas			NGLs			Total
2017 sales revenues	$	3,085		$	821		$	503		$	4,409
Changes associated with prices	1,144			(104		)	143			1,183
Changes associated with sales volumes	163			(267		)	(36		)	(140		)
2018 sales revenues	$	4,392		$	450		$	610		$	5,452
Increase (decrease) vs. 2017	42		%	(45		)%	21		%	24		%

The above table illustrates the effects of changes in prices and sales volumes. The changes in sales volumes include 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.

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



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2018	Inc (Dec) vs. 2017		2017	2018	Inc (Dec) vs. 2017		2017
Barrels of Oil Equivalent
(MMBOE except percentages)
United States	50	3	%	49	100	(10	)%	111
International	8	(9	)	8	16	(13	)	18
Total barrels of oil equivalent	58	1		57	116	(10	)	129

Barrels of Oil Equivalent per Day
(MBOE/d except percentages)
United States	552	3	%	538	553	(10	)%	614
International	85	(9	)	93	87	(13	)	99
Total barrels of oil equivalent per day	637	1		631	640	(10	)	713

Sales volumes represent actual production volumes adjusted for changes in commodity inventories as well as natural-gas production volumes provided to satisfy a commitment under the Jubilee development plan in Ghana. The Company has derivative instruments in place to reduce the price risk associated with future production. For additional information, see Note 8—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.

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Oil Sales Revenues, Average Prices, and Volumes



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018		Inc (Dec) vs. 2017		2017		2018		Inc (Dec) vs. 2017		2017
Oil sales revenues (millions)	$	2,265	59	%	$	1,422	$	4,392	42	%	$	3,085

United States
Sales volumes—MMBbls	27		17	%	22		52		12	%	46
MBbls/d	284		17		243		286		12		256
Price per barrel	$	66.94	43		$	46.68	$	64.75	35		$	48.01

International
Sales volumes—MMBbls	7		(9	)%	8		15		(12	)%	17
MBbls/d	80		(9	)	88		82		(12	)	93
Price per barrel	$	73.70	52		$	48.61	$	70.51	38		$	51.10

Total
Sales volumes—MMBbls	34		10	%	30		67		5	%	63
MBbls/d	364		10		331		368		5		349
Price per barrel	$	68.43	45		$	47.19	$	66.03	35		$	48.84

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 June 30, 2018 vs. 2017	$	843	$	703	$	140
Six months ended June 30, 2018 vs. 2017	1,307		1,144		163

Oil Prices

The average oil price received increased for the three and six months ended June 30, 2018, primarily due to strong global demand growth and a more balanced global supply as a result of a reduction in OPEC’s production in 2017 and early 2018.

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Oil Sales Volumes

2018 vs. 2017 The Company’s oil sales volumes increased by 33 MBbls/d for the three months ended June 30, 2018, and 19 MBbls/d for the six months ended June 30, 2018, primarily due to the following:

U.S. Onshore


•	Sales volumes for the Delaware basin increased by 29 MBbls/d for the three months ended June 30, 2018, and 25 MBbls/d for the six months ended June 30, 2018, primarily due to continued drilling and completion activities in 2018.


•	Sales volumes for the DJ basin increased by 23 MBbls/d for the three months ended June 30, 2018, and 21 MBbls/d for the six months ended June 30, 2018, primarily due to continued drilling and completion activities in 2018.


•	Divestitures resulted in a decrease in sales volumes of 15 MBbls/d for the three months ended June 30, 2018, and 20 MBbls/d for the six months ended June 30, 2018, primarily related to the sale of the Eagleford and West Chalk assets in the first half of 2017 and the Alaska nonoperated assets in the first quarter of 2018.

Gulf of Mexico


•	Sales volumes for the Gulf of Mexico increased by 2 MBbls/d for the three and six months ended June 30, 2018, primarily due to continued tie-back activity at Horn Mountain and Marlin, partially offset by construction and maintenance downtime at other platforms.

International


•	Sales volumes for Algeria decreased by 7 MBbls/d for the three months ended June 30, 2018, and 10 MBbls/d for the six months ended June 30, 2018, primarily due to timing of liftings and a decrease in production driven by facility downtime for statutory maintenance.

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Natural-Gas Sales Revenues, Average Prices, and Volumes



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018		Inc (Dec) vs. 2017		2017		2018		Inc (Dec) vs. 2017		2017
Natural-gas sales revenues (millions)	$	203	(36	)%	$	319	$	450	(45	)%	$	821

United States
Sales volumes—Bcf	94		(16	)%	113		189		(33	)%	280
MMcf/d	1,037		(16	)	1,238		1,044		(33	)	1,547
Price per Mcf	$	2.15	(24	)	$	2.84	$	2.38	(19	)	$	2.93

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



millions	Change in Revenues			Due to Change in Prices			Due to Change in Volumes
Three months ended June 30, 2018 vs. 2017	$	(116	)	$	(64	)	$	(52	)
Six months ended June 30, 2018 vs. 2017	(371		)	(104		)	(267		)

Natural-Gas Prices

The average natural-gas price received decreased for the three and six months ended June 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 decreased by 201 MMcf/d for the three months ended June 30, 2018, and 503 MMcf/d for the six months ended June 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.

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018		Inc (Dec) vs. 2017		2017		2018		Inc (Dec) vs. 2017		2017
Natural-gas liquids sales revenues (millions)	$	318	49	%	$	214	$	610	21	%	$	503

Total
Sales volumes—MMBbls ⁽¹⁾	9		7	%	8		18		(7	)%	19
MBbls/d ⁽¹⁾	100		7		94		98		(7	)	106
Price per barrel	$	34.88	39		$	25.14	$	34.27	30		$	26.27

_______________________________________________________________________________


⁽¹⁾	The percentage of total and daily NGLs sales volumes from the U.S. was 95% for three and six months ended June 30, 2018, and 94% for the three and six months ended June 30, 2017.

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



millions	Change in Revenues		Due to Change in Prices		Due to Change in Volumes
Three months ended June 30, 2018 vs. 2017	$	104	$	89	$	15
Six months ended June 30, 2018 vs. 2017	107		143		(36		)

NGLs Prices

The average NGLs price received increased for the three and six months ended June 30, 2018, primarily due to increased ethane prices resulting from increased domestic demand and increased propane prices stemming from higher underlying crude prices.

NGLs Sales Volumes

2018 vs. 2017 The Company’s NGLs sales volumes increased by 6 MBbls/d for the three months ended June 30, 2018, and decreased by 8 MBbls/d for the six months ended June 30, 2018, primarily due to the following:

U.S. Onshore


•	Sales volumes for the Delaware basin increased by 7 MBbls/d for the three and six months ended June 30, 2018, primarily due to continued drilling and completion activities in 2018.


•	Sales volumes for other U.S. onshore assets decreased by 13 MBbls/d for the six months ended June 30, 2018, primarily due to the sale of the Eagleford and West Chalk assets in the first half of 2017 and the Moxa assets in the second half of 2017.

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Gathering, Processing, and Marketing



	Three Months Ended						Six Months Ended
	June 30,						June 30,
millions except percentages	2018		Inc (Dec) vs. 2017		2017		2018		Inc (Dec) vs. 2017		2017
Gathering, processing, and marketing sales ⁽¹⁾	$	382	(18	)%	$	464	$	742	(18	)%	$	908
Gathering, processing, and marketing expense ⁽¹⁾	252		(29	)	355		489		(31	)	705
Gathering, processing, and marketing, net	$	130	19		$	109	$	253	25		$	203

__________________________________________________________________

⁽¹⁾

As a result of adopting ASU 2014-09, Revenue from Contracts with Customers (Topic 606), as of January 1, 2018, gathering, processing, and marketing sales decreased by $268 million for the three months ended June 30, 2018, and $485 million for the six months ended June 30, 2018, and gathering, processing, and marketing expenses decreased by $266 million for the three months ended June 30, 2018, and $480 million for the six months ended June 30, 2018. Refer to Note 2—Revenue from Contracts with Customers in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for further information.

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. The net margin from the sale of NGLs and residue gas for service customers when Anadarko is acting as agent is also included. Gathering and processing expense includes the cost of third-party natural gas purchased and processed by Anadarko as well as other operating and transportation expenses related to the Company’s costs to perform gathering 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 marketing activities.

Total gathering, processing, and marketing, net increased by $21 million for the three months ended June 30, 2018, and by $50 million for the six months ended June 30, 2018, primarily due to increased throughput volumes at the DBM Complex, which were partially due to increased capacity from the 200 MMcf/d cryogenic train that commenced service in December 2017, and increased throughput volumes at the DJ Basin Complex.

Gains (Losses) on Divestitures and Other, net



	Three Months Ended						Six Months Ended
	June 30,						June 30,
millions except percentages	2018		Inc (Dec) vs. 2017		2017		2018		Inc (Dec) vs. 2017		2017
Gains (losses) on divestitures, net	$	52	(75	)%	$	205	$	28	(97	)%	$	1,009
Other	71		(23	)	92		114		(27	)	157
Gains (losses) on divestitures and other, net	$	123	(59	)	$	297	$	142	(88	)	$	1,166

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

During the three and six months ended June 30, 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.

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Costs and Expenses

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



	Three Months Ended				Six Months Ended
	June 30,				June 30,
millions	2018		2017		2018		2017
Oil and gas operating	$	275	$	229	$	551	$	485
Oil and gas transportation	209		229		405		478
Exploration	94		532		262		1,616
Gathering, processing, and marketing ⁽¹⁾	252		355		489		705
G&A	288		244		566		507
DD&A	1,003		1,037		1,993		2,152
Production, property, and other taxes	201		135		391		290
Impairments	128		10		147		383
Other operating expense	22		12		162		34
Total	$	2,472	$	2,783	$	4,966	$	6,650

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

Oil and Gas Operating and Transportation Expenses



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018		Inc (Dec) vs. 2017		2017		2018		Inc (Dec) vs. 2017		2017
Oil and gas operating (millions)	$	275	20	%	$	229	$	551	14	%	$	485
Oil and gas operating—per BOE	4.75		19		3.98		4.76		27		3.76
Oil and gas transportation (millions)	209		(9	)	229		405		(15	)	478
Oil and gas transportation—per BOE	3.61		(10	)	4.00		3.50		(6	)	3.71

Oil and Gas Operating Expense

Oil and gas operating expenses increased by $66 million for the six months ended June 30, 2018, primarily due to the following:


•	higher operating costs of $68 million, primarily related to increased activity in the DJ and Delaware basins, partially offset by lower expenses of $47 million as a result of U.S. onshore asset divestitures


•	higher operating costs of $23 million, primarily related to increased platform maintenance, workovers, and repairs in the Gulf of Mexico

The related costs per BOE increased by $1.00 for the six months ended June 30, 2018, primarily due to increased costs as a result of shifting to a higher-return, oil-levered portfolio that includes the Gulf of Mexico and the DJ and Delaware basins, which operate at a higher cost compared to the divested lower-return, gas-levered assets.

Oil and Gas Transportation Expense

Oil and gas transportation expenses decreased by $73 million for the six months ended June 30, 2018, primarily due to U.S. onshore divestitures. Oil and gas transportation expenses per BOE decreased by $0.21 for the six months ended June 30, 2018, primarily due to divestitures and lower transportation expense per BOE in the Delaware and DJ basins. After significant investment in its midstream infrastructure, the Company has increased the use of its midstream facilities resulting in lower transportation costs for its Delaware and DJ sales volumes.

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Exploration Expense



	Three Months Ended				Six Months Ended
	June 30,				June 30,
millions	2018		2017		2018		2017
Dry hole expense	$	2	$	367	$	55	$	843
Impairments of unproved properties	41		87		94		623
Geological and geophysical, exploration overhead, and other expense	51		78		113		150
Total	$	94	$	532	$	262	$	1,616

Total exploration expense decreased by $438 million for the three months ended June 30, 2018, and $1.4 billion for the six months ended June 30, 2018, primarily related to the following:

Dry Hole Expense

The Company expensed $55 million of exploratory well costs for the six months ended June 30, 2018.

Dry hole expense for the six months ended June 30, 2018, primarily related to the following:


•	$50 million related to unsuccessful drilling activities in the Gulf of Mexico

Dry hole expense for the six months ended June 30, 2017, primarily related to the following:


•	$435 million related to the Shenandoah project in the Gulf of Mexico


•	$241 million related to wells in the Grand Fuerte area in Colombia


•	$119 million related to certain wells in Côte d’Ivoire


•	$48 million primarily related to unsuccessful drilling activities associated with other Gulf of Mexico and international properties

Impairments of Unproved Properties

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

G&A



	Three Months Ended						Six Months Ended
	June 30,						June 30,
millions except percentages	2018		Inc (Dec) vs. 2017		2017		2018		Inc (Dec) vs. 2017		2017
G&A	$	288	18	%	$	244	$	566	12	%	$	507

G&A increased by $44 million for the three months ended June 30, 2018, and $59 million for the six months ended June 30, 2018, primarily due to an increase in the fair value of performance-based unit awards. 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.

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DD&A Expense



	Three Months Ended						Six Months Ended
	June 30,						June 30,
millions except percentages	2018		Inc (Dec) vs. 2017		2017		2018		Inc (Dec) vs. 2017		2017
DD&A	$	1,003	(3	)%	$	1,037	$	1,993	(7	)%	$	2,152

DD&A expense decreased by $159 million for the six months ended June 30, 2018, primarily due to divestitures of U.S. onshore properties in 2018 and 2017 and an increase in proved developed reserves in Ghana.

Impairments



	Three Months Ended				Six Months Ended
	June 30,				June 30,
millions	2018		2017		2018		2017
Impairments	$	128	$	10	$	147	$	383

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
millions except percentages	2018		Inc (Dec) vs. 2017		2017		2018		Inc (Dec) vs. 2017	2017
Other operating expense	$	22	83	%	$	12	$	162	NM	$	34

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

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Other (Income) Expense

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



	Three Months Ended				Six Months Ended
	June 30,				June 30,
millions	2018		2017		2018			2017
Interest expense	$	237	$	229	$	465		$	452
(Gains) losses on derivatives, net ⁽¹⁾	436		32		471			(115		)
Other (income) expense, net	4		44		(8		)	46
Total	$	677	$	305	$	928		$	383

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

Income Tax Expense (Benefit)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
millions except percentages	2018			2017			2018			2017
Income tax expense (benefit)	$	125		$	(38	)	$	251		$	59
Income (loss) before income taxes	142			(372		)	442			(550		)
Effective tax rate	88		%	10		%	57		%	(11		)%

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. If the payment is ultimately determined to not be deductible, the Company would be required to repay the tentative refund previously received plus interest, and the Company would be required to reverse the net benefit of $346 million previously recognized in its financial statements.

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

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LIQUIDITY AND CAPITAL RESOURCES



	Six Months Ended
	June 30,
millions	2018			2017
Net cash provided by (used in) operating activities	$	2,655		$	1,980
Net cash provided by (used in) investing activities	(3,056		)	1,219
Net cash provided by (used in) financing activities	(1,826		)	(372		)

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.

During the six months ended June 30, 2018, Anadarko paid $1.9 billion to repurchase shares under the Share-Repurchase Program and received net proceeds of $384 million from divestitures, primarily related to the sale of the Company’s nonoperated interest in Alaska. As of June 30, 2018, Anadarko had $2.3 billion of cash plus $5.0 billion of borrowing capacity under its APC RCF and 364-Day Facility. 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, its quarterly dividends, the planned debt retirements, and the repurchase of $1.0 billion of the Company’s common stock remaining under the Share-Repurchase Program. 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 was $2.7 billion for the six months ended June 30, 2018, $675 million higher than in the same period of 2017, primarily due to higher sales revenues resulting from higher commodity prices and a higher oil composition of sales volumes.

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Investing Activities

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



	Six Months Ended
	June 30,
millions	2018		2017
Cash Flows from Investing Activities
Additions to properties and equipment ⁽¹⁾	$	3,277	$	2,296
Adjustments for capital expenditures
Changes in capital accruals	211		147
Other	14		22
Total capital expenditures	$	3,502	$	2,465

Exploration and Production and other capital expenditures	$	2,371	$	1,900
WES Midstream capital expenditures	628		437
Other Midstream capital expenditures	503		128

________________________________________________________________________________________


⁽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.

The Company’s capital expenditures increased by $1.0 billion for the six months ended June 30, 2018. Exploration and Production capital expenditures increased primarily due to higher development costs of $741 million driven by increased drilling and completion activity primarily in the DJ and Delaware basins and the Gulf of Mexico. This increase was partially offset by lower exploration costs of $325 million primarily related to decreased exploration drilling in the Gulf of Mexico, Côte d’Ivoire, and Colombia. Other Midstream capital expenditures increased $375 million due to asset development primarily in the Delaware basin. WES Midstream capital expenditures increased $191 million primarily related to the development of assets in the Delaware and DJ basins.

Investments During the six months ended June 30, 2018, the Company made capital contributions of $192 million for equity investments, which are included in other, net under Investing Activities in the Consolidated Statements of Cash Flows. These contributions were primarily associated with joint ventures for pipelines.

Divestitures During the six months ended June 30, 2018, Anadarko received net proceeds of $384 million from divestitures, primarily related to the sale of the Company’s nonoperated interest in Alaska. See Note 4—Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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Financing Activities



	June 30,			December 31,
millions except percentages	2018			2017
Anadarko	$	12,088		$	12,196
WES	4,177			3,465
WGP	28			28
Total debt	$	16,293		$	15,689
Total equity	11,495			13,790
Consolidated debt to total capitalization ratio	58.6		%	53.2		%

Debt Activity

Anadarko Debentures In May 2018, the Company repaid $114 million of 7.050% Debentures at maturity in May 2018.

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 June 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 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 six months ended June 30, 2018, WES borrowed $260 million under its RCF, which was used for general partnership purposes, and made repayments of $630 million. At June 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 June 30, 2018, WGP had outstanding borrowings of $28 million at an interest rate of 4.10% 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 Note 10—Debt in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Debt Maturities At June 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. In addition, WES has a scheduled debt maturity during 2018 of $350 million of 2.600% Senior Notes due August 2018, which was classified as long-term debt on the Company’s Consolidated Balance Sheet at June 30, 2018, as WES has the ability and intent to refinance this obligation using long-term debt.

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

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

Common Stock Dividends Anadarko paid dividends to its common stockholders of $254 million during the six months ended June 30, 2018, and $56 million during the six months ended June 30, 2017. In February 2018, the Company announced an increase to the quarterly dividend to $0.25 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 Owners Distributions to noncontrolling interest owners primarily relate to the following:



	Six Months Ended
	June 30,
millions	2018		2017
WES distributions to unitholders (excluding Anadarko and WGP) ⁽¹⁾	$	186	$	146
WES distributions to Series A Preferred unitholders ⁽²⁾	—		22
WGP distributions to unitholders (excluding Anadarko) ⁽³⁾	45		38

__________________________________________________________________


⁽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 $0.950 per common unit for the second quarter of 2018 (to be paid in August 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 $0.58250 per unit for the second quarter of 2018 (to be paid in August 2018).

RECENT ACCOUNTING DEVELOPMENTS

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

Derivative Instruments Held for Non-Trading Purposes The Company had derivative instruments in place to reduce the price risk associated with future production of 35 MMBbls of oil and 98 Bcf of natural gas at June 30, 2018, with a net derivative liability position of $553 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would increase the net derivative liability by $402 million, while a 10% decrease in underlying commodity prices would decrease the net derivative liability by $367 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 Borrowings, if any, under each of the 364-Day Facility, the APC RCF, the WES RCF, and the WGP RCF are subject to variable interest rates. The balance of Anadarko’s short-term and long-term debt on the Company’s Consolidated Balance Sheets has fixed interest rates. The Company has $2.9 billion of LIBOR-based obligations that are presented on the Company’s Consolidated Balance Sheets net of preferred investments in two noncontrolled entities. These obligations give rise to minimal net interest-rate risk because coupons on the related preferred investments are also LIBOR-based. While a 10% change in LIBOR would not materially impact the Company’s interest cost, it would affect the fair value of outstanding fixed-rate debt.

At June 30, 2018, the Company had a net derivative liability position of $1.2 billion related to interest-rate swaps. A 10% increase (decrease) in the three-month LIBOR interest-rate curve would decrease (increase) the aggregate fair value of outstanding interest-rate swap agreements by $96 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—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (Exchange Act). The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and to ensure that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of June 30, 2018.

Changes in Internal Control over Financial Reporting

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

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

WGR Operating, LP, a wholly owned subsidiary of the Company, is currently in negotiations with the U.S. Environmental Protection Agency (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 will result in a fine or penalty in excess of $100,000.

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

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

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

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—Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q, which is incorporated herein by reference, for a discussion of material legal proceedings to which the Company is a party.

Item 1A. Risk Factors

There have been no material changes from the risk factors included under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

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

The following sets forth information with respect to repurchases by the Company of its shares of common stock during the second quarter of 2018:



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⁾
April 1 - 30, 2018	200,325	$	62.57	—	$	—
May 1 - 31, 2018	9,735	$	66.75	—	$	—
June 1 - 30, 2018 ⁽²⁾	3,020,164	$	65.29	3,016,427	$	—
Total	3,230,224	$	65.12	3,016,427

____________________________________________________________

⁽¹⁾

During the second quarter of 2018, (i) 3.0 million shares were purchased under the Share-Repurchase Program and (ii) 214 thousand shares were purchased 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⁾

In March 2018, the Company entered into an ASR Agreement to repurchase $1.4 billion of the Company’s common stock under the Share-Repurchase Program and received an initial delivery of 19.1 million shares. The Company completed the transaction in June 2018, and received an additional 3.0 million shares. The settlement price was determined by the volume-weighted average price of the shares during the term less a negotiated settlement price adjustment. 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.


⁽³⁾	The 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 Share-Repurchase Program was further expanded to $4.0 billion and extended through June 30, 2019, resulting in $1.0 billion of common stock authorized for repurchase as of the date of this filing.

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Item 6. Exhibits

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



Exhibit Number			Description
	3	(i)	Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated May 21, 2009, filed as Exhibit 3.3 to Form 8-K filed on May 22, 2009
		(ii)	By-Laws of Anadarko Petroleum Corporation, amended and restated as of November 14, 2017, filed as Exhibit 3.1 to Form 8-K filed on November 16, 2017
*	10	(i)	Form of Director Annual Deferred Shares Award Letter for Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as Amended and Restated Effective as of May 10, 2016
*	31	(i)	Rule 13a-14(a)/15d-14(a) Certification—Chief Executive Officer
*	31	(ii)	Rule 13a-14(a)/15d-14(a) Certification—Chief Financial Officer
**	32		Section 1350 Certifications
*	101	.INS	XBRL Instance Document
*	101	.SCH	XBRL Schema Document
*	101	.CAL	XBRL Calculation Linkbase Document
*	101	.DEF	XBRL Definition Linkbase Document
*	101	.LAB	XBRL Label Linkbase Document
*	101	.PRE	XBRL Presentation Linkbase Document

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SIGNATURES

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



		ANADARKO PETROLEUM CORPORATION
		(Registrant)

July 31, 2018	By:	/s/ ROBERT G. GWIN
		Robert G. Gwin Executive Vice President, Finance and Chief Financial Officer