Quarterly Report (10-q)

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, 2015

[ ] 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)

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 ý No ¨

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

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

Large accelerated filer ý Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨

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

The number of shares outstanding of the Company’s common stock at June 30, 2015, is shown below:



Title of Class		Number of Shares Outstanding
Common Stock, par value $0.10 per share		508,012,188

TABLE OF CONTENTS




PART I		Page
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three and Six Months Ended June 30, 2015 and 2014	2
	Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2015 and 2014	3
	Consolidated Balance Sheets at June 30, 2015, and December 31, 2014	4
	Consolidated Statement of Equity for the Six Months Ended June 30, 2015	5
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2015 and 2014	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 4.	Controls and Procedures	49
PART II
Item 1.	Legal Proceedings	50
Item 1A.	Risk Factors	50
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 6.	Exhibits	51

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)



	Three Months Ended June 30,							Six Months Ended June 30,
millions except per-share amounts	2015			2014				2015				2014
Revenues and Other
Natural-gas sales	$	487		$	991			$	1,128			$	2,208
Oil and condensate sales	1,616			2,705				3,035				5,129
Natural-gas liquids sales	229			411				461				797
Gathering, processing, and marketing sales	305			278				598				589
Gains (losses) on divestitures and other, net	(1		)	54				(265		)		1,560
Total	2,636			4,439				4,957				10,283
Costs and Expenses
Oil and gas operating	226			273			522				586
Oil and gas transportation and other	289			281				650				547
Exploration	103			502				1,186				801
Gathering, processing, and marketing	255			250				509				502
General and administrative	278			305				588				603
Depreciation, depletion, and amortization	1,214			1,048				2,470				2,172
Other taxes	151			361				333				675
Impairments	30			117				2,813				120
Deepwater Horizon settlement and related costs	—			93				4				93
Total	2,546			3,230				9,075				6,099
Operating Income (Loss)	90			1,209				(4,118		)		4,184
Other (Income) Expense
Interest expense	201			186				417				369
(Gains) losses on derivatives, net	(311		)	323				(159		)		776
Other (income) expense, net	15			(13		)		62				(12		)
Tronox-related contingent loss	—			19				5				4,319
Total	(95		)	515				325				5,452
Income (Loss) Before Income Taxes	185			694				(4,443		)		(1,268		)
Income tax expense (benefit)	77			428				(1,315		)		1,092
Net Income (Loss)	108			266				(3,128		)		(2,360		)
Net income attributable to noncontrolling interests	47			39				79				82
Net Income (Loss) Attributable to Common Stockholders	$	61		$	227			$	(3,207	)		$	(2,442	)

Per Common Share
Net income (loss) attributable to common stockholders—basic	$	0.12		$	0.45			$	(6.32	)		$	(4.84	)
Net income (loss) attributable to common stockholders—diluted	$	0.12		$	0.45			$	(6.32	)		$	(4.84	)
Average Number of Common Shares Outstanding—Basic	508			505				507				505
Average Number of Common Shares Outstanding—Diluted	509			507				507				505
Dividends (per common share)	$	0.27		$	0.27			$	0.54			$	0.45

See accompanying Notes to Consolidated Financial Statements.

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
millions	2015			2014			2015			2014
Net Income (Loss)	$	108		$	266		$	(3,128	)	$	(2,360	)
Other Comprehensive Income (Loss)
Adjustments for derivative instruments
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	3			3			5			5
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	(1		)	(1		)	(2		)	(2		)
Total adjustments for derivative instruments, net of taxes	2			2			3			3
Adjustments for pension and other postretirement plans
Amortization of net actuarial (gain) loss to general and administrative expense	13			7			26			14
Income taxes on amortization of net actuarial (gain) loss to general and administrative expense	(5		)	(3		)	(9		)	(5		)
Amortization of net prior service (credit) cost to general and administrative expense	1			—			1			—
Total adjustments for pension and other postretirement plans, net of taxes	9			4			18			9
Total	11			6			21			12
Comprehensive Income (Loss)	119			272			(3,107		)	(2,348		)
Comprehensive income attributable to noncontrolling interests	47			39			79			82
Comprehensive Income (Loss) Attributable to Common Stockholders	$	72		$	233		$	(3,186	)	$	(2,430	)

See accompanying Notes to Consolidated Financial Statements.

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)



millions	June 30, 2015			December 31, 2014
ASSETS
Current Assets
Cash and cash equivalents	$	2,173		$	7,369
Accounts receivable (net of allowance of $6 million and $7 million)
Customers	1,028			1,118
Others	1,574			1,409
Other current assets	635			1,325
Total	5,410			11,221
Properties and Equipment
Cost	75,608			75,107
Less accumulated depreciation, depletion, and amortization	37,788			33,518
Net properties and equipment	37,820			41,589
Other Assets	2,474			2,310
Goodwill and Other Intangible Assets	6,420			6,569
Total Assets	$	52,124		$	61,689

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	3,034		$	3,683
Current asset retirement obligations	267			257
Accrued expenses	1,244			994
Short-term debt	33			—
Deepwater Horizon settlement and related costs	91			90
Tronox-related contingent liability	—			5,210
Total	4,669			10,234
Long-term Debt	16,025			15,092
Other Long-term Liabilities
Deferred income taxes	7,594			9,249
Asset retirement obligations	1,714			1,796
Other	2,763			3,000
Total	12,071			14,045

Equity
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 527.7 million and 525.9 million shares issued)	52			52
Paid-in capital	9,169			9,005
Retained earnings	8,641			12,125
Treasury stock (19.7 million and 19.3 million shares)	(977		)	(940		)
Accumulated other comprehensive income (loss)	(496		)	(517		)
Total Stockholders’ Equity	16,389			19,725
Noncontrolling interests	2,970			2,593
Total Equity	19,359			22,318
Total Liabilities and Equity	$	52,124		$	61,689

See accompanying Notes to Consolidated Financial Statements.

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)



	Total Stockholders’ Equity
	Common Stock		Paid-in Capital		Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Non- controlling Interests			Total Equity
millions
Balance at December 31, 2014	$	52	$	9,005	$	12,125		$	(940	)	$	(517	)	$	2,593		$	22,318
Net income (loss)	—		—		(3,207		)	—			—			79			(3,128		)
Common stock issued	—		105		—			—			—			—			105
Dividends—common stock	—		—		(277		)	—			—			—			(277		)
Repurchase of common stock	—		—		—			(37		)	—			—			(37		)
Subsidiary equity transactions	—		59		—			—			—			85			144
Issuance of tangible equity units	—		—		—			—			—			348			348
Distributions to noncontrolling interest owners	—		—		—			—			—			(135		)	(135		)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	—		—		—			—			3			—			3
Adjustments for pension and other postretirement plans	—		—		—			—			18			—			18
Balance at June 30, 2015	$	52	$	9,169	$	8,641		$	(977	)	$	(496	)	$	2,970		$	19,359

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	2015			2014
Cash Flows from Operating Activities
Net income (loss)	$	(3,128	)	$	(2,360	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	2,470			2,172
Deferred income taxes	(1,187		)	188
Dry hole expense and impairments of unproved properties	1,040			609
Impairments	2,813			120
(Gains) losses on divestitures, net	425			(1,468		)
Total (gains) losses on derivatives, net	(158		)	786
Operating portion of net cash received (paid) in settlement of derivative instruments	172			(186		)
Other	74			108
Changes in assets and liabilities
Deepwater Horizon settlement and related costs	1			92
Tronox-related contingent liability	(5,210		)	4,319
(Increase) decrease in accounts receivable	(105		)	(183		)
Increase (decrease) in accounts payable and accrued expenses	(199		)	21
Other items—net	(269		)	(27		)
Net cash provided by (used in) operating activities	(3,261		)	4,191
Cash Flows from Investing Activities
Additions to properties and equipment and dry hole costs	(3,501		)	(5,100		)
Acquisition of businesses	(3		)	(4		)
Divestitures of properties and equipment and other assets	700			3,286
Other—net	19			(282		)
Net cash provided by (used in) investing activities	(2,785		)	(2,100		)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	4,787			1,077
Repayments of debt	(3,857		)	(1,255		)
Financing portion of net cash received (paid) for derivative instruments	(77		)	(222		)
Increase (decrease) in outstanding checks	(109		)	178
Dividends paid	(277		)	(230		)
Repurchase of common stock	(37		)	(35		)
Issuance of common stock, including tax benefit on share-based compensation awards	19			73
Sale of subsidiary units	187			92
Issuance of tangible equity units — equity component	348			—
Distributions to noncontrolling interest owners	(135		)	(102		)
Net cash provided by (used in) financing activities	849			(424		)
Effect of Exchange Rate Changes on Cash	1			—
Net Increase (Decrease) in Cash and Cash Equivalents	(5,196		)	1,667
Cash and Cash Equivalents at Beginning of Period	7,369			3,698
Cash and Cash Equivalents at End of Period	$	2,173		$	5,365

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 marketing of natural gas, oil, condensate, natural gas liquids (NGLs), and the anticipated production of liquefied natural gas (LNG). In addition, the Company engages in the gathering, processing, treating, and transporting of natural gas, oil, and NGLs. The Company also participates in the hard-minerals business through royalty arrangements. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

Basis of Presentation The information furnished herein reflects 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.

Use of Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States requires management to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to proved reserves; the value of properties and equipment; goodwill; intangible assets; asset retirement obligations; litigation liabilities; environmental liabilities; pension assets, liabilities, and costs; income taxes; and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Recently Issued Accounting Standards The Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2015-03, Interest—Imputation of Interest (Subtopic 853-30)—Simplifying the Presentation of Debt Issuance Costs. This ASU will simplify the presentation of debt issuance costs by requiring such costs to be presented in the balance sheet as a reduction from the corresponding debt liability rather than as an asset. This ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective approach, with early adoption permitted. The Company does not expect the adoption to have a material impact on its consolidated financial statements.

The FASB issued ASU 2015-02, Consolidation—Amendments to the Consolidation Analysis. This ASU will simplify existing requirements by reducing the number of acceptable consolidation models and placing more emphasis on risk of loss when determining a controlling financial interest. The provisions will affect how limited partnerships and similar entities are assessed for consolidation, including the elimination of the presumption that a general partner should consolidate a limited partnership. This ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective or modified retrospective approach, with early adoption permitted. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements.

The FASB issued ASU 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition, and 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. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using one of two retrospective application methods, with early adoption permitted in 2017. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Acquisitions, Divestitures, and Assets Held for Sale

Acquisitions In November 2014, Western Gas Partners, LP (WES), a publicly traded consolidated subsidiary, acquired Nuevo Midstream, LLC (Nuevo) for $1.554 billion. Following the acquisition, WES changed the name of Nuevo to Delaware Basin Midstream, LLC (DBM). The acquisition constitutes a business combination and was accounted for using the acquisition method of accounting. The fair-value measurements of the assets acquired and liabilities assumed at the acquisition date were preliminary as of June 30, 2015, pending final review of certain support related to the acquired entity’s assets and liabilities. There were no material changes to the fair value of assets acquired and liabilities assumed from the amounts included on the Company’s Consolidated Balance Sheet at December 31, 2014.

Divestitures and Assets Held for Sale For the six months ended June 30, 2015, the Company received $700 million in proceeds from divestitures and recognized net losses of $425 million primarily related to assets that were included in the oil and gas exploration and production reporting segment. The sale of certain enhanced oil recovery (EOR) assets in the Rocky Mountains Region (Rockies), with an original sales price of $703 million, closed in April 2015 for net proceeds of $686 million after closing adjustments. During the first quarter of 2015, these EOR assets satisfied criteria to be considered held for sale. These assets were remeasured to their then-current fair value using a market approach and Level 2 fair-value measurement, and the Company recognized a loss of $340 million.

During the second quarter of 2015, certain U.S. onshore oil and gas exploration and production properties and related midstream assets in East Texas satisfied criteria to be considered held for sale. These assets were remeasured to their fair value using a market approach and Level 2 fair-value measurement, and the Company recognized a loss of $97 million. Gains and losses on assets held for sale are included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income. The sale of these assets is expected to close in the third quarter of 2015 for a sales price of $440 million, subject to closing adjustments. At June 30, 2015, the Company’s Consolidated Balance Sheet included long-term assets of $440 million associated with assets held for sale.

3. Inventories

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



millions	June 30, 2015		December 31, 2014
Oil	$	111	$	133
Natural gas	30		27
NGLs	62		83
Total inventories	$	203	$	243

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

4. Impairments

The following summarizes impairments of proved properties and the related post-impairment fair values by segment:



	Three Months Ended				Six Months Ended
millions	Impairment		Fair Value⁽¹⁾		Impairment		Fair Value⁽¹⁾
June 30, 2015
Oil and gas exploration and production
Long-lived assets held for use
U.S. onshore properties	$	4	$	12	$	2,303	$	1,303
Gulf of Mexico properties	17		—		25		—
Cost-method investment ⁽²⁾	1		32		1		32
Midstream
Long-lived assets held for use	8		199		484		202
Total	$	30	$	243	$	2,813	$	1,537

June 30, 2014
Oil and gas exploration and production
Long-lived assets held for use
Gulf of Mexico properties	$	115	$	327	$	115	$	327
Cost-method investment ⁽²⁾	1		32		2		32
Midstream
Long-lived assets held for use	1		—		3		—
Total	$	117	$	359	$	120	$	359

__________________________________________________________________


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


⁽²⁾	Represents the after-tax net investment.

Impairments during the six months ended June 30, 2015, were primarily related to the Company’s Greater Natural Buttes oil and gas and midstream properties in the Rockies, which were impaired due to lower commodity prices. Impairments of proved properties are included in impairment expense in the Company’s Consolidated Statements of Income. During the second quarter of 2014, the Company impaired a Gulf of Mexico property due to a reduction in estimated future cash flows.

In addition to the proved property impairments above, the Company also recognized a $935 million impairment of unproved Greater Natural Buttes properties during the six months ended June 30, 2015, as a result of lower commodity prices. Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

5. Suspended Exploratory Well Costs

The Company’s suspended exploratory well costs were $1.7 billion at June 30, 2015, and $1.5 billion at December 31, 2014. The increase in suspended exploratory well costs during 2015 is primarily related to the capitalization of costs associated with exploration drilling in the Gulf of Mexico and Mozambique. Projects with suspended exploratory well costs are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development and where management is actively pursuing efforts to assess whether reserves can be attributed to these projects. 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, 2015, no exploratory well costs previously capitalized as suspended exploratory well costs for greater than one year at December 31, 2014, were charged to dry hole expense.

6. 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 Henry Hub, Louisiana, for natural gas and Cushing, Oklahoma, or Sullom Voe, Scotland, for oil. Basis swaps are periodically used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities (Marketing and Trading Derivative Activities).

Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to interest-rate changes. The fair value of the Company’s current interest-rate swap portfolio increases (decreases) when interest rates increase (decrease).

The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized currently in earnings. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings. See Note 10—Accumulated Other Comprehensive Income (Loss).

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6. Derivative Instruments (Continued)

Oil and Natural-Gas Production/Processing Derivative Activities The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The crude-oil prices listed below are a combination of NYMEX West Texas Intermediate and Intercontinental Exchange, Inc. (ICE) Brent Blend 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, 2015:



	2015 Settlement		2016 Settlement
Natural Gas
Three-Way Collars (thousand MMBtu/d)	635		—
Average price per MMBtu
Ceiling sold price (call)	$	4.76	$	—
Floor purchased price (put)	$	3.75	$	—
Floor sold price (put)	$	2.75	$	—
Fixed-Price Contracts (thousand MMBtu/d)	7		28
Average price per MMBtu	$	2.56	$	3.22
Extendable Fixed-Price Contracts (thousand MMBtu/d)⁽¹⁾	170		—
Average price per MMBtu	$	4.17	$	—
Oil
Three-Way Collars (MBbls/d)	—		28
Average price per barrel
Ceiling sold price (call)	$	—	$	69.29
Floor purchased price (put)	$	—	$	61.43
Floor sold price (put)	$	—	$	46.43

__________________________________________________________________


⁽¹⁾	The extendable fixed-price contracts have a contract term of January 2015 to December 2015 with an option for the counterparty to extend the contract term to December 2016 at the same price.

MMBtu—million British thermal units

MMBtu/d—million British thermal units per day

MBbls/d—thousand barrels per day

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

Marketing and Trading Derivative Activities The Company had financial derivative transactions with notional volumes of natural gas totaling 6 billion cubic feet at June 30, 2015 and December 31, 2014, that were entered into to mitigate commodity-price risk related to fixed-price purchase and sales contracts and storage activity.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6. Derivative Instruments (Continued)

Interest-Rate Derivatives Anadarko has outstanding interest-rate swap contracts to manage interest-rate risk associated with anticipated debt issuances. The Company has locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month London Interbank Offered Rate (LIBOR). These swap instruments currently include a provision that requires both the termination of the swaps and cash settlement in full at the start of the reference period.

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 or collateralization related to these extended interest-rate derivatives are classified as cash flows from financing activities.

The Company had the following outstanding interest-rate swaps at June 30, 2015:



millions except percentages		Reference Period		Weighted-Average
Notional Principal Amount		Start	End	Interest Rate
$	50	September 2016	September 2026	5.91%
$	1,850	September 2016	September 2046	6.06%

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	2015		2014		2015			2014
Commodity derivatives
Other current assets	$	238	$	421	$	(73	)	$	(118	)
Other assets	5		1		—			—
Accrued expenses	60		71		(89		)	(114		)
Other liabilities	34		—		(40		)	(6		)
	337		493		(202		)	(238		)
Interest-rate derivatives
Other liabilities	—		—		(1,110		)	(1,217		)
Total derivatives	$	337	$	493	$	(1,312	)	$	(1,455	)

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



millions	Three Months Ended June 30,					Six Months Ended June 30,
Classification of (Gain) Loss Recognized	2015			2014		2015			2014
Commodity derivatives
Gathering, processing, and marketing sales ⁽¹⁾	$	1		$	2	$	1		$	10
(Gains) losses on derivatives, net	1			164		(52		)	379
Interest-rate derivatives
(Gains) losses on derivatives, net	(312		)	159		(107		)	397
Total (gains) losses on derivatives, net	$	(310	)	$	325	$	(158	)	$	786

__________________________________________________________________


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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6. 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 fair value of its counterparties’ creditworthiness. The Company has the ability to require cash collateral or letters of credit to mitigate its credit-risk exposure.

The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities, and routinely exercises its contractual right to offset gains and losses when settling with derivative counterparties. In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and provide for contract termination and net settlement across derivative types. At June 30, 2015, $198 million of the Company’s $1.312 billion gross derivative liability balance, and at December 31, 2014, $289 million of the Company’s $1.455 billion gross derivative liability balance, would have been eligible for setoff against the Company’s gross derivative asset balance in the event of default. Other than in the event of default, the Company does not net settle across derivative types.

The Company’s derivative instruments are subject to individually negotiated credit provisions that may require collateral of cash or letters of credit depending on the derivative’s valuation versus negotiated credit thresholds. These credit thresholds may also require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered, such as if the Company’s credit rating from major credit rating agencies declines to below investment grade. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $976 million (net of collateral) at June 30, 2015, and $97 million (net of collateral) at December 31, 2014. The increase is primarily a result of derivative counterparties no longer maintaining secured positions under the Company’s credit facilities and, therefore, the derivative instruments are now subject to credit-risk-related provisions. For information on the Company’s revolving credit facilities, see Note 8—Debt and Interest Expense—Anadarko Revolving Credit Facilities and Commercial Paper Program.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6. Derivative Instruments (Continued)

Fair Value 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
June 30, 2015	Level 1		Level 2			Level 3		Netting ⁽¹⁾			Collateral			Total
Assets
Commodity derivatives
Financial institutions	$	—	$	314		$	—	$	(163	)	$	(3	)	$	148
Other counterparties	—		23			—		(4		)	—			19
Total derivative assets	$	—	$	337		$	—	$	(167	)	$	(3	)	$	167
Liabilities
Commodity derivatives
Financial institutions	$	—	$	(192	)	$	—	$	163		$	—		$	(29	)
Other counterparties	—		(10		)	—		4			—			(6		)
Interest-rate derivatives	—		(1,110		)	—		—			100			(1,010		)
Total derivative liabilities	$	—	$	(1,312	)	$	—	$	167		$	100		$	(1,045	)

December 31, 2014
Assets
Commodity derivatives
Financial institutions	$	—	$	471		$	—	$	(187	)	$	(13	)	$	271
Other counterparties	—		22			—		(2		)	—			20
Total derivative assets	$	—	$	493		$	—	$	(189	)	$	(13	)	$	291
Liabilities
Commodity derivatives
Financial institutions	$	—	$	(234	)	$	—	$	187		$	—		$	(47	)
Other counterparties	—		(4		)	—		2			—			(2		)
Interest-rate derivatives	—		(1,217		)	—		—			23			(1,194		)
Total derivative liabilities	$	—	$	(1,455	)	$	—	$	189		$	23		$	(1,243	)

__________________________________________________________________


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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Tangible Equity Units

In June 2015, the Company issued 9.2 million 7.50% tangible equity units (TEUs) at a stated amount of $50.00 per TEU, raising net proceeds of $446 million. Each TEU is comprised of a prepaid equity purchase contract for common units of Western Gas Equity Partners, LP (WGP), a publicly traded consolidated subsidiary, and a senior amortizing note. Subsequent to issuance, each TEU may be legally separated into the two components. The prepaid equity purchase contract is considered a freestanding financial instrument, indexed to WGP common units, and meets the conditions for equity classification.

Anadarko allocated the proceeds from the issuance of the TEUs to equity and debt based on the relative fair values of their respective components as follows:



millions, except price per TEU	Equity Component		Debt Component		Total
Price per TEU	$	39.05	$	10.95	$	50.00
Gross proceeds	359		101		460
Less issuance costs	11		3		14
Net proceeds	$	348	$	98	$	446

The prepaid equity purchase contracts were recorded in noncontrolling interests, net of issuance costs, and the senior amortizing notes were recorded in short-term debt and long-term debt on the Company’s Consolidated Balance Sheet.

Equity Component Unless settled earlier at the holder’s option, each purchase contract has a mandatory settlement date of June 7, 2018. Anadarko has a right to elect to issue and deliver shares of Anadarko Petroleum Corporation common stock (APC shares) in lieu of delivering WGP common units at settlement. The Company will deliver WGP common units (or APC shares) on the settlement date at the settlement rate based upon the applicable market value of WGP common units (or APC shares) as follows:



	Settlement Rate per Purchase Contract
Applicable Market Value of WGP Common Units ⁽¹⁾	WGP Common Units	APC Shares (if elected)⁽¹⁾
Exceeds $69.8422 (Threshold Appreciation Price)	0.7159 units (Minimum Settlement Rate)	a number of shares equal to (a) the Minimum Settlement Rate, multiplied by the applicable market value of WGP common units, divided by (b) 98% of the applicable market value of APC shares
Less than or equal to the Threshold Appreciation Price, but greater than or equal to $58.20 (Reference Price)	a number of units equal to $50.00, divided by the applicable market value of WGP common units	a number of shares equal to $50.00, divided by 98% of the applicable market value of APC shares
Less than the Reference Price	0.8591 units (Maximum Settlement Rate)	a number of shares equal to (a) the Maximum Settlement Rate, multiplied by the applicable market value of WGP common units, divided by (b) 98% of the applicable market value of APC shares

__________________________________________________________________


⁽¹⁾	The applicable market value is the average of the daily volume-weighted average prices of WGP common units (or APC shares) for the 20 consecutive trading days beginning on, and including, the 23^rd scheduled trading day immediately preceding June 7, 2018.

The WGP common units underlying the purchase contract are currently issued and outstanding, and are owned by a wholly owned subsidiary of Anadarko. In the event Anadarko elects to settle in APC shares, the number of such shares issued and delivered upon settlement of each purchase contract is subject to adjustment and cannot exceed four shares under any circumstance (APC share cap). The above fixed settlement rates for WGP common units and the APC share cap are subject to adjustment upon the occurrence of certain specified dilutive events.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Tangible Equity Units (Continued)

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

8. Debt and Interest Expense

Debt The Company’s outstanding debt, excluding the capital lease obligation, is senior unsecured. The following summarizes the Company’s outstanding debt:



millions	June 30, 2015			December 31, 2014
Total debt at face value	$	17,640		$	16,687
Net unamortized discounts and premiums ⁽¹⁾	(1,603		)	(1,616		)
Total borrowings	16,037			15,071
Capital lease obligation	21			21
Less short-term debt	33			—
Total long-term debt⁽²⁾	$	16,025		$	15,092

__________________________________________________________________


⁽¹⁾	Unamortized discounts and premiums are amortized over the term of the related debt.


⁽²⁾	Includes WES debt of $2.7 billion at June 30, 2015, and $2.4 billion at December 31, 2014.

Anadarko’s Zero-Coupon Senior Notes due 2036 (Zero Coupons) can be put to the Company in October of each year, in whole or in part, for the then-accreted value, which will be $796 million at the next put date in October 2015. Anadarko’s Zero Coupons are classified as long-term debt on the Company’s Consolidated Balance Sheets, as the Company has the ability and intent to refinance these obligations using long-term debt.

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 variable interest rates are reflective of market rates. The estimated fair value of the Company’s total borrowings was $17.9 billion at June 30, 2015, and $17.4 billion at December 31, 2014.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Debt and Interest Expense (Continued)

Debt Activity The following summarizes the Company’s debt activity during the six months ended June 30, 2015:



	Carrying
millions	Value			Description
Balance at December 31, 2014	$	15,071
Issuances	494			WES 3.950% Senior Notes due 2025
	101			Tangible Equity Units - senior amortizing notes
Borrowings	1,500			$5.0 billion revolving credit facility
	1,800			364-Day Facility
	280			WES revolving credit facility
	592			Commercial paper notes, net ⁽¹⁾
Repayments	(1,500		)	$5.0 billion revolving credit facility
	(1,800		)	364-Day Facility
	(520		)	WES revolving credit facility
Other, net	19			Amortization of debt discounts and premiums
Balance at June 30, 2015	$	16,037

__________________________________________________________________


⁽¹⁾	Includes repayments of $37 million related to commercial paper notes with maturities greater than 90 days.

Anadarko Revolving Credit Facilities and Commercial Paper Program In January 2015, upon satisfaction of certain conditions, including the settlement payment related to the Tronox Adversary Proceeding, the Company’s $5.0 billion senior secured revolving credit facility was replaced by a $3.0 billion five-year senior unsecured revolving credit facility (Five-Year Facility), which is expandable to $4.0 billion, and a $2.0 billion 364-day senior unsecured revolving credit facility (364-Day Facility). For additional information, see Note 12—Contingencies—Tronox Litigation.

Borrowings under the Five-Year and 364-Day Facilities generally bear interest under one of two rate options, at Anadarko’s election, using either LIBOR (or Euro Interbank Offered Rate in the case of borrowings under the Five-Year Facility denominated in Euro) or an alternate base rate, in each case plus an applicable margin ranging from 0.00% to 1.65% for the Five-Year Facility and 0.00% to 1.675% for the 364-Day Facility. The applicable margin will vary depending on Anadarko’s credit ratings.

The Five-Year and 364-Day Facilities contain certain customary affirmative and negative covenants, including a financial covenant requiring maintenance of a consolidated indebtedness to total capitalization ratio of no greater than 65% and limitations on certain secured indebtedness, sale-and-leaseback transactions, and mergers and other fundamental changes. At June 30, 2015, the Company had no outstanding borrowings under the Five-Year and 364-Day Facilities and was in compliance with all covenants contained therein.

During the first quarter of 2015, the Company initiated a commercial paper program, which allows a maximum of $3.0 billion of unsecured commercial paper notes and is supported by the Company’s Five-Year Facility. The maturities of the commercial paper notes vary, but may not exceed 397 days. The commercial paper notes are sold under customary terms in the commercial paper market and are issued either at a discounted price to their principal face value or will bear interest at varying interest rates on a fixed or floating basis. Such discounted price or interest amounts are dependent on market conditions and the ratings assigned to the commercial paper program by credit rating agencies at the time of issuance of the commercial paper notes. At June 30, 2015, the Company had $592 million of commercial paper notes outstanding at a weighted-average interest rate of 0.51%. Anadarko classified the outstanding commercial paper notes as long-term debt on the Company’s Consolidated Balance Sheet, as the Company currently intends to refinance these obligations at maturity with additional commercial paper notes supported by Anadarko’s Five-Year Facility.

WES Borrowings During the second quarter of 2015, WES completed a public offering of $500 million aggregate principal amount of 3.950% Senior Notes due 2025. At June 30, 2015, WES was in compliance with all covenants contained in its five-year $1.2 billion senior unsecured revolving credit facility maturing in February 2019 (RCF), which is expandable to $1.5 billion. At June 30, 2015, WES had outstanding borrowings under its RCF of $270 million at an interest rate of 1.49%, had outstanding letters of credit of $13 million, and had available borrowing capacity of $917 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Debt and Interest Expense (Continued)

Interest Expense The following summarizes interest expense:



	Three Months Ended June 30,						Six Months Ended June 30,
millions	2015			2014			2015			2014
Debt and other	$	244		$	233		$	498		$	473
Capitalized interest	(43		)	(47		)	(81		)	(104		)
Total interest expense	$	201		$	186		$	417		$	369

9. Stockholders’ Equity

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 earnings per share attributable to common stockholders:



	Three Months Ended June 30,				Six Months Ended June 30,
millions except per-share amounts	2015		2014		2015			2014
Net income (loss)
Net income (loss) attributable to common stockholders	$	61	$	227	$	(3,207	)	$	(2,442	)
Less distributions on participating securities	1		1		2			1
Basic	$	60	$	226	$	(3,209	)	$	(2,443	)
Diluted	$	60	$	226	$	(3,209	)	$	(2,443	)
Shares
Average number of common shares outstanding—basic	508		505		507			505
Dilutive effect of stock options	1		2		—			—
Average number of common shares outstanding—diluted	509		507		507			505
Excluded due to anti-dilutive effect	6		4		11			11
Net income (loss) per common share
Basic	$	0.12	$	0.45	$	(6.32	)	$	(4.84	)
Diluted	$	0.12	$	0.45	$	(6.32	)	$	(4.84	)

10. Accumulated Other Comprehensive Income (Loss)

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



millions	Interest-rate Derivatives Previously Subject to Hedge Accounting			Pension and Other Postretirement Plans			Total
Balance at December 31, 2014	$	(48	)	$	(469	)	$	(517	)
Reclassifications to Consolidated Statement of Income	3			18			21
Balance at June 30, 2015	$	(45	)	$	(451	)	$	(496	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Noncontrolling Interests

WGP, a publicly traded consolidated subsidiary, is a limited partnership that owns interests in WES. During the three months ended June 30, 2015, Anadarko sold 2.3 million WGP common units to the public, raising net proceeds of $130 million. At June 30, 2015, Anadarko’s ownership interest in WGP consisted of an 87.3% limited partner interest and the entire non-economic general partner interest. The remaining 12.7% limited partner interest in WGP was owned by the public. In June 2015, Anadarko issued 9.2 million TEUs, which include an equity component that may be settled in WGP common units. For additional disclosure of the TEU effect on noncontrolling interests, see Note 7—Tangible Equity Units.

WES, a publicly traded consolidated subsidiary, is a limited partnership that acquires, owns, develops, and operates midstream assets. During the six months ended June 30, 2015, WES issued 874 thousand common units to the public under its continuous offering program, raising net proceeds of $57 million. In 2014, WES issued 11 million Class C units to Anadarko to partially fund the acquisition of DBM. These Class C units receive distributions in the form of additional Class C units until conversion into common units at the end of 2017 unless WES elects to convert the units earlier or Anadarko extends the conversion date. During the six months ended June 30, 2015, WES distributed 164 thousand Class C units to Anadarko. At June 30, 2015, WGP’s ownership interest in WES consisted of a 34.7% limited partner interest, the entire 1.8% general partner interest, and all of the WES incentive distribution rights. At June 30, 2015, Anadarko also owned an 8.3% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 55.2% limited partner interest in WES was owned by the public.

12. Contingencies

Litigation The following is a discussion of any material developments in previously reported contingencies and 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, 2014.

Tronox Litigation On April 3, 2014, Anadarko and Kerr-McGee Corporation and certain of its subsidiaries entered into a settlement agreement to resolve all claims asserted by Tronox Incorporated (Tronox) and certain of its affiliates, including claims for actual and constructive fraudulent conveyance (Adversary Proceeding), for $5.15 billion. In addition, the Company agreed to pay interest on that amount from April 3, 2014, through the payment of the settlement. In January 2015, the Company paid $5.2 billion after the settlement agreement became effective. For additional disclosure of the Tronox Adversary Proceeding, see Note 17—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

Anadarko recognized Tronox-related contingent losses of $850 million in the fourth quarter of 2013 and $4.3 billion in the first quarter of 2014. In addition, Anadarko recognized settlement-related interest expense, included in Tronox-related contingent loss in the Company’s Consolidated Statement of Income, of $60 million during the year ended December 31, 2014, and $5 million during the first quarter of 2015. For information on the tax effects of the settlement agreement, see Note 13—Income Taxes.

Deepwater Horizon Events In April 2010, the Macondo well in the Gulf of Mexico blew out and an explosion occurred on the Deepwater Horizon drilling rig, resulting in an oil spill. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% nonoperated interest. In October 2011, the Company and BP entered into a settlement agreement relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company is fully indemnified by BP against all claims and damages arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and assessment costs, and any claims arising under the Operating Agreement with BP. This indemnification is guaranteed by BP Corporation North America Inc. (BPCNA) and, in the event that the net worth of BPCNA declines below an agreed-upon amount, BP p.l.c. has agreed to become the sole guarantor. Under the Settlement Agreement, BP does not indemnify the Company against penalties and fines, punitive damages, shareholder derivative or securities laws claims, or certain other claims. The Company has not recorded a liability for any costs that are subject to indemnification by BP. For additional disclosure of the Deepwater Horizon events, the Company’s Settlement Agreement with BP, environmental claims under OPA, NRD claims, potential penalties and fines, and civil litigation, see Note 17—Contingencies—Deepwater Horizon Events in the Notes to Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. Contingencies (Continued)

Penalties and Fines In December 2010, the U.S. Department of Justice (DOJ), on behalf of the United States, filed a civil lawsuit in the U.S. District Court for the Eastern District of Louisiana in New Orleans, Louisiana (Louisiana District Court) against several parties, including the Company, seeking an assessment of civil penalties under the Clean Water Act (CWA) in an amount to be determined by the Louisiana District Court. In February 2012, the Louisiana District Court entered a declaratory judgment that, as a partial owner of the Macondo well, Anadarko is liable for civil penalties under Section 311 of the CWA. The declaratory judgment was affirmed in June 2014 by the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit). In March 2015, Anadarko filed a petition for a writ of certiorari with the U.S. Supreme Court appealing the Fifth Circuit’s decision, which was denied in June 2015. The declaratory judgment addresses liability only, and does not address the amount of any civil penalty. The assessment of a civil penalty against Anadarko will be determined by the Louisiana District Court upon its ruling in the penalty phase of trial discussed below under Civil Litigation Damage Claims.

Applicable accounting guidance requires the Company to accrue a liability if it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. The Louisiana District Court’s declaratory judgment in February 2012 satisfies the requirement that a liability arising from the future assessment of a civil penalty against Anadarko is probable. In an effort to resolve this matter, the Company made a settlement offer to the DOJ in July 2014 of $90 million and recorded a contingent liability for this amount at June 30, 2014. The Company subsequently engaged in further discussions regarding settlement, but the parties have not been able to reach agreement on either the amount of, or the terms and conditions governing, a settlement. The Company’s settlement offer of $90 million remains outstanding and the Company remains open to resolving the matter through settlement discussions. The Company believes that $90 million under a settlement scenario is a better estimate of loss at this time than any other amount. Based on the above accounting guidance, the Company’s contingent liability for CWA penalties and fines remains $90 million at June 30, 2015. However, the Company may ultimately incur a liability related to CWA penalties in excess of the current accrued liability.

The actual amount of a CWA penalty is subject to uncertainty, including whether the Company will be able to reach a settlement with the DOJ or will await the Louisiana District Court’s opinion in the penalty phase trial. The CWA sets forth subjective criteria to be considered by the court in assessing the magnitude of any CWA penalty: economic benefit to the violator; degree of culpability; seriousness of the violation; the nature, extent, and degree of success of any efforts to minimize or mitigate the effects of the discharge; prior history of violations; other penalties for the same incident; economic impact of the penalty on the violator; and other matters as justice may require. For the Phase I and II trials (defined in Civil Litigation Damage Claims below) and again for the penalty phase trial in January 2015, the Louisiana District Court ruled that no evidence of Anadarko’s alleged culpability or fault could be presented. In addition, in its Phase I Findings of Fact and Conclusions of Law (Phase I Findings and Conclusions), the Louisiana District Court did not allocate any fault to Anadarko. Given the subjective nature of the CWA criteria used to determine penalty assessments and the Louisiana District Court’s prior rulings related to culpability and allocation of fault, the Company currently cannot reasonably estimate the amount of any such penalty to be assessed or determine a reasonable range of potential loss if the matter is resolved by the Louisiana District Court following trial. Furthermore, BP’s July 2015 announcement of a settlement agreement in principle with the DOJ and the five Gulf states (Texas, Louisiana, Mississippi, Alabama, and Florida) regarding essentially all of the outstanding claims against BP related to the Deepwater Horizon event, including $5.5 billion to resolve CWA penalties, does not affect the Company’s current conclusion concerning its ability to estimate potential fines and penalties. The Company lacks insight into that settlement, which has yet to be finalized, retains legal counsel separate from BP, and was not involved in any manner with respect to that settlement. In addition, the consent decree covering the terms and conditions of BP’s announced settlement has yet to be disclosed.

Although the Company currently cannot reasonably estimate the amount of any such penalty to be assessed or determine a reasonable range of potential loss, the Company believes the following factors should limit the magnitude of any CWA penalties assessed:


•	the Company’s lack of direct operational involvement in the event as a non-operator,


•	the Louisiana District Court’s rulings excluding any evidence of Anadarko’s alleged culpability or fault, and


•	the Phase I Findings and Conclusions that did not allocate any fault to Anadarko.

In addition, the Company is not aware that any court has ever assessed a substantial CWA penalty against a party who has been found by a court to bear no fault for a spill.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. Contingencies (Continued)

Events or factors that could assist the Company in estimating the amount of settlement or potential civil penalty or a range of potential loss related to such penalty include a ruling by the Louisiana District Court or substantive settlement negotiations between the Company and the DOJ.

As discussed below, numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. Certain state and local governments appealed, or provided indication of a likely appeal of, the Louisiana District Court’s decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. It is unclear whether these appeals will be dismissed as part of BP’s announced settlement. If any such appeal proceeds and is successful, state and/or local laws and regulations could become sources of penalties or fines against the Company.

Civil Litigation Damage Claims Numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. This litigation has been consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the Louisiana District Court.

The first phase of the trial in the MDL (Phase I) commenced in February 2013. The issues tried in Phase I included the cause of the blowout and all related events leading up to April 22, 2010, the date the Deepwater Horizon sank, as well as allocation of fault. In September 2014, the Louisiana District Court issued its Phase I Findings and Conclusions. The Louisiana District Court found that BP and BP America Production Company (BPAP), Transocean Ltd. (Transocean), and Halliburton Energy Services, Inc. (Halliburton), but not Anadarko, are each liable under general maritime law for the blowout, explosion, and oil spill. The court determined that BP’s and BPAP’s conduct was reckless and that both Transocean’s and Halliburton’s conduct was negligent. The Louisiana District Court apportioned 67% of the fault to BP and BPAP, 30% to Transocean, and 3% to Halliburton. No fault was allocated to Anadarko. The plaintiffs and BP have appealed the Phase I Findings and Conclusions.

The second phase of trial (Phase II) began in September 2013. The issues tried in Phase II included spill-source control and quantification of the spill for the period from April 20, 2010, until the well was capped. In January 2015, the Louisiana District Court issued its Phase II Findings of Fact and Conclusions of Law (Phase II Findings and Conclusions). The Louisiana District Court found that, for purposes of calculating the maximum possible civil penalty under the CWA, 3.19 million barrels of oil were discharged into the Gulf of Mexico. The United States has appealed the Phase II Findings and Conclusions.

The penalty phase of the trial began in January 2015. In March 2014, the Louisiana District Court ruled that no evidence of Anadarko’s alleged culpability or fault could be presented during the penalty phase trial. The parties rested their case in February 2015, post-trial briefing concluded in April 2015, and the matter is pending before the Louisiana District Court. The trial included Anadarko, BP, and the United States, and will assess findings and penalties under the CWA.

Remaining Liability Outlook In addition to the assessment of civil penalties under the CWA discussed above, it is possible that the Company may recognize additional Deepwater Horizon event-related liabilities for potential fines and penalties and certain other claims not covered by the indemnification provisions of the Settlement Agreement.

Although the Company is fully indemnified by BP against OPA damage claims, NRD claims and assessment costs, and certain other potential liabilities, the Company may be required to recognize a liability for these amounts in advance of or in connection with recognizing a receivable from BP for the related indemnity payment. In all circumstances, however, the Company expects that any additional indemnified liability that may be recognized by the Company will be subsequently recovered from BP itself or through the guarantees of BPCNA or BP p.l.c.

The Company will continue to monitor the MDL and other legal proceedings discussed above, as well as federal investigations related to the Deepwater Horizon events. The Company cannot predict the nature of additional evidence that may be discovered during the course of legal proceedings or the timing of completion of any legal proceedings.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. Contingencies (Continued)

Other Litigation In December 2008, Anadarko sold its interest in the Peregrino heavy-oil field offshore Brazil. The Company is currently litigating a dispute with the Brazilian tax authorities regarding the tax rate applicable to the transaction. In August 2013, following a determination by an administrative court in a related matter that the amount of tax in dispute was not calculated properly, the Company filed a petition requesting the withdrawal of a portion of the judicial deposit to the extent it exceeds the amount of tax currently in dispute, and any interest on such amount. In April 2015, the Company’s petition was denied. For additional disclosure on this matter, see Note 17—Contingencies—Other Litigation in the Notes to Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

The Company believes that it will more likely than not prevail in Brazilian courts. Therefore, no tax liability has been recorded for Peregrino divestiture-related litigation at June 30, 2015.

13. Income Taxes

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



	Three Months Ended June 30,						Six Months Ended June 30,
millions except percentages	2015			2014			2015			2014
Income tax expense (benefit)	$	77		$	428		$	(1,315	)	$	1,092
Income (loss) before income taxes	185			694			(4,443		)	(1,268		)
Effective tax rate	42		%	62		%	30		%	(86		)%

The increase from the 35% U.S. federal statutory rate for the three months ended June 30, 2015 and 2014, was primarily attributable to the tax impact from foreign operations and Algerian exceptional profits taxes. The increase from the 35% U.S. federal statutory rate for the three months ended June 30, 2014, was also attributable to net changes in uncertain tax positions and the non-deductible contingent CWA-penalty accrual.

The Company reported a loss before income taxes for the six months ended June 30, 2015 and 2014. As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The decrease from the 35% U.S. federal statutory rate for the six months ended June 30, 2015, was primarily attributable to Algerian exceptional profits taxes and the tax impact from foreign operations. The decrease from the 35% U.S. federal statutory rate for the six months ended June 30, 2014, was primarily attributable to net changes in uncertain tax positions related to the settlement agreement associated with the Tronox Adversary Proceeding, the tax impact from foreign operations, Algerian exceptional profits taxes, and the non-deductible contingent CWA-penalty accrual.

At June 30, 2015, the Company had recorded a $577 million tax benefit related to the Tronox settlement. This benefit was net of a $1.3 billion uncertain tax position due to the uncertainty related to the deductibility of the settlement payment. The Company is a participant in the U.S. Internal Revenue Service’s (IRS) Compliance Assurance Process and has regular discussions with the IRS concerning the Company’s tax positions. Depending on the outcome of such discussions, it is reasonably possible that the amount of the uncertain tax position related to the settlement could change, perhaps materially. See Note 12—Contingencies—Tronox Litigation.

At June 30, 2015, the Company’s Consolidated Balance Sheet included $675 million of income taxes receivable presented in accounts receivable—others and $289 million of accrued income taxes presented in accrued expenses.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14. Supplemental Cash Flow Information

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	2015			2014
Cash paid (received)
Interest, net of amounts capitalized⁽¹⁾	$	1,621		$	342
Income taxes, net of refunds	6			655
Non-cash investing activities
Fair value of properties and equipment from non-cash transactions	$	126		$	5
Asset retirement cost additions	90			122
Accruals of property, plant, and equipment	901			1,344
Net liabilities assumed (divested) in acquisitions and divestitures	(29		)	(32		)
Non-cash investing and financing activities
Floating production, storage, and offloading vessel construction period obligation	$	43		$	53

__________________________________________________________________


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

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15. Segment Information

Anadarko’s business segments are separately managed due to distinct operational differences and unique technology, distribution, and marketing requirements. The Company’s three reporting segments are oil and gas exploration and production, midstream, and marketing. The oil and gas exploration and production segment explores for and produces natural gas, oil, condensate, and NGLs, and plans for the development and operation of the Company’s LNG project in Mozambique. The midstream segment engages in gathering, processing, treating, and transporting Anadarko and third-party oil, natural-gas, and NGLs production. The midstream reporting segment consists of two operating segments, WES and other midstream, which are aggregated into one reporting segment due to similar financial and operating characteristics. The marketing segment sells much of Anadarko’s oil, natural-gas, and NGLs production, as well as third-party purchased volumes.

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; exploration expense; depreciation, depletion, and amortization (DD&A); impairments; interest expense; total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives; and certain items not related to the Company’s normal operations, less net income attributable to noncontrolling interests. During the periods presented, items not related to the Company’s normal operations included Deepwater Horizon settlement and related costs, Tronox-related contingent loss, and certain other nonoperating items included in other (income) expense, net. The Company’s definition of Adjusted EBITDAX excludes exploration expense as it is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Finally, net income 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.



	Three Months Ended June 30,					Six Months Ended June 30,
millions	2015			2014		2015			2014
Income (loss) before income taxes	$	185		$	694	$	(4,443	)	$	(1,268	)
Exploration expense	103			502		1,186			801
DD&A	1,214			1,048		2,470			2,172
Impairments	30			117		2,813			120
Interest expense	201			186		417			369
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	(229		)	237		14			600
Deepwater Horizon settlement and related costs	—			93		4			93
Tronox-related contingent loss	—			19		5			4,319
Certain other nonoperating items	—			—		22			—
Less net income attributable to noncontrolling interests	47			39		79			82
Consolidated Adjusted EBITDAX	$	1,457		$	2,857	$	2,409		$	7,124

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15. Segment Information (Continued)

Information presented below as “Other and Intersegment Eliminations” includes corporate costs, results from hard-minerals royalties, and net cash from settlement of commodity derivatives. The following summarizes selected financial information for Anadarko’s reporting segments:



millions	Oil and Gas Exploration & Production			Midstream			Marketing			Other and Intersegment Eliminations			Total
Three Months Ended June 30, 2015
Sales revenues	$	1,356		$	191		$	1,090		$	—		$	2,637
Intersegment revenues	885			303			(954		)	(234		)	—
Gains (losses) on divestitures and other, net	(95		)	3			—			91			(1		)
Total revenues and other	2,146			497			136			(143		)	2,636
Operating costs and expenses ⁽¹⁾	832			234			192			(59		)	1,199
Net cash from settlement of commodity derivatives	—			—			—			(82		)	(82		)
Other (income) expense, net ⁽²⁾	—			—			—			15			15
Net income attributable to noncontrolling interests	—			47			—			—			47
Total expenses and other	832			281			192			(126		)	1,179
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—			—			—			—
Adjusted EBITDAX	$	1,314		$	216		$	(56	)	$	(17	)	$	1,457

Three Months Ended June 30, 2014
Sales revenues	$	2,223		$	119		$	2,043		$	—		$	4,385
Intersegment revenues	1,790			326			(1,906		)	(210		)	—
Gains (losses) on divestitures and other, net	10			(1		)	—			45			54
Total revenues and other	4,023			444			137			(165		)	4,439
Operating costs and expenses ⁽¹⁾	1,026			251			186			7			1,470
Net cash from settlement of commodity derivatives	—			—			—			88			88
Other (income) expense, net ⁽²⁾	—			—			—			(13		)	(13		)
Net income attributable to noncontrolling interests	—			39			—			—			39
Total expenses and other	1,026			290			186			82			1,584
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—			2			—			2
Adjusted EBITDAX	$	2,997		$	154		$	(47	)	$	(247	)	$	2,857

__________________________________________________________________


⁽¹⁾	Operating costs and expenses excludes exploration expense, DD&A, impairments, and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX.


⁽²⁾	Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15. Segment Information (Continued)



millions	Oil and Gas Exploration & Production			Midstream			Marketing			Other and Intersegment Eliminations			Total
Six Months Ended June 30, 2015
Sales revenues	$	2,426		$	365		$	2,431		$	—		$	5,222
Intersegment revenues	2,002			605			(2,145		)	(462		)	—
Gains (losses) on divestitures and other, net	(433		)	3			—			165			(265		)
Total revenues and other	3,995			973			286			(297		)	4,957
Operating costs and expenses ⁽¹⁾	1,834			474			390			(96		)	2,602
Net cash from settlement of commodity derivatives	—			—			—			(172		)	(172		)
Other (income) expense, net ⁽²⁾	—			—			—			40			40
Net income attributable to noncontrolling interests	—			79			—			—			79
Total expenses and other	1,834			553			390			(228		)	2,549
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—			1			—			1
Adjusted EBITDAX	$	2,161		$	420		$	(103	)	$	(69	)	$	2,409

Six Months Ended June 30, 2014
Sales revenues	$	4,612		$	239		$	3,872		$	—		$	8,723
Intersegment revenues	3,343			646			(3,595		)	(394		)	—
Gains (losses) on divestitures and other, net	1,470			(3		)	—			93			1,560
Total revenues and other	9,425			882			277			(301		)	10,283
Operating costs and expenses ⁽¹⁾	2,038			483			367			25			2,913
Net cash from settlement of commodity derivatives	—			—			—			180			180
Other (income) expense, net ⁽²⁾	—			—			—			(12		)	(12		)
Net income attributable to noncontrolling interests	—			82			—			—			82
Total expenses and other	2,038			565			367			193			3,163
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—			4			—			4
Adjusted EBITDAX	$	7,387		$	317		$	(86	)	$	(494	)	$	7,124

__________________________________________________________________


⁽¹⁾	Operating costs and expenses excludes exploration expense, DD&A, impairments, and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX.


⁽²⁾	Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

16. 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	2015			2014			2015		2014
Three Months Ended June 30
Service cost	$	29		$	24		$	2	$	2
Interest cost	26			25			4		3
Expected return on plan assets	(28		)	(26		)	—		—
Amortization of net actuarial loss (gain)	13			8			—		(1		)
Amortization of net prior service cost (credit)	—			—			1		—
Net periodic benefit cost	$	40		$	31		$	7	$	4

Six Months Ended June 30
Service cost	$	59		$	49		$	5	$	4
Interest cost	51			50			8		7
Expected return on plan assets	(55		)	(53		)	—		—
Amortization of net actuarial loss (gain)	26			17			—		(3		)
Amortization of net prior service cost (credit)	—			—			1		—
Net periodic benefit cost	$	81		$	63		$	14	$	8

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

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 report, 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


•	reserves levels


•	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 natural gas, oil, natural gas liquids (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 risks


•	processing volumes and pipeline throughput


•	general economic conditions nationally, internationally, or in the jurisdictions in which the Company or its subsidiaries are, or in the future may be, doing business


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


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

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•

the ability of BP Exploration & Production Inc. (BP) to meet its indemnification obligations to the Company for Deepwater Horizon events, including, among other things, damage claims arising under the Oil Pollution Act of 1990, claims for natural resource damages and associated damage-assessment costs, and any claims arising under the Operating Agreement for the Macondo well, as well as the ability of BP Corporation North America Inc. and BP p.l.c. to satisfy their guarantees of such indemnification obligations


•	the impact of remaining claims related to the Deepwater Horizon events, including, but not limited to, fines, penalties, and punitive damages against the Company, for which it is not indemnified by BP


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


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


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


•	the Company’s ability to successfully monetize select assets, repay its debt, and the impact of changes in the Company’s credit ratings


•	disruptions in international oil, NGLs, and condensate 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

•

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, 2014, 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 report in Part I, Item 1; the information set forth in 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, 2014; 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, 2014.

OVERVIEW

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

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Significant operating and financial activities for the second quarter of 2015 include the following:

Overall


•	Anadarko’s second-quarter sales volumes averaged 846 thousand barrels of oil equivalent per day (MBOE/d), which was essentially flat compared to the second quarter of 2014.


•	Oil and NGLs (liquids) sales volumes increased by 43 thousand barrels per day (MBbls/d), representing a 10% increase from the second quarter of 2014. This increase included a 15 MBbls/d decrease in sales volumes related to the divestitures of certain enhanced oil recovery (EOR) assets in the Rocky Mountains Region (Rockies) and the Company’s Chinese subsidiary.


•	The Company’s overall sales product mix increased to 53% liquids in the second quarter of 2015 compared to 49% in the second quarter of 2014.

U.S. Onshore


•	U.S. onshore second-quarter liquids sales volumes increased by 38 MBbls/d, representing a 15% increase from the second quarter of 2014, primarily due to higher sales volumes from the Wattenberg field, the Eagleford shale, and the Delaware basin, partially offset by lower sales volumes due to the sale of certain EOR assets in April 2015.


•	U.S. onshore second-quarter natural-gas sales volumes decreased by 35 MBOE/d, representing an 8% decrease from the second quarter of 2014, reflecting third-party infrastructure downtime and curtailments, as well as the Company’s storage of natural-gas volumes during the second quarter of 2015.


•	The sale of certain EOR assets in the Rockies, with an original sales price of $703 million, closed in April 2015 for net proceeds of $686 million after closing adjustments.


•	In early July, the Company entered into an agreement to sell certain U.S. onshore oil and gas exploration and production properties and related midstream assets in East Texas for $440 million, subject to closing adjustments, recognizing a loss of $97 million in the second quarter of 2015.

Gulf of Mexico


•	Gulf of Mexico second-quarter sales volumes averaged 83 MBOE/d, representing a 9% increase from the second quarter of 2014, primarily due to the commencement of oil production from the Lucius development in January 2015, partially offset by natural-gas production declines at Independence Hub.


•	The Company completed operations on the Thorvald exploration well (50% working interest), encountering approximately 80 net feet of oil pay. The well tested multiple sub-salt reservoirs in a three-way closure.

International


•	International second-quarter sales volumes averaged 84 MBbls/d, representing a 12% decrease from the second quarter of 2014, primarily due to the timing of cargo liftings in Algeria and the sale of the Company’s Chinese subsidiary in August 2014, partially offset by an increase in Ghana due to the timing of cargo liftings.


•	The Kronos-1 prospect in deepwater Colombia has encountered 130 to 230 net feet of natural-gas pay in the upper objective. The well is still drilling to test a deeper objective.

Financial


•	Anadarko’s net income attributable to common stockholders for the second quarter of 2015 totaled $61 million.


•	The Company generated $1.2 billion of cash flow from operations and ended the quarter with $2.2 billion of cash on hand.


•	Western Gas Partners, LP (WES), a publicly traded consolidated subsidiary, completed a public offering of $500 million aggregate principal amount of 3.950% Senior Notes due 2025.


•	Anadarko issued 9.2 million 7.50% tangible equity units (TEUs) at a stated amount of $50.00 per unit, raising net proceeds of $446 million.


•	Anadarko completed a public secondary offering of 2.3 million common units in Western Gas Equity Partners, LP (WGP), a publicly traded consolidated subsidiary that owns partnership interests in WES, raising net proceeds of $130 million.

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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, 2015,” refer to the comparison of the three months ended June 30, 2015, to the three months ended June 30, 2014, and any increases or decreases “for the six months ended June 30, 2015,” refer to the comparison of the six months ended June 30, 2015, to the six months ended June 30, 2014. The primary factors that affect the Company’s results of operations include commodity prices for natural gas, oil, and NGLs; sales volumes; the Company’s ability to discover additional oil and natural-gas reserves; the cost of finding such reserves; and operating costs.

RESULTS OF OPERATIONS



	Three Months Ended June 30,					Six Months Ended June 30,
millions except per-share amounts	2015			2014		2015			2014
Financial Results
Revenues and other	$	2,636		$	4,439	$	4,957		$	10,283
Costs and expenses	2,546			3,230		9,075			6,099
Other (income) expense	(95		)	515		325			5,452
Income tax expense (benefit)	77			428		(1,315		)	1,092
Net income (loss) attributable to common stockholders	$	61		$	227	$	(3,207	)	$	(2,442	)
Net income (loss) per common share attributable to common stockholders—diluted	$	0.12		$	0.45	$	(6.32	)	$	(4.84	)
Average number of common shares outstanding—diluted	509			507		507			505

Operating Results
Adjusted EBITDAX ⁽¹⁾	$	1,457		$	2,857	$	2,409		$	7,124
Sales volumes (MMBOE)	77			77		161			151

________________________________________________________________________________________________________

MMBOE—million barrels of oil equivalent


⁽¹⁾	See Operating Results—Segment Analysis—Adjusted EBITDAX for a description of Adjusted EBITDAX, which is not a U.S. Generally Accepted Accounting Principles (GAAP) measure, and for a reconciliation of Adjusted EBITDAX to income (loss) before income taxes, which is presented in accordance with GAAP.

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FINANCIAL RESULTS

Sales Revenues and Volumes



	Three Months Ended June 30,
millions except percentages	Natural Gas			Oil and Condensate			NGLs			Total
2014 sales revenues	$	991		$	2,705		$	411		$	4,107
Changes associated with sales volumes	(101		)	250			54			203
Changes associated with prices	(403		)	(1,339		)	(236		)	(1,978		)
2015 sales revenues	$	487		$	1,616		$	229		$	2,332
Increase (decrease) vs. 2014	(51		)%	(40		)%	(44		)%	(43		)%

	Six Months Ended June 30,
millions except percentages	Natural Gas			Oil and Condensate			NGLs			Total
2014 sales revenues	$	2,208		$	5,129		$	797		$	8,134
Changes associated with sales volumes	(94		)	824			218			948
Changes associated with prices	(986		)	(2,918		)	(554		)	(4,458		)
2015 sales revenues	$	1,128		$	3,035		$	461		$	4,624
Increase (decrease) vs. 2014	(49		)%	(41		)%	(42		)%	(43		)%

Anadarko’s sales revenues decreased for the three and six months ended June 30, 2015, due to lower average commodity prices and lower natural-gas sales volumes, partially offset by higher sales volumes for oil and NGLs.



	Three Months Ended June 30,				Six Months Ended June 30,
Sales Volumes	2015	Inc/(Dec) vs. 2014		2014	2015	Inc/(Dec) vs. 2014		2014
Barrels of Oil Equivalent (MMBOE except percentages)
United States	69	1	%	68	144	7	%	134
International	8	(12	)	9	17	1		17
Total barrels of oil equivalent	77	—		77	161	7		151

Barrels of Oil Equivalent per Day (MBOE/d except percentages)
United States	762	1	%	752	796	7	%	741
International	84	(12	)	96	94	1		93
Total barrels of oil equivalent per day	846	—		848	890	7		834

Sales volumes represent actual production volumes adjusted for changes in commodity inventories and natural-gas production volumes provided to satisfy a commitment established in conjunction with a development plan. Anadarko employs marketing strategies to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. For additional information, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q and Other (Income) Expense—(Gains) Losses on Derivatives, net.

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Natural-Gas Sales Volumes, Average Prices, and Revenues



	Three Months Ended June 30,						Six Months Ended June 30,
	2015		Inc/(Dec) vs. 2014		2014		2015		Inc/(Dec) vs. 2014		2014
United States
Sales volumes—Bcf	215		(10	)%	238		461		(4	)%	481
MMcf/d	2,354		(10	)	2,620		2,545		(4	)	2,658
Price per Mcf	$	2.28	(45	)	$	4.16	$	2.45	(47	)	$	4.59
Natural-gas sales revenues (millions)	$	487	(51	)	$	991	$	1,128	(49	)	$	2,208

_______________________________________________________________________________

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

Mcf—thousand cubic feet

The Company’s natural-gas sales volumes decreased by 266 MMcf/d for the three months ended June 30, 2015, and 113 MMcf/d for the six months ended June 30, 2015.

•

Sales volumes in the Southern and Appalachia Region decreased by 213 MMcf/d for the three months ended June 30, 2015, and 76 MMcf/d for the six months ended June 30, 2015, primarily due to third-party infrastructure downtime and curtailments, as well as the Company’s storage of natural-gas volumes during the second quarter of 2015. These decreases were partially offset by higher sales volumes as a result of continued horizontal drilling in the Eagleford shale.


•	Sales volumes in the Gulf of Mexico decreased by 62 MMcf/d for the three months ended June 30, 2015, and 58 MMcf/d for the six months ended June 30, 2015, primarily due to natural production declines at Independence Hub.


•	Sales volumes in the Rockies increased by 9 MMcf/d for the three months ended June 30, 2015, and 21 MMcf/d for the six months ended June 30, 2015, due to higher sales volumes in the Wattenberg field as a result of continued horizontal drilling, partially offset by natural production declines at Greater Natural Buttes and the Powder River basin.

The average natural-gas price Anadarko received decreased for the three and six months ended June 30, 2015, primarily due to strong year-over-year production growth in the northeast United States and slightly lower weather-driven residential and commercial demand.

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Oil and Condensate Sales Volumes, Average Prices, and Revenues



	Three Months Ended June 30,						Six Months Ended June 30,
	2015		Inc/(Dec) vs. 2014		2014		2015		Inc/(Dec) vs. 2014		2014
United States
Sales volumes—MMBbls	21		22	%	18		43		26	%	34
MBbls/d	240		22		196		238		26		189
Price per barrel	$	54.14	(45	)	$	98.69	$	49.23	(49	)	$	96.86
International
Sales volumes—MMBbls	8		(17	)%	9		16		(4	)%	17
MBbls/d	78		(17	)	95		88		(4	)	92
Price per barrel	$	60.81	(44	)	$	109.00	$	57.12	(47	)	$	108.71
Total
Sales volumes—MMBbls	29		9	%	27		59		16	%	51
MBbls/d	318		9		291		326		16		281
Price per barrel	$	55.78	(45	)	$	102.04	$	51.37	(49	)	$	100.76
Oil and condensate sales revenues (millions)	$	1,616	(40	)	$	2,705	$	3,035	(41	)	$	5,129

_______________________________________________________________________________

MMBbls—million barrels

Anadarko’s oil and condensate sales volumes increased by 27 MBbls/d for the three months ended June 30, 2015, and 45 MBbls/d for the six months ended June 30, 2015.


•	Sales volumes in the Rockies increased by 13 MBbls/d for the three months ended June 30, 2015, and 27 MBbls/d for the six months ended June 30, 2015, primarily in the Wattenberg field due to continued horizontal drilling, partially offset by lower sales volumes due to the sale of certain EOR assets in April 2015.


•	Southern and Appalachia Region sales volumes increased by 15 MBbls/d for the three and six months ended June 30, 2015, primarily in the Eagleford shale as a result of continued horizontal drilling, and in the Delaware basin due to increased drilling and wells brought online as a result of added infrastructure.


•	Sales volumes in the Gulf of Mexico increased by 16 MBbls/d for the three months ended June 30, 2015, and 9 MBbls/d for the six months ended June 30, 2015, primarily from the Lucius development, which achieved first oil in January 2015.


•	International sales volumes decreased by 17 MBbls/d for the three months ended June 30, 2015, and 4 MBbls/d for the six months ended June 30, 2015, due to the timing of cargo liftings in Algeria and the sale of the Company’s Chinese subsidiary in August 2014, partially offset by an increase in Ghana due to the timing of cargo liftings.

Anadarko’s average oil price received decreased for the three and six months ended June 30, 2015, as a result of global oversupply.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2015		Inc/(Dec) vs. 2014		2014		2015		Inc/(Dec) vs. 2014		2014
United States
Sales volumes—MMBbls	12		10	%	11		24		23	%	20
MBbls/d	130		10		119		134		23		109
Price per barrel	$	17.98	(52	)	$	37.39	$	17.63	(56	)	$	40.08
International
Sales volumes—MMBbls	—		NM		—		1		NM		—
MBbls/d	6		NM		1		6		NM		1
Price per barrel	$	31.11	(53	)	$	66.69	$	32.01	(52	)	$	66.69
Total
Sales volumes—MMBbls	12		13	%	11		25		27	%	20
MBbls/d	136		13		120		140		27		110
Price per barrel	$	18.50	(51	)	$	37.66	$	18.24	(55	)	$	40.22
Natural-gas liquids sales revenues (millions)	$	229	(44	)	$	411	$	461	(42	)	$	797

_________________________________________________________________________

NM—not meaningful

NGLs sales represent revenues from the sale of product derived from the processing of Anadarko’s natural-gas production. The Company’s NGLs sales volumes increased by 16 MBbls/d for the three months ended June 30, 2015, and 30 MBbls/d for the six months ended June 30, 2015.


•	Sales volumes in the Rockies increased by 7 MBbls/d for the three months ended June 30, 2015, and 19 MBbls/d for the six months ended June 30, 2015, primarily in the Wattenberg field due to continued horizontal drilling and the Lancaster plant coming online in April 2014.


•	Sales volumes in the Southern and Appalachia Region increased by 3 MBbls/d for the three months ended June 30, 2015, and 5 MBbls/d for the six months ended June 30, 2015, as a result of continued horizontal drilling in the Eagleford shale.


•	International NGLs sales volumes increased by 5 MBbls/d for the three and six months ended June 30, 2015, as volumes have increased in Algeria since the commencement of sales at the Company’s El Merk facility during the second quarter of 2014.

Anadarko’s average NGLs price received decreased for the three and six months ended June 30, 2015, primarily due to decreased propane prices as a result of lower seasonal demand, higher NGLs production levels, and declines in oil prices.

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Gathering, Processing, and Marketing



	Three Months Ended June 30,						Six Months Ended June 30,
millions except percentages	2015		Inc/(Dec) vs. 2014		2014		2015		Inc/(Dec) vs. 2014		2014
Gathering, processing, and marketing sales	$	305	10	%	$	278	$	598	2	%	$	589
Gathering, processing, and marketing expense	255		2		250		509		1		502
Total gathering, processing, and marketing, net	$	50	79		$	28	$	89	2		$	87

Gathering and processing sales includes revenue from the sale of NGLs and remaining residue gas extracted from natural gas purchased from third parties and processed by Anadarko, as well as fee revenue earned by providing gathering, processing, compression, and treating services to third parties. Marketing sales include the margin earned from purchasing and selling third-party oil and natural gas. Gathering, processing, and marketing expense includes the cost of third-party natural gas purchased and processed by Anadarko, as well as other operating and transportation expenses related to the Company’s costs to perform gathering, processing, and marketing activities.

Gathering, processing, and marketing, net increased by $22 million for the three months ended June 30, 2015, primarily resulting from higher gathering and processing revenue due to increased volumes. The increased processing volumes primarily related to WES’s November 2014 acquisition of Nuevo Midstream, LLC, which was renamed to Delaware Basin Midstream, LLC after the acquisition. Gathering, processing, and marketing, net was relatively flat for the six months ended June 30, 2015, due to higher gathering revenue related to higher throughput volumes offset by lower marketing margins from lower natural-gas and NGLs prices and higher operating expenses related to utilities.

Gains (Losses) on Divestitures and Other, net



	Three Months Ended June 30,					Six Months Ended June 30,
millions	2015			2014		2015			2014
Gains (losses) on divestitures and other, net	$	(1	)	$	54	$	(265	)	$	1,560

For the three months ended June 30, 2015 gains (losses) on divestitures and other, net decreased by $55 million.

•

The Company recognized a loss of $97 million on assets held for sale during the three months ended June 30, 2015. The loss was associated with the agreement to divest certain U.S. onshore oil and gas exploration and production properties and related midstream assets in East Texas for a sales price of $440 million, subject to closing adjustments. The sale is expected to close in the third quarter of 2015.


•	The Company recognized income of $63 million in 2015 related to the settlement of a royalty lawsuit associated with a property in the Gulf of Mexico.


•	The remaining decrease relates to lower minerals revenues and other revenues.

For the six months ended June 30, 2015 gains (losses) on divestitures and other, net decreased by $1.8 billion.


•	The Company recognized losses of $437 million on divestitures and assets held for sale in 2015. These losses were comprised of the $97 million loss on properties in East Texas and a loss of $340 million associated with certain EOR assets in the Rockies.


•	The Company recognized income of $117 million in 2015 related to the settlement of a royalty lawsuit associated with a property in the Gulf of Mexico.


•	The Company recognized a $1.5 billion gain in the first quarter of 2014 associated with its divestiture of a 10% working interest in Offshore Area 1 in Mozambique for sales proceeds of $2.64 billion.

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Costs and Expenses



	Three Months Ended June 30,						Six Months Ended June 30,
	2015		Inc/(Dec) vs. 2014		2014		2015		Inc/(Dec) vs. 2014		2014
Oil and gas operating (millions)	$	226	(17	)%	$	273	$	522	(11	)%	$	586
Oil and gas operating—per BOE	2.93		(17	)	3.53		3.24		(16	)	3.88
Oil and gas transportation and other (millions)	289		3		281		650		19		547
Oil and gas transportation and other—per BOE	3.75		3		3.64		4.03		11		3.62

_________________________________________________________________________

BOE—barrel of oil equivalent

Oil and gas operating expense decreased by $47 million for the three months ended June 30, 2015, due to lower expenses of $26 million related to the sale of certain EOR assets in April 2015, $16 million related to the sale of the Company’s Chinese subsidiary in August 2014, and $12 million of lower workover costs due to reduced activity primarily in the Southern and Appalachia Region and in the Rockies, partially offset by higher costs of $12 million associated with increased workovers in Ghana.

Oil and gas operating expense decreased by $64 million for the six months ended June 30, 2015, due to lower workover costs of $47 million as a result of reduced activity primarily in the Gulf of Mexico and the Rockies, lower expenses of $32 million related to the divestiture of the Company’s Chinese subsidiary in August 2014, and $27 million related to the divestiture of certain EOR assets in April 2015, partially offset by higher costs of $38 million associated with increased workovers in Ghana.

The related per BOE costs decreased by $0.60 for the three months ended June 30, 2015, and $0.64 for the six months ended June 30, 2015, primarily due to the lower costs and asset sales discussed above as well as increased sales volumes for the six months ended June 30, 2015.

Oil and gas transportation and other expense increased by $8 million for the three months ended June 30, 2015, and $103 million for the six months ended June 30, 2015, primarily attributable to higher volumes associated with the growth in the Rockies. In addition, oil and gas transportation and other expense increased for the six months ended June 30, 2015, due to a $50 million expense for the early termination of a drilling rig.

Oil and gas transportation and other expense per BOE increased by $0.11 for the three months ended June 30, 2015, due to higher costs. Oil and gas transportation and other expense per BOE increased by $0.41 for the six months ended June 30, 2015, as higher costs were only partially offset by increased sales volumes. Oil and gas transportation and other expense per BOE for the six months ended June 30, 2015, included $0.31 related to the early termination of the drilling rig.

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	Three Months Ended June 30,				Six Months Ended June 30,
millions	2015		2014		2015		2014
Exploration Expense
Dry hole expense	$	13	$	302	$	42	$	423
Impairments of unproved properties	18		109		998		186
Geological and geophysical expense	16		37		38		80
Exploration overhead and other	56		54		108		112
Total exploration expense	$	103	$	502	$	1,186	$	801

For the three months ended June 30, 2015, total exploration expense decreased by $399 million.


•	Dry hole expense decreased by $289 million due to unsuccessful drilling activities expensed in 2014 primarily associated with wells in the Gulf of Mexico.


•	Impairments of unproved properties decreased $91 million due to 2014 impairments of $54 million primarily related to the expiration of leases in the Gulf of Mexico and $33 million as a result of changes in the Company’s drilling plans for certain U.S. onshore oil and gas properties.


•	Geological and geophysical expense decreased by $21 million due to lower seismic purchases in Colombia, New Zealand, and Côte d’Ivoire.

For the six months ended June 30, 2015, total exploration expense increased by $385 million.

•

Impairments of unproved properties increased by $812 million primarily due to a $935 million impairment in the first quarter of 2015 related to the Company’s unproved Greater Natural Buttes properties as a result of lower commodity prices. The Company recognized a $50 million impairment in the first quarter of 2014 due to the decision not to pursue further drilling in Sierra Leone in addition to the impairments in the Gulf of Mexico and for certain U.S. onshore oil and gas properties discussed above.


•	Dry hole expense decreased by $381 million due to unsuccessful drilling activities expensed in 2014 primarily associated with wells in the Gulf of Mexico and New Zealand, compared to unsuccessful drilling activities expensed in 2015 primarily associated with a well in Mozambique.


•	Geological and geophysical expense decreased by $42 million due to lower seismic purchases in Côte d’Ivoire, Colombia, and the Gulf of Mexico.



	Three Months Ended June 30,						Six Months Ended June 30,
millions except percentages	2015		Inc/(Dec) vs. 2014		2014		2015		Inc/(Dec) vs. 2014		2014
General and administrative	$	278	(9	)%	$	305	$	588	(2	)%	$	603
Depreciation, depletion, and amortization	1,214		16		1,048		2,470		14		2,172
Other taxes	151		(58	)	361		333		(51	)	675
Impairments	30		(74	)	117		2,813		NM		120

General and administrative expense (G&A) decreased by $27 million for the three months ended June 30, 2015, and $15 million for the six months ended June 30, 2015, due to lower legal and consulting fees primarily as a result of the Tronox settlement reached in 2014. The decrease in G&A expense for the six months ended June 30, 2015, was partially offset by increased pension plan expenses as a result of changes in interest rates and higher employee headcount.

Depreciation, depletion, and amortization (DD&A) expense increased by $166 million for the three months ended June 30, 2015, primarily due to costs associated with U.S. onshore properties and additional gathering and processing facilities and increased asset retirement costs for wells in the Gulf of Mexico.

DD&A expense increased by $298 million for the six months ended June 30, 2015, primarily due to costs associated with U.S. onshore properties and additional gathering and processing facilities and higher 2015 sales volumes associated with U.S. onshore properties.

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Other taxes decreased by $210 million for the three months ended June 30, 2015, primarily due to lower U.S. severance taxes of $85 million, lower Algerian exceptional profits taxes of $76 million, and lower ad valorem taxes of $42 million. These decreases were primarily caused by lower commodity prices and lower sales volumes in Algeria.

For the six months ended June 30, 2015, other taxes decreased by $342 million primarily due to lower U.S. severance taxes of $145 million, lower Algerian exceptional profits taxes of $109 million, and lower ad valorem taxes of $62 million. These decreases were primarily caused by lower commodity prices. Also, Chinese windfall profits taxes decreased by $24 million for the six months ended June 30, 2015, as a result of the sale of the Company’s Chinese subsidiary in August 2014.

Impairment expense for the six months ended June 30, 2015, included $2.3 billion related to the Company’s Greater Natural Buttes oil and gas properties and $449 million for related midstream properties, which were impaired due to lower commodity prices. Impairment expense for the three and six months ended June 30, 2014, included $115 million related to an oil and gas property in the Gulf of Mexico that was impaired due to a reduction in estimated future cash flows.



	Three Months Ended June 30,				Six Months Ended June 30,
millions	2015		2014		2015		2014
Deepwater Horizon settlement and related costs	$	—	$	93	$	4	$	93

Deepwater Horizon settlement and related costs for the three and six months ended June 30, 2015, included legal fees and other costs associated with the Deepwater Horizon event-related claims. In the second quarter of 2014, the Company recorded a $90 million expense and contingent liability associated with potential civil penalties under the Clean Water Act (CWA) related to the Deepwater Horizon event-related claims. For additional information, see Note 12—Contingencies—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Other (Income) Expense



	Three Months Ended June 30,						Six Months Ended June 30,
millions except percentages	2015			2014			2015			2014
Interest Expense
Debt and other	$	244		$	233		$	498		$	473
Capitalized interest	(43		)	(47		)	(81		)	(104		)
Total interest expense	$	201		$	186		$	417		$	369

Interest expense increased by $15 million for the three months ended June 30, 2015, and $48 million for the six months ended June 30, 2015, primarily due to a decrease in capitalized interest related to lower construction-in-progress balances for long-term capital projects and an increase in interest expense due to higher debt outstanding during 2015.



	Three Months Ended June 30,					Six Months Ended June 30,
millions	2015			2014		2015			2014
(Gains) Losses on Derivatives, net
(Gains) losses on commodity derivatives, net	$	1		$	164	$	(52	)	$	379
(Gains) losses on interest-rate derivatives, net	(312		)	159		(107		)	397
Total (gains) losses on derivatives, net	$	(311	)	$	323	$	(159	)	$	776

(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. Anadarko enters into commodity derivatives to manage the risk of changes in the market prices for its anticipated sales of production. Anadarko also enters into interest-rate swaps to fix or float interest rates on existing or anticipated indebtedness to manage exposure to interest-rate changes. For additional information, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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	Three Months Ended June 30,						Six Months Ended June 30,
millions	2015			2014			2015			2014
Other (Income) Expense, net
Interest income	$	(2	)	$	(4	)	$	(7	)	$	(7	)
Other	17			(9		)	69			(5		)
Total other (income) expense, net	$	15		$	(13	)	$	62		$	(12	)

Other expense, net increased by $28 million for the three months ended June 30, 2015, primarily due to lower income associated with certain equity investments as a result of lower commodity prices.

Other expense, net increased by $74 million for the six months ended June 30, 2015, primarily due to lower income of $32 million associated with certain equity investments as a result of lower commodity prices and $30 million due to changes in foreign currency gains/losses, which reflect the unfavorable impact of exchange-rate changes primarily applicable to foreign currency held in escrow pending final determination of the Company’s Brazilian tax liability attributable to the 2008 divestiture of the Peregrino field offshore Brazil. Also, as a result of a Chapter 11 bankruptcy declaration by a third party, the U.S. Department of the Interior ordered Anadarko to perform the decommissioning of a production facility and related wells, previously sold to the third party. The Company accrued the costs to decommission the facility and the wells in prior years. During the six months ended June 30, 2015, the Company recognized a charge of $22 million for the required decommissioning of an additional well. Anadarko has completed the decommissioning of the facility and expects to complete the remaining decommissioning of the wells in 2016.



	Three Months Ended June 30,				Six Months Ended June 30,
millions	2015		2014		2015		2014
Tronox-related contingent loss	$	—	$	19	$	5	$	4,319

In April 2014, Anadarko and Kerr-McGee Corporation and certain of its subsidiaries (collectively, Kerr-McGee) entered into a settlement agreement for $5.15 billion, plus interest, resolving all claims asserted in the Tronox Adversary Proceeding. In January 2015, the Company paid $5.2 billion after the settlement agreement became effective.

Anadarko recognized a Tronox-related contingent loss of $4.3 billion during the six months ended June 30, 2014, settlement-related interest expense of $19 million for the three and six months ended June 30, 2014, and additional settlement-related interest expense of $5 million until the settlement payment was made in late January 2015. See Note 12—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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Income Tax Expense



	Three Months Ended June 30,						Six Months Ended June 30,
millions except percentages	2015			2014			2015			2014
Income tax expense (benefit)	$	77		$	428		$	(1,315	)	$	1,092
Income (loss) before income taxes	185			694			(4,443		)	(1,268		)
Effective tax rate	42		%	62		%	30		%	(86		)%

The Company reported a loss before income taxes for the six months ended June 30, 2015 and 2014. As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The decrease from the 35% U.S. federal statutory rate for the six months ended June 30, 2015, was primarily attributable to Algerian exceptional profit taxes and the tax impact from foreign operations. The variation from the 35% U.S. federal statutory rate for the six months ended June 30, 2014, was primarily attributable to net changes in uncertain tax positions related to the settlement agreement associated with the Tronox Adversary Proceeding, the tax impact from foreign operations, Algerian exceptional profits taxes, and the non-deductible contingent CWA-penalty accrual.

For additional information on income taxes, see Note 13—Income Taxes in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Net Income Attributable to Noncontrolling Interests

The Company’s net income attributable to noncontrolling interests for the three and six months ended June 30, 2015 and 2014, related to public ownership interests in WES and WGP. Public ownership in WES consisted of a limited partnership interest of 55.2% at June 30, 2015, and 56.8% at June 30, 2014. Public ownership in WGP consisted of a limited partnership interest of 12.7% at June 30, 2015, and 9.0% at June 30, 2014. In June 2015, Anadarko issued 9.2 million TEUs, which include an equity component that may be settled in WGP common units. See Note 7—Tangible Equity Units and Note 11—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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OPERATING RESULTS

Segment Analysis—Adjusted EBITDAX 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; exploration expense; DD&A; impairments; interest expense; total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives; and certain items not related to the Company’s normal operations, less net income attributable to noncontrolling interests. During the periods presented, items not related to the Company’s normal operations included Deepwater Horizon settlement and related costs, Tronox-related contingent loss, and certain other nonoperating items included in other (income) expense, net. The Company’s definition of Adjusted EBITDAX, which is not a GAAP measure, excludes exploration expense, as it is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Finally, net income attributable to noncontrolling interests is excluded from the Company’s measure of Adjusted EBITDAX because it represents earnings that are not attributable to the Company’s common stockholders.

Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders. 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 prepared in accordance with GAAP, such as operating income or cash flows from operating activities. Adjusted EBITDAX has important limitations as an analytical tool because it excludes certain items that affect net income (loss) attributable to common stockholders and net cash provided by operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Anadarko’s results as reported under GAAP. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes, and consolidated Adjusted EBITDAX by reporting segment.

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Adjusted EBITDAX



	Three Months Ended June 30,								Six Months Ended June 30,
millions except percentages	2015			Inc/(Dec) vs. 2014		2014			2015			Inc/(Dec) vs. 2014		2014
Income (loss) before income taxes	$	185		(73	)%	$	694		$	(4,443	)	NM		$	(1,268	)
Exploration expense	103			(79	)	502			1,186			48	%	801
DD&A	1,214			16		1,048			2,470			14		2,172
Impairments	30			(74	)	117			2,813			NM		120
Interest expense	201			8		186			417			13		369
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	(229		)	(197	)	237			14			(98	)	600
Deepwater Horizon settlement and related costs	—			(100	)	93			4			(96	)	93
Tronox-related contingent loss	—			(100	)	19			5			(100	)	4,319
Certain other nonoperating items	—			NM		—			22			NM		—
Less net income attributable to noncontrolling interests	47			21		39			79			(4	)	82
Consolidated Adjusted EBITDAX	$	1,457		(49	)	$	2,857		$	2,409		(66	)	$	7,124
Adjusted EBITDAX by reporting segment
Oil and gas exploration and production	$	1,314		(56	)%	$	2,997		$	2,161		(71	)%	$	7,387
Midstream	216			40		154			420			32		317
Marketing	(56		)	(19	)	(47		)	(103		)	(20	)	(86		)
Other and intersegment eliminations	(17		)	93		(247		)	(69		)	86		(494		)

Oil and Gas Exploration and Production Adjusted EBITDAX decreased for the three and six months ended June 30, 2015, due to lower commodity prices, partially offset by higher oil and NGLs sales volumes. Adjusted EBITDAX also decreased for the six months ended June 30, 2015, due to a $1.5 billion gain associated with the Company’s 2014 divestiture of a 10% working interest in Offshore Area 1 in Mozambique and a $340 million loss on assets held for sale associated with the divestiture of certain EOR assets in the Rockies in April 2015.

Midstream Adjusted EBITDAX increased for the three and six months ended June 30, 2015, primarily due to higher gathering revenue resulting from higher volumes.

Marketing Marketing earnings primarily represent the margin earned on sales of natural gas, oil, and NGLs purchased from third parties. Adjusted EBITDAX decreased for the three and six months ended June 30, 2015, due to lower marketing margins.

Other and Intersegment Eliminations Other and intersegment eliminations consists primarily of corporate costs, income from hard-minerals royalties, and net cash from settlement of commodity derivatives. Adjusted EBITDAX increased for the three and six months ended June 30, 2015, primarily due to a favorable change in net cash received/paid on the settlement of commodity derivatives in 2015.

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LIQUIDITY AND CAPITAL RESOURCES

Overview Anadarko generates cash needed to fund capital expenditures, debt-service obligations, and dividend payments primarily from operating activities, and enters into debt and equity transactions primarily to maintain the Company’s desired capital structure and to finance acquisition opportunities. The Company has a variety of funding sources available, including cash on hand, an asset portfolio that provides ongoing cash-flow-generating capacity, opportunities for liquidity enhancement through divestitures and joint-venture arrangements that reduce future capital expenditures, and the Company’s credit facilities and commercial paper program. In addition, an effective registration statement is available to Anadarko covering the sale of 32 million WGP common units owned by the Company at June 30, 2015. For additional information, see Sources of Cash—Financing Activities below.

During the six months ended June 30, 2015, cash from operations and cash on hand were the primary sources for funding capital investments. Anadarko’s cash flows used in operating activities included a $5.2 billion payment related to the Tronox settlement, which was funded using cash on hand and borrowings. The Company continuously monitors its liquidity needs, coordinates its capital expenditure program with its expected cash flows and projected debt-repayment schedule, and evaluates available funding alternatives in light of current and expected conditions.

At June 30, 2015, Anadarko’s scheduled debt maturities during the next year consist of $592 million of borrowings under the commercial paper program and $33 million related to the senior amortizing notes associated with the TEUs as discussed in Sources of Cash—Financing Activities below. The Company classified the outstanding commercial paper notes as long-term debt on the Company’s Consolidated Balance Sheet, as the Company currently intends to refinance these obligations at maturity with additional commercial paper notes supported by the Company’s Five-Year Facility. In addition, the Company’s $1.750 billion 5.950% Senior Notes are scheduled to mature in September 2016. The Company has the ability and intent to refinance these notes with long-term debt.

Anadarko’s Zero-Coupon Senior Notes due 2036 (Zero Coupons) can be put to the Company in October of each year, in whole or in part, for the then-accreted value, which will be $796 million at the next put date in October 2015. The Zero Coupons are classified as long-term debt on the Company’s Consolidated Balance Sheets, as the Company has the ability and intent to refinance these obligations using long-term debt.

Management believes that the Company’s liquidity position, asset portfolio, and operating and financial performance provide the necessary financial flexibility to fund the Company’s current and long-term operations.

Revolving Credit Facilities and Commercial Paper Program In January 2015, upon satisfaction of certain conditions, including the settlement payment related to the Tronox Adversary Proceeding, the Company’s $5.0 billion senior secured revolving credit facility was replaced by a $3.0 billion five-year senior unsecured revolving credit facility (Five-Year Facility), which is expandable to $4.0 billion, and a $2.0 billion 364-day senior unsecured revolving credit facility (364-Day Facility). At June 30, 2015, the Company had no outstanding borrowings under the Five-Year or 364-Day Facilities and was in compliance with all covenants therein.

During the first quarter of 2015, the Company initiated a commercial paper program, which allows a maximum of $3.0 billion of unsecured commercial paper notes and is supported by the Company’s Five-Year Facility. At June 30, 2015, the Company had $592 million of commercial paper notes outstanding at a weighted-average interest rate of 0.51%. During the six months ended June 30, 2015, maximum outstanding borrowings under the commercial paper program were $1.4 billion. The average borrowings outstanding under the commercial paper program were $1.0 billion with a weighted-average interest rate of 0.62%.

For additional information on the revolving credit facilities and the commercial paper program, see Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

WES Funding Sources WES, Anadarko’s publicly traded consolidated subsidiary, uses cash flows from operations to fund ongoing operations, service its debt, and make distributions to its equity holders. As needed, WES supplements cash generated from its operating activities with proceeds from debt or equity issuances or borrowings under its five-year $1.2 billion senior unsecured revolving credit facility maturing in February 2019 (RCF), which is expandable to $1.5 billion.

At June 30, 2015, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $270 million at an interest rate of 1.49%, had outstanding letters of credit of $13 million, and had available borrowing capacity of $917 million. See Sources of Cash—Financing Activities below.

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During the six months ended June 30, 2015, WES issued 874 thousand of its common units to the public under its continuous offering program, which allows the issuance of up to an aggregate of $500 million of WES common units, raising net proceeds of $57 million. The remaining amount available under this program was $443 million of WES common units at June 30, 2015.

Sources of Cash

Operating Activities Anadarko’s cash flow used in operating activities during the six months ended June 30, 2015, was $3.3 billion, compared to cash flow provided by operating activities of $4.2 billion for the same period of 2014. The decrease is primarily due to the $5.2 billion Tronox settlement payment, decreased sales revenues resulting from lower commodity prices, and the unfavorable impact of changes in working capital items.

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

Investing Activities During the six months ended June 30, 2015, Anadarko received pretax proceeds of $700 million primarily related to the April 2015 sale of certain EOR assets in the Rockies.

Financing Activities During the six months ended June 30, 2015, the Company borrowed $1.8 billion under the 364-Day Facility, which was primarily used to repay $1.5 billion of borrowings entered into in January 2015 under its $5.0 billion senior secured revolving credit facility. The remaining proceeds were used for partial payment of the settlement related to the Tronox Adversary Proceeding and for general corporate purposes. The Company also had net borrowings of $629 million of commercial paper notes and sold 2.3 million WGP common units to the public, raising net proceeds of $130 million, with proceeds from both used for general corporate purposes.

During the second quarter of 2015, Anadarko issued 9.2 million TEUs at a stated amount of $50.00 per TEU, raising net proceeds of $446 million. Each TEU is comprised of a prepaid equity purchase contract for WGP common units, subject to Anadarko’s right to elect to issue and deliver shares of Anadarko’s common stock in lieu of WGP common units, and a senior amortizing note due in June 2018, which bears interest at the rate of 1.50% per annum. For additional information, see Note 7—Tangible Equity Units in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Anadarko’s consolidated subsidiary, WES, borrowed $280 million under its RCF primarily for general partnership purposes, including the funding of capital expenditures. In addition, during the second quarter of 2015, WES completed a public offering of $500 million aggregate principal amount of 3.950% Senior Notes due 2025. Net proceeds from the offering were used to repay a portion of the borrowings under WES’s RCF. WES also issued 874 thousand of its common units to the public under its continuous offering program, raising net proceeds of $57 million.

Uses of Cash

Anadarko invests significant capital to develop, acquire, and explore for oil and natural gas and to expand its midstream infrastructure. The Company also uses cash to fund ongoing operating costs, capital contributions for equity investments, debt repayments, and distributions to its shareholders.

Tronox Settlement Payment In April 2014, Anadarko and Kerr-McGee entered into a settlement agreement to resolve all claims asserted in the Tronox Adversary Proceeding for $5.15 billion. In addition, the Company agreed to pay interest on that amount from April 3, 2014, through payment of the settlement. In January 2015, the Company paid $5.2 billion after the settlement agreement became effective. See Note 12—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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



	Six Months Ended June 30,
millions	2015		2014
Property acquisitions
Exploration	$	53	$	92
Development	1		112
Exploration	382		786
Development	2,224		3,149
Capitalized interest	68		93
Total oil and gas capital expenditures	2,728		4,232
Gathering, processing, and marketing and other ⁽¹⁾	495		738
Total capital expenditures ⁽²⁾	$	3,223	$	4,970

________________________________________________________________________________________


⁽¹⁾	Includes WES capital expenditures of $278 million for the six months ended June 30, 2015, and $343 million for the six months ended June 30, 2014.


⁽²⁾	Capital expenditures in this table are presented on an accrual basis. Additions to properties and equipment on the Company’s Consolidated Statements of Cash Flows only include capital expenditures funded with cash payments during the period.

The Company’s capital spending decreased by $1.7 billion for the six months ended June 30, 2015, due to decreased development costs of $925 million primarily in the Rockies and the Southern and Appalachia Region and lower exploration costs of $404 million primarily in the Gulf of Mexico and the Southern and Appalachia Region. Also, development acquisitions in 2014 included a spar lease buyout of $110 million in the Gulf of Mexico and gathering, processing, and marketing and other decreased $243 million primarily due to lower expenditures for plants and gathering in the Rockies.

In the third quarter of 2014, the Company entered into a carried-interest arrangement that requires a third party to fund $442 million of Anadarko’s capital costs in exchange for a 34% working interest in the Eaglebine development, located in Southeast Texas. The third-party funding is expected to cover Anadarko’s future capital costs in the development through 2020. At June 30, 2015, $61 million of the total $442 million obligation had been funded.

In the second quarter of 2013, the Company entered into a carried-interest arrangement that requires a third-party partner to fund $860 million of Anadarko’s capital costs in exchange for a 12.75% working interest in the Heidelberg development, located in the Gulf of Mexico. The third-party funding is expected to cover the substantial majority of Anadarko’s expected future capital costs through first production, which is expected to occur by mid-2016. At June 30, 2015, $592 million of the total $860 million obligation had been funded.

Investments During the six months ended June 30, 2015, the Company made capital contributions of $68 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 a gas processing plant, marine well containment, and pipelines.

Debt Retirements and Repayments During the six months ended June 30, 2015, the Company repaid $1.5 billion of borrowings under the $5.0 billion senior secured revolving credit facility, $1.8 billion under the 364-Day Facility, and $37 million of commercial paper notes with maturities greater than 90 days. WES also repaid $520 million of borrowings under its RCF primarily from proceeds from WES’s debt offering.

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Derivative Instruments The Company’s derivative instruments are subject to individually negotiated credit provisions that may require the Company or the counterparties to provide collateral of cash or letters of credit depending on the derivative portfolio valuation versus negotiated credit thresholds. These credit thresholds may also require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered, such as if the Company’s credit rating from major credit rating agencies declines to below investment grade. The Company provided cash collateral of $100 million as of June 30, 2015, in connection with its derivative instruments. Also, the Company has $1.1 billion of interest rate derivatives scheduled to settle in September 2016, unless the terms of the derivatives are amended.

Common Stock Dividends and Distributions to Noncontrolling Interest Owners Anadarko paid dividends of $277 million to its common stockholders during the six months ended June 30, 2015, and $230 million during the six months ended June 30, 2014. During the second quarter of 2014, Anadarko increased the quarterly dividend paid to common stockholders from $0.18 per share to $0.27 per share. Anadarko has paid a dividend to its common stockholders on a quarterly basis since becoming a public company in 1986. The amount of future dividends paid to Anadarko common stockholders will be determined by the Board of Directors on a quarterly basis and will depend on earnings, financial condition, capital requirements, the effect a dividend payment would have on the Company’s compliance with relevant financial covenants, and other factors.

WES distributed to its unitholders other than Anadarko and WGP an aggregate of $111 million during the six months ended June 30, 2015, and $83 million during the six months ended June 30, 2014. WES has made quarterly distributions to its unitholders since its initial public offering in the second quarter of 2008, and has increased its distribution from $0.30 per common unit for the third quarter of 2008 to $0.75 per common unit for the second quarter of 2015 (to be paid in August 2015).

WGP distributed to its unitholders other than Anadarko an aggregate of $17 million during the six months ended June 30, 2015, and $10 million during the six months ended June 30, 2014. WGP has made quarterly distributions to its unitholders since its initial public offering in December 2012, and has increased its distribution from $0.17875 per common unit for the first quarter of 2013 to $0.36375 per unit for the second quarter of 2015 (to be paid in August 2015).

Outlook

The Company’s revenues, operating results, cash flows from operations, capital spending, and future growth rates are highly dependent on the prices the Company receives for oil, natural gas, and NGLs, which can fluctuate significantly. During the last 12 months, New York Mercantile Exchange West Texas Intermediate oil prices have been volatile and ranged from a high of $105.34 per barrel in July 2014 to a low of $43.46 in March 2015. New York Mercantile Exchange Henry Hub natural-gas prices have also been volatile and ranged from a high of $4.49 per MMBtu in November 2014 to a low of $2.49 in April 2015. The duration and magnitude of the decline in oil and natural-gas prices cannot be predicted.

The Company has a deep portfolio of investment opportunities and the financial strength and operational flexibility to move capital spending from areas focused on near-term production growth to areas focused on longer-term growth where anticipated returns are less sensitive to spot oil and natural-gas prices. The recent decline in oil prices resulted in the Company significantly reducing its capital expenditures in 2015 compared to 2014. The Company will continue to evaluate the oil and natural-gas price environments and may adjust its capital spending plans as prices fluctuate while maintaining appropriate liquidity and financial flexibility.

The Company is committed to the execution of its worldwide exploration, appraisal, and development programs. The Company estimates a 2015 capital spending range of $6.0 billion to $6.4 billion. This amount includes approximately $630 million to $690 million of WES capital expenditures, excluding any acquisitions made by WES. The Company has currently allocated approximately 65% of its 2015 capital spending budget to development activities, 15% to exploration activities, and 20% to gathering and processing activities and other business activities. The Company currently expects its 2015 capital spending by area to be approximately 55% for the U.S. onshore region and Alaska, 10% for the Gulf of Mexico, 20% for Midstream and other, and 15% for International.

Anadarko believes that its cash on hand, available borrowing capacity, and expected level of operating cash flows will be sufficient to fund the Company’s projected operational and capital programs for 2015 and continue to meet its other current obligations. The Company’s cash on hand is available for use and could be supplemented, as needed, with available borrowing capacity under the 364-Day Facility, Five-Year Facility, and commercial paper program. The Company may also enter into carried-interest arrangements with third parties to fund certain capital expenditures, execute asset divestitures, and sell WGP common units that it owns in order to supplement cash flow.

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The Company continuously monitors its liquidity needs, coordinates its capital expenditure program with its expected cash flows and evaluates available funding alternatives in light of current and expected conditions. To reduce commodity-price risk and increase the predictability of 2015 cash flows, Anadarko entered into strategic derivative positions covering approximately 37% of its remaining 2015 anticipated natural-gas sales volumes. In addition, the Company has derivative positions in place for 2016. See Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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.

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. In addition, foreign-currency exchange-rate risk exists due to anticipated foreign-currency denominated payments and receipts. 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. Both exchange- and over-the-counter-traded derivative instruments may be subject to margin-deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 6—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 natural gas, oil, 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. 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. 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 210 Bcf of natural gas and 10 MMBbls of oil at June 30, 2015, with a net derivative asset position of $124 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $76 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $67 million. However, any cash received or paid to settle these derivatives would be substantially offset by the sales value of production covered by the derivative instruments.

Derivative Instruments Held for Trading Purposes At June 30, 2015, the Company had a net derivative asset position of $11 million on outstanding derivative instruments entered into for trading purposes. Based on actual derivative contractual volumes, a 10% increase or decrease in underlying commodity prices would not materially impact the Company’s gains or losses on these derivative instruments.

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INTEREST-RATE RISK Borrowings under each of the 364-Day Facility, the Five-Year Facility, the commercial paper program, and WES’s RCF are subject to variable interest rates. The balance of Anadarko’s long-term debt on the Company’s Consolidated Balance Sheets has fixed interest rates. The Company has $2.9 billion of obligations based on the London Interbank Offered Rate (LIBOR) that are presented on the Company’s Consolidated Balance Sheets net of preferred investments in two non-controlled 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 fair value of outstanding fixed-rate debt.

At June 30, 2015, the Company had a net derivative liability position of $1.1 billion related to interest-rate swaps. A 10% increase (decrease) in the three-month LIBOR interest-rate curve would increase (decrease) the aggregate fair value of outstanding interest-rate swap agreements by $111 million. However, any change in the interest-rate derivative gain or loss could be substantially offset by changes in actual borrowing costs associated with future debt issuances. For a summary of the Company’s outstanding interest-rate derivative positions, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

FOREIGN-CURRENCY EXCHANGE-RATE RISK Anadarko’s operating revenues are denominated in U.S. dollars, and the predominant portion of Anadarko’s capital and operating expenditures are also U.S.-dollar-denominated. Exposure to foreign-currency risk generally arises in connection with project-specific contractual arrangements and other commitments. Near-term foreign-currency-denominated expenditures are primarily in euros, Brazilian reais, British pounds sterling, Mozambican meticais, and Colombian pesos. Management periodically engages in various risk-management activities to mitigate a portion of its exposure to foreign-currency exchange-rate risk.

The Company has risk related to exchange-rate changes applicable to cash held in escrow pending final determination of the Company’s Brazilian tax liability for its 2008 divestiture of the Peregrino field offshore Brazil. The Brazilian tax matter is currently under consideration by the Brazilian courts. At June 30, 2015, cash of $110 million was held in escrow. A 10% increase or decrease in the foreign-currency exchange rate would not materially impact the Company’s gain or loss related to foreign currency.

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 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, 2015.

Changes in Internal Control over Financial Reporting

There were no changes in Anadarko’s internal control over financial reporting during the second quarter of 2015 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

GENERAL The Company is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the ordinary course of business, including, but not limited to, personal injury claims; property damage claims; title disputes; tax disputes; royalty claims; contract claims; contamination claims relating to oil and gas 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, 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 with respect to alleged noncompliance with the leak detection and repair requirements of the Clean Air Act at its Granger, Wyoming facilities. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.

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 material developments with respect to matters previously reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, and material matters that have arisen since the filing of such report.

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, 2014.

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 2015.



Period	Total number of shares purchased ⁽¹⁾	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs	Approximate dollar value of shares that may yet be purchased under the plans or programs
April 1 - 30, 2015	3,051	$	87.32	—
May 1 - 31, 2015	3,313	$	86.37	—
June 1 - 30, 2015	3,779	$	84.47	—
Total	10,143	$	85.95	—	$	—

____________________________________________________________


⁽¹⁾	During the second quarter of 2015, all purchased shares related to stock received by the Company for the payment of withholding taxes due on employee stock plan share issuances.

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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 May 11, 2015, filed as Exhibit 3.1 to Form 8-K filed on May 15, 2015
	4	(i)	Purchase Contract Agreement, dated June 10, 2015, between Anadarko Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A., filed as Exhibit 4.1 to Form 8-K filed on June 10, 2015
		(ii)	Trustee Indenture, dated as of September 19, 2006, Anadarko Petroleum Corporation to The Bank of New York Trust Company, N.A., filed as Exhibit 4.1 to Form 8-K filed on September 19, 2006
		(iii)	Third Supplemental Indenture dated as of June 10, 2015, between Anadarko Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A., filed as Exhibit 4.2 to Form 8-K filed on June 10, 2015
		(iv)	Form of Unit (included in Exhibit 4.i)
		(v)	Form of Purchase Contract (included in Exhibit 4.i)
		(vi)	Form of Amortizing Note (included in Exhibit 4.iii)
*	10	(i)	Anadarko Petroleum Corporation Key Employee Change of Control Contract, dated June 1, 2015, for Christopher O. Champion
*		(ii)	First Amendment to Time Sharing Agreement between R.A. Walker and Anadarko Petroleum Corporation, dated June 2, 2015
*	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 28, 2015	By:	/s/ ROBERT G. GWIN
		Robert G. Gwin Executive Vice President, Finance and Chief Financial Officer

EXHIBIT 10(i)

ANADARKO PETROLEUM CORPORATION

KEY EMPLOYEE CHANGE OF CONTROL CONTRACT

This Anadarko Petroleum Corporation Key Employee Change of Control Contract (“Agreement”) is made and entered into by and between Anadarko Petroleum Corporation (“Company”) and Christopher O. Champion (“Executive”), effective as of June 1, 2015 (“Effective Date”). Company and Executive may be collectively referred to herein as the “Parties.”

The Board of Directors of the Company (the “Board”), has determined that it is in the best interests of the Company and its shareholders to assure that the Company will have the continued dedication of the Executive, notwithstanding the possibility, threat or occurrence of a Change of Control (as defined below) of the Company. The Board believes it is imperative to diminish the inevitable distraction of the Executive by virtue of the personal uncertainties and risks created by a pending or threatened Change of Control and to encourage the Executive’s full attention and dedication to the Company currently and in the event of any threatened or pending Change of Control, and to provide the Executive with compensation and benefits arrangements upon a Change of Control which ensure that the compensation and benefits expectations of the Executive will be satisfied and which are competitive with those of other corporations. Therefore, in order to accomplish these objectives, the Board has caused the Company to enter into this Agreement.

NOW, THEREFORE, IT IS HEREBY AGREED AS FOLLOWS:

1. Certain Definitions.

(a) The “Change of Control Date” shall mean the first date during the Change of Control Period (as defined in Section 1(b)) on which a Change of Control (as defined in Section 2) occurs. Anything in this Agreement to the contrary notwithstanding, if a Change of Control occurs and if the Executive’s employment with the Company is terminated prior to the date on which the Change of Control occurs, and if it is reasonably demonstrated by the Executive that such termination of employment (i) was at the request of a third party who has taken steps reasonably calculated to effect a Change of Control or (ii) otherwise arose in connection with or anticipation of a Change of Control, then for all purposes of this Agreement the “Change of Control Date” shall mean the date immediately prior to the date of such termination of employment.

(b) The “Change of Control Period” shall mean the period commencing on the Effective Date hereof and ending on the second anniversary of such Effective Date; provided, however, that commencing on the date one year after the Effective Date hereof, and on each annual anniversary of such date (such date and each annual anniversary thereof shall be hereinafter referred to as the “Renewal Date”), unless previously terminated, the Change of Control Period shall be automatically extended so as to terminate two years from such Renewal Date, unless at least 90 days prior to the Renewal Date the Company shall give notice to the Executive that the Change of Control Period shall not be so extended.

2. Change of Control. For the purpose of this Agreement, a “Change of Control” shall mean:

(a) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (i) the then outstanding shares of common stock of the Company (the “Outstanding Company Common Stock”) or (ii) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”); provided, however, that for purposes of this subsection (a), the following acquisitions shall not constitute a Change of Control: (i) any acquisition directly from the Company, (ii) any acquisition by the Company, (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company or (iv) any acquisition pursuant to a transaction which complies with clauses (i), (ii) and (iii) of Section 2(c); or

(b) Individuals who, as of the date hereof, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company’s shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or

(c) Consummation by the Company of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Company or the acquisition of assets of another entity (a “Business Combination”), in each case, unless, following such Business Combination, (i) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 60% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (ii) no Person (excluding any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 20% or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership existed prior to the Business Combination, and (iii) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the

execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or

(d) Approval by the shareholders of the Company of a complete liquidation or dissolution of the Company.

3. Employment Period. The Company hereby agrees to continue the Executive in its employ, and the Executive hereby agrees to remain in the employ of the Company subject to the terms and conditions of this Agreement, for the period commencing on the Change of Control Date and ending on the second anniversary of such date (the “Employment Period”).

4. Terms of Employment.

(a) Position and Duties.

(i) During the Employment Period, (A) the Executive’s position (including status, offices, titles and reporting requirements), authority, duties and responsibilities shall be at least commensurate in all material respects with the most significant of those held, exercised and assigned to the Executive at any time during the 120‑day period immediately preceding the Change of Control Date and (B) the Executive’s services shall be performed at the location where the Executive was employed immediately preceding the Change of Control Date or any office or location less than 35 miles from such location.

(ii) During the Employment Period, and excluding any periods of vacation and sick leave to which the Executive is entitled, the Executive agrees to devote reasonable attention and time during normal business hours to the business and affairs of the Company and, to the extent necessary to discharge the responsibilities assigned to the Executive hereunder, to use the Executive’s reasonable best efforts to perform faithfully and efficiently such responsibilities. During the Employment Period it shall not be a violation of this Agreement for the Executive to (A) serve on corporate, civic or charitable boards or committees, (B) deliver lectures, fulfill speaking engagements or teach at educational institutions, and (C) manage personal investments, so long as such activities do not significantly interfere with the performance of the Executive’s responsibilities as an employee of the Company in accordance with this Agreement. It is expressly understood and agreed that to the extent that any such activities have been conducted by the Executive prior to the Change of Control Date, the continued conduct of such activities (or the conduct of activities similar in nature and scope thereto) subsequent to the Change of Control Date shall not thereafter be deemed to interfere with the performance of the Executive’s responsibilities to the Company.

(b) Compensation.

(i) Base Salary. During the Employment Period, the Executive shall receive an annual base salary (“Annual Base Salary”), which shall be paid at a monthly rate, at least' equal to twelve times the highest monthly base salary paid or payable, including any base salary which has been earned but deferred, to the Executive by the Company and its affiliated companies in respect of the twelve-month period immediately preceding the month in which the Change of Control Date occurs. During the Employment Period, the Annual Base Salary shall be reviewed no more than 12 months after the last salary increase awarded to the Executive prior to

the Change of Control Date and thereafter at least annually. Any increase in Annual Base Salary shall not serve to limit or reduce any other obligation to the Executive under this Agreement. Annual Base Salary shall not be reduced after any such increase and the term Annual Base Salary as utilized in this Agreement shall refer to Annual Base Salary as so increased. As used in this Agreement, the term “affiliated companies” shall include any company controlled by, controlling or under common control with the Company.

(ii) Annual Bonus. In addition to Annual Base Salary, the Executive shall be awarded, for each fiscal year ending during the Employment Period, an annual bonus (the “Annual Bonus”) in cash at least equal to the Executive’s target annual bonus under the Company’s Annual Incentive Bonus Program, or any comparable bonus under any predecessor or successor plan, for the fiscal year in which the Change of Control Date occurs, which shall be calculated as follows: (A) the target bonus percentage as established by the Board prior to the Change of Control Date for the fiscal year in which the Change of Control Date occurs, multiplied by (B) the Executive’s Annual Base Salary (the “Recent Annual Bonus”). In the event that, prior to the Change of Control Date, the Executive’s target bonus percentage has not been established by the Board under the Annual Incentive Bonus Program or any comparable bonus under any predecessor or successor plan, then for purposes of this Agreement, the Executive’s Recent Annual Bonus shall be calculated by using the target bonus percentage for the other executives in the Executive’s peer group (determined based on title, responsibilities and duties) who are parties to a Key Employee Change of Control Contract with the Company. Such Annual Bonus shall be paid no later than January 31 of the fiscal year next following the fiscal year for which the Annual Bonus is awarded, unless the Executive shall elect to defer the receipt of such Annual Bonus in accordance with procedures established by the Company that comply with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”).

(iii) Incentive, Savings and Retirement Plans. During the Employment Period, the Executive shall be entitled to participate in all incentive, savings and retirement plans, practices, policies and programs applicable generally to other peer executives of the Company and its affiliated companies, but in no event shall such plans, practices, policies and programs provide the Executive with incentive opportunities (measured with respect to regular, annual incentive opportunities), savings opportunities and retirement benefit opportunities, in each case, less favorable, in the aggregate, than the most favorable of those provided by the Company and its affiliated companies for the Executive under such plans, practices, policies and programs as in effect at any time during the 120‑day period immediately preceding the Change of Control Date or if more favorable to the Executive, those provided generally at any time after the Change of Control Date to other peer executives of the Company and its affiliated companies.

(iv) Welfare Benefit Plans. During the Employment Period, the Executive and/or the Executive’s family, as the case may be, shall be eligible for participation in and shall receive all benefits under welfare benefit plans, practices, policies and programs provided by the Company and its affiliated companies (including, without limitation, medical, prescription, dental, disability, salary continuance, employee life, group life, accidental death and travel accident insurance plans and programs) to the extent applicable generally to other peer executives of the Company and its affiliated companies, but in no event shall such plans, practices, policies and programs provide the Executive with benefits which are less favorable, in the aggregate, than the most favorable of such plans, practices, policies and programs in effect for the Executive at

any time during the 120‑day period immediately preceding the Change of Control Date or, if more favorable to the Executive, those provided generally at any time after the Change of Control Date to other peer executives of the Company and its affiliated companies.

(v) Expenses. During the Employment Period, the Executive shall be entitled to receive prompt reimbursement for all reasonable expenses incurred by the Executive in accordance with the most favorable policies, practices and procedures of the Company and its affiliated companies in effect for the Executive at any time during the 120‑day period immediately preceding the Change of Control Date or, if more favorable to the Executive, as in effect generally at any time thereafter with respect to other peer executives of the Company and its affiliated companies.

(vi) Fringe Benefits. During the Employment Period, the Executive shall be entitled to fringe benefits in accordance with the most favorable plans, practices, programs and policies of the Company and its affiliated companies in effect for the Executive at any time during the 120‑day period immediately preceding the Change of Control Date or, if more favorable to the Executive, as in effect generally at any time thereafter with respect to other peer executives of the Company and its affiliated companies.

(vii) Office and Support Staff. During the Employment Period, the Executive shall be entitled to an office or offices of a size and with furnishings and other appointments, and to exclusive personal secretarial and other assistance, at least equal to the most favorable of the foregoing provided to the Executive by the Company and its affiliated companies at any time during the 120‑day period immediately preceding the Change of Control Date or, if more favorable to the Executive, as provided generally at any time thereafter with respect to other peer executives of the Company and its affiliated companies.

(viii) Paid Time Off. During the Employment Period, the Executive shall be entitled to paid time off in accordance with the most favorable plans, policies, programs and practices of the Company and its affiliated companies as in effect for the Executive at any time during the 120‑day period immediately preceding the Change of Control Date or, if more favorable to the Executive, as in effect generally at any time thereafter with respect to other peer executives of the Company and its affiliated companies.

5. Termination of Employment.

(a) Death or Disability. The Executive’s employment shall terminate automatically upon the Executive’s death during the Employment Period. If the Company determines in good faith that the Disability of the Executive has occurred during the Employment Period (pursuant to the definition of Disability set forth below), it may give to the Executive written notice in accordance with Section 12(b) of this Agreement of its intention to terminate the Executive’s employment. In such event, the Executive’s employment with the Company shall terminate effective on the 30th day after receipt of such notice by the Executive (the “Disability Effective Date”), provided that, within the 30 days after such receipt, the Executive shall not have returned to full-time performance of the Executive’s duties. For purposes of this Agreement, “Disability” shall mean the absence of the Executive from the Executive’s duties with the Company on a full-time basis for 180 consecutive business days as a result of incapacity due to

mental or physical illness which is determined to be total and permanent by a physician selected by the Company or its insurers and acceptable to the Executive or the Executive’s legal representative.

(b) By the Company. The Company may terminate the Executive’s employment during the Employment Period for Cause, or without Cause. For purposes of this Agreement, “Cause” shall mean:

(i) the willful and continued failure of the Executive to perform substantially the Executive’s duties with the Company or one of its affiliates (other than any such failure resulting from incapacity due to physical or mental illness), after a written demand for substantial performance is delivered to the Executive by the Board or the Chief Executive Officer of the Company which specifically identifies the manner in which the Board or Chief Executive Officer believes that the Executive has not substantially performed the Executive’s duties, or

(ii) the willful engaging by the Executive in illegal conduct or gross misconduct which is materially and demonstrably injurious to the Company.

For purposes of this provision, no act or failure to act, on the part of the Executive, shall be considered “willful” unless it is done, or omitted to be done, by the Executive in bad faith or without reasonable belief that the Executive’s action or omission was in the best interests of the Company. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board or upon the instructions of the Chief Executive Officer or a senior officer of the Company or based upon the advice of counsel for the Company shall be conclusively presumed to be done, or omitted to be done, by the Executive in good faith and in the best interests of the Company. The cessation of employment of the Executive shall not be deemed to be for Cause unless and until there shall have been delivered to the Executive a copy of a resolution duly adopted by the affirmative vote of not less than three-quarters of the entire membership of the Board at a meeting of the Board called and held for such purpose (after reasonable notice is provided to the Executive and the Executive is given an opportunity, together with counsel, to be heard before the Board), finding that, in the good faith opinion of the Board, the Executive is guilty of the conduct described in subparagraph (i) or (ii) above, and specifying the particulars thereof in detail.

(c) By the Executive. The Executive’s employment may be terminated by the Executive for Good Reason, or without Good Reason. For purposes of this Agreement, Good Reason shall mean:

(i) the assignment to the Executive of any duties inconsistent in any respect with the Executive’s position (including status, offices, titles and reporting requirements), authority, duties or responsibilities as contemplated by Section 4(a) of this Agreement, or any other action by the Company which results in a diminution in such position, authority, duties or responsibilities, excluding for this purpose an isolated, insubstantial and inadvertent action not taken in bad faith and which is remedied by the Company promptly after receipt of notice thereof given by the Executive;

(ii) any failure by the Company to comply with any of the provisions of Section 4(b) of this Agreement, other than an isolated, insubstantial and inadvertent failure not

occurring in bad faith and which is remedied by the Company promptly after receipt of notice thereof given by the Executive;

(iii) the Company requiring the Executive to be based at any office or location other than as provided in Section 4(a)(i)(B) hereof, or the Company requiring the Executive to travel on Company business to a substantially greater extent than required immediately prior to the Change of Control Date;

(iv) any purported termination by the Company of the Executive’s employment otherwise than as expressly permitted by this Agreement; or

(v) any failure by the Company to comply with and satisfy Section 11(c) of this Agreement.

For purposes of this Section 5(c), any good faith determination of “Good Reason” made by the Executive shall be conclusive.

(d) Notice of Termination. Any termination by the Company for Cause, or by the Executive for Good Reason, shall be communicated by Notice of Termination to the other party hereto given in accordance with Section 12(b) of this Agreement. For purposes of this Agreement, a “Notice of Termination” means a written notice which (i) indicates the specific termination provision in this Agreement relied upon, (ii) to the extent applicable, sets forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of the Executive’s employment under the provision so indicated, and (iii) if the Date of Termination (as defined below) is other than the date of receipt of such notice, specifies the termination date (which date shall be not more than thirty days after the giving of such notice). The failure by the Executive or the Company to set forth in the Notice of Termination any fact or circumstance which contributes to a showing of Good Reason or Cause shall not waive any right of the Executive or the Company, respectively, hereunder or preclude the Executive or the Company, respectively, from asserting such fact or circumstance in enforcing the Executive’s or the Company’s rights hereunder.

(e) Date of Termination. “Date of Termination” means (i) if the Executive’s employment is terminated by the Company for Cause, or by the Executive for Good Reason, the date of receipt of the Notice of Termination or any later date specified therein, as the case may be, (ii) if the Executive’s employment is terminated by the Company other than for Cause or Disability, the date on which the Company notifies the Executive of such termination, (iii) if the Executive’s employment is terminated by the Executive without Good Reason, the date of receipt of the Notice of Termination or any later date specified therein (which date shall be not later than 30 days after the giving of such notice), and (iv) if the Executive’s employment is terminated by reason of death or Disability, the date of death of the Executive or the Disability Effective Date, as the case may be.

6. Obligations of the Company upon Termination.

(a) Good Reason; Other Than for Cause, Death or Disability. If, during the Employment Period, the Company shall terminate the Executive’s employment other than for

Cause, Death or Disability or the Executive shall terminate employment for Good Reason, the Company shall provide the Executive with the following compensation and benefits.

(i) The Company shall pay to the Executive in a lump sum in cash within 20 days after the Date of Termination the aggregate of the amounts set forth in the following subsections (A) through (E), except as provided in Section 6(e):

(A)

the sum of (1) the Executive’s Annual Base Salary through the Date of Termination to the extent not theretofore paid, (2) the product of (x) the higher of (I) the highest annual bonus earned by the Executive for the last three fiscal years prior to the Change of Control Date, (II) in the case of the Change of Control Date occurring during the first 36 months following the date of this agreement, $490,000, and (III) the Annual Bonus paid or payable for the most recently completed fiscal year during the Employment Period, in each case, including any bonus or portion thereof which has been earned but deferred (and annualized for any fiscal year consisting of less than twelve full months or during which the Executive was employed for less than twelve full months) (such higher amount being referred to as the “Highest Annual Bonus”) and (y) a fraction, the numerator of which is the number of days in the current fiscal year through the Date of Termination, and the denominator of which is 365, and (3) any accrued paid time off, to the extent not theretofore used or paid (the sum of the amounts described in clauses (1), (2), and (3) shall be hereinafter referred to as the “Accrued Obligations”); and


(B)	an amount equal to the product of (1) two and (2) the sum of (x) the Executive’s Annual Base Salary and (y) the Highest Annual Bonus; and

(C)

an amount equal to the total value of the Executive’s Account (as defined in the Company’s Savings Restoration Plan (the “SRP”)), with such amount being the higher of (1) the value of the Executive’s Account on the Executive’s Date of Termination or (2) the value of the Executive’s Account on the Change of Control Date, in each case with “value” determined under the applicable change of control provisions in the SRP, if any. The amount payable under this Section 6(a)(i)(C) shall represent the payment of the amount due to the Executive under the SRP, and shall not be duplicative thereof. Notwithstanding the above provisions of this Section 6(a)(i)(C), the Company shall pay the lump sum cash payment as set forth herein above only if such payment would not be considered to be an impermissible acceleration of benefits under the SRP under Code Section 409A. In the event that the payment of the benefits payment in a lump sum would constitute an impermissible acceleration of benefits under the SRP under Code Section 409A, then the portion

of the benefit payable under this Section 6(a)(i)(C) that is equal to the benefits payable under the SRP shall be payable in the same form and at the time specified in the SRP, and any excess amount determined under this paragraph shall, subject to Section 6(e), be paid in a cash lump sum within 20 days after the Date of Termination; and

(D)

an amount equal to the additional Company matching contributions which would have been made on the Executive’s behalf in the Company’s Employee Savings Plan (the “ESP”) (assuming continued participation on the same basis as immediately prior to the Change of Control Date), plus the additional amount of any benefit the Executive would have accrued under the SRP as a result of contribution limitations in the ESP, for the 24-month period beginning on the Date of Termination (with the Company’s matching contributions being determined pursuant to the applicable provisions of the ESP and the SRP and based upon the Executive’s compensation (including any amounts deferred pursuant to any deferred compensation program) in effect for the 12-month period immediately prior to the Change of Control Date); and

(E)

an amount equal to the sum of the present values, as of the Date of Termination, of (1) the accrued retirement benefit payable under the Company’s Retirement Restoration Plan (or, if the Executive participates in another plan that, in the sole determination of the Company, is intended to provide benefits similar to those under the Company’s Retirement Restoration Plan, such other plan) (each referred to herein as the “RRP”) and (2) the additional retirement benefits that the Executive would have accrued under the tax-qualified defined benefit plan of the Company or any Affiliate in which the Executive participates (the “Retirement Plan”) and the RRP if the Executive had continued employment until the expiration of the two-year period following the Date of Termination (assuming that the Executive’s compensation in each of the additional years is that required by Section 4(b)(i) and Section 4(b)(ii) hereof), with the present values being computed by discounting to the Date of Termination the accrued benefit and the additional retirement benefits payable as lump sums at an assumed benefit commencement date of the later of (i) the date the Executive attains age 55 and (ii) the date two years after the Date of Termination, at the rate of interest used for valuing lump-sum payments in excess of $25,000 for participants with retirement benefits commencing immediately under the Retirement Plan, as in effect as of the Change of Control Date with such amount to be fully offset and reduced by the amount of any additional benefit provided under the Retirement Plan or the RRP in connection with the Change of Control or the Executive’s termination of employment in connection with the

Change of Control, including an amount that the Company determines, in its sole discretion, is intended to provide a similar or supplemental benefit (or, if the Executive does not participate in a Retirement Plan or RRP as of the date of the Executive’s termination of employment, such other amount as the Company may chose, in its sole discretion, to approximate this benefit).

(ii) The Company shall, at its sole expense as incurred, provide the Executive with outplacement services at a cost to the Company not to exceed $30,000, the scope and provider of which shall be selected by the Executive in the Executive’s sole discretion; provided, however, that such outplacement services as provided in this Section 6(a)(ii) shall be limited to qualifying expenses incurred, or services provided by the Company, during the period ending on the last day of the second calendar year following the calendar year containing the Date of Termination, and any reimbursements by the Company shall be made not later than the last day of the third calendar year following the calendar year containing the Date of Termination; and

(iii) Until the second anniversary of the Date of Termination, the Company shall maintain in full force and effect for the Executive all life, accident, disability, medical and health care benefit plans, programs and arrangements in which the Executive was entitled to participate, at the same rates and levels (which levels may vary based on the Executive’s age in accordance with the terms of the applicable plans, programs and arrangements), in which the Executive was participating immediately prior to the Change of Control Date, provided that the Executive’s continued participation is possible under the general terms and provisions of such plans, programs and arrangements; and further provided that (A) if the Executive becomes reemployed with another employer and is eligible to receive medical or other welfare benefits under another employer-provided plan, the medical and other welfare benefits described herein shall be secondary to those provided under such other plan during such applicable period of eligibility, and (B) the medical and other welfare benefits described herein shall be subject to the application of any Medicare or other coordination of benefits provisions under the applicable medical or welfare benefit plan, program or arrangement. In the event that the Executive’s participation in any such plan, program or arrangement is barred due to the eligibility and participation requirements of such plan or program as then in effect, the Company shall arrange to provide benefits substantially similar to those to which the Executive was entitled to receive under such plans and programs of the Company prior to the Change of Control Date. In such event, appropriate adjustments shall be made so that the after-tax value thereof to the Executive is similar to the after-tax value of the benefit plans in which participation is barred.

Benefits provided pursuant to this Section 6(a)(iii) are contractual only and are not to be considered a continuation of coverage as provided under Code Section 4980B (i.e., COBRA continuation coverage). For purposes of determining the Executive’s eligibility (but not the time of commencement of coverage) for retiree benefits pursuant to such plans and programs, the Executive shall be considered to have remained employed until two years after the Date of Termination and to have retired on the last day of such period, and, if the Executive satisfies the eligibility requirements, such benefits shall commence no later than the expiration of the two-year continuation period provided in the first sentence of this Section 6(a)(iii).

The continued coverage under this Section 6(a)(iii) shall be provided at the Company’s discretion in a manner that is intended to satisfy an exception to Code Section 409A, and therefore not be treated as an arrangement providing for nonqualified deferred compensation that is subject to taxation under Code Section 409A, or in a manner that otherwise complies with Code Section 409A, including without limitation (1) providing such benefits on a nontaxable basis to the Executive, (2) providing for the reimbursement of medical expenses incurred during the period of time during which the Executive would be entitled to continuation coverage under a group health plan of the Company under Code Section 4980B (i.e., COBRA continuation coverage), (3) providing that such benefits constitute the reimbursement or provision of in-kind benefits payable at a specified time or pursuant to a fixed schedule as permitted under Code Section 409A and the authoritative guidance thereunder, or (4) requiring the Executive to pay the actual cost of such coverage and having the Company reimburse the Executive for such payments in excess of the rates that would otherwise be required to be paid by the Executive under the preceding provisions of this Section 6(a)(iii) (with such reimbursement, less applicable taxes, for a particular calendar year during which the Executive received such coverage to be made within 15 days following the end of such calendar year (but in no event prior to the date that is six months after the Date of Termination)).

(iv) To the extent not theretofore paid or provided, the Company shall timely pay or provide to the Executive any other amounts or benefits required to be paid or provided or which the Executive is eligible to receive under any plan, program, policy or practice or contract or agreement of the Company and its affiliated companies (such other amounts and benefits shall be hereinafter referred to as the “Other Benefits”).

(b) Death. If the Executive’s employment is terminated by reason of the Executive’s death during the Employment Period, this Agreement shall terminate without further obligations to the Executive’s legal representatives under this Agreement, other than for payment of Accrued Obligations and the timely payment or provision of Other Benefits. Accrued Obligations shall be paid to the Executive’s estate or beneficiary, as applicable, in a lump sum in cash within 20 days of the Date of Termination. With respect to the provision of Other Benefits, the term Other Benefits as utilized in this Section 6(b) shall include, without limitation, and the Executive’s estate and/or beneficiaries shall be entitled to receive, benefits equal to the most favorable benefits provided by the Company and affiliated companies to the estates and beneficiaries of peer executives of the Company and such affiliated companies under such plans, programs, practices and policies relating to death benefits, if any, as in effect with respect to other peer executives and their beneficiaries at any time during the 120‑day period immediately preceding the Change of Control Date or, if more favorable to the Executive’s estate and/or the Executive’s beneficiaries, as in effect on the date of the Executive’s death with respect to other peer executives of the Company and its affiliated companies and their beneficiaries.

(c) Disability. If the Executive’s employment is terminated by reason of the Executive’s Disability during the Employment Period, this Agreement shall terminate without further obligations to the Executive, other than for payment of Accrued Obligations and the timely payment or provision of Other Benefits. Accrued Obligations shall be paid to the Executive in a lump sum in cash within 20 days of the Date of Termination. With respect to the provision of Other Benefits, the term Other Benefits as utilized in this Section 6(c) shall include, and the Executive shall be entitled after the Disability Effective Date to receive, disability and other

benefits at least equal to the most favorable of those generally provided by the Company and its affiliated companies to disabled executives and/or their families in accordance with such plans, programs, practices and policies relating to disability, if any, as in effect generally with respect to other peer executives and their families at any time during the 120‑day period immediately preceding the Change of Control Date or, if more favorable to the Executive and/or the Executive’s family, as in effect at any time thereafter generally with respect to other peer executives of the Company and its affiliated companies and their families.

(d) Cause; Other than for Good Reason. If the Executive’s employment shall be terminated for Cause during the Employment Period, this Agreement shall terminate without further obligations to the Executive other than the obligation to pay to the Executive (i) the Annual Base Salary through the Date of Termination, (ii) the amount of any compensation previously deferred by the Executive, and (iii) Other Benefits, in each case to the extent theretofore unpaid. If the Executive voluntarily terminates employment during the Employment Period, excluding a termination for Good Reason, this Agreement shall terminate without further obligations to the Executive, other than for Accrued Obligations and the timely payment or provision of Other Benefits. In such case, all Accrued Obligations shall be paid to the Executive in a lump sum in cash within 20 days of the Date of Termination.

(e) Matters Relating to Code Section 409A. Notwithstanding any provision in this Agreement to the contrary, if the payment of any benefit hereunder (including, without limitation, any severance benefit) would be subject to additional taxes and interest under Code Section 409A because the timing of such payment is not delayed as provided in Code Section 409A for a “specified employee”, then if the Executive is a “specified employee” under Code Section 409A, any such payment that the Executive would otherwise be entitled to receive during the first six months following the Date of Termination shall be accumulated and paid or provided, as applicable, within ten days after the date that is six months following the Date of Termination, or such earlier date upon which such amount can be paid or provided under Code Section 409A without being subject to such additional taxes and interest. For all purposes of this Agreement, the Executive shall be considered to have terminated employment with the Company when the Executive incurs a “separation from service” with the Company within the meaning of Code Section 409A(a)(2)(A)(i). The Executive agrees to be bound by the Company’s determination of its “specified employees” (as defined in Code Section 409A). Any payment or benefit (including any severance payment or benefit) provided under this Agreement to which Code Section 409A applies that constitutes a reimbursement of expenses incurred by the Executive or the provision of an in-kind benefit to the Executive shall be subject to the following: (i) the amount of expenses eligible for reimbursement, or in-kind benefits provided, during the Executive’s taxable year may not affect the expenses eligible for reimbursement, or in-kind benefits to be provided, in any other taxable year; (ii) the reimbursement of an eligible expense shall be made on or before the last day of the Executive’s taxable year following the taxable year in which the expense was incurred; and (iii) the right to reimbursement or to receive an in-kind benefit shall not be subject to liquidation or exchange by the Executive for another payment or benefit.

7. Non-exclusivity of Rights. Nothing in this Agreement shall prevent or limit the Executive’s continuing or future participation in any plan, program, policy or practice provided by the Company or any of its affiliated companies and for which the Executive may qualify, nor, subject to Section 12(f), shall anything herein limit or otherwise affect such rights as the Executive

may have under any contract or agreement with the Company or any of its affiliated companies. Amounts which are vested benefits or which the Executive is otherwise entitled to receive under any plan, policy, practice or program of or any contract or agreement with the Company or any of its affiliated companies, including, but not limited to, the Company’s Management Life Insurance Plan and Override Pool Bonus Plan, at or subsequent to the Date of Termination shall be payable in accordance with such plan, policy, practice or program or contract or agreement except as explicitly modified by this Agreement. Without limiting the generality of the foregoing, there shall be no duplication of any of the payments or benefits described in Section 6 hereof, and payments under the applicable provisions of Section 6(a)(i) shall be in full satisfaction of the amounts otherwise payable under the SRP, the RRP and the executive deferred compensation plans, respectively.

8. Full Settlement; Legal Fees. The Company’s obligation to make the payments provided for in this Agreement and otherwise to perform its obligations hereunder shall not be affected by any set-off, counterclaim, recoupment, defense or other claim, right or action which the Company may have against the Executive or others. In no event shall the Executive be obligated to seek other employment or take any other action by way of mitigation of the amounts payable to the Executive under any of the provisions of this Agreement and except as specifically provided in Section 6(a)(iii), such amounts shall not be reduced whether or not the Executive obtains other employment. The Company agrees to pay as incurred, to the full extent permitted by law, all legal fees and expenses which the Executive may reasonably incur as a result of any contest (regardless of the outcome thereof) by the Company, the Executive or others of the validity or enforceability of, or liability or entitlement under, any provision of this Agreement or any guarantee of performance thereof (whether such contest is between the Company and the Executive or between either of them and any third party, and including as a result of any contest by the Executive about the amount of any payment pursuant to this Agreement), plus in each case interest on any delayed payment at the applicable Federal rate provided for in Code Section 7872(f)(2)(A).

9. Parachute Payment Limitation.

(a) Anything in this Agreement to the contrary notwithstanding, if the Executive is a “disqualified individual” (as defined in Section 280G of the Code), and the payments and benefits provided for in this Agreement, together with any other payments and benefits which the Executive has the right to receive (collectively, the “Payments”), would constitute a “parachute payment” (as defined in Section 280G of the Code), then the Payments shall be either (a) reduced (but not below zero) so that the aggregate present value of the Payments will be one dollar ($1.00) less than three times the Executive’s “base amount” (as defined in Section 280G of the Code) and so that no portion of the Payments shall be subject to the excise tax imposed by Section 4999 of the Code, or (b) paid in full, whichever produces the better net after-tax result for the Executive (taking into account any applicable excise tax under Section 4999 of the Code and any applicable income tax). The reduction of Payments, if any, shall be made by reducing the Payments in the reverse order in which the Payments would be paid or provided (beginning with such payment or benefit that would be made last in time and continuing, to the extent necessary, through to such payment or benefit that would be made first in time).

(b) The determinations as to the Payments to be reduced and the amount of reduction shall be made by the Company in good faith, and such determinations shall be conclusive and binding on the Executive. If a reduced Payment is made or provided and, through error or otherwise, that Payment, when aggregated with other payments and benefits from the Company (or its affiliated companies) used in determining if a “parachute payment” exists, exceeds one dollar ($1.00) less than three (3) times the Executive’s base amount, the Executive shall immediately repay such excess to the Company upon notification that an overpayment has been made.

10. Confidential Information. The Executive shall hold in a fiduciary capacity for the benefit of the Company all secret or confidential information, knowledge or data relating to the Company or any of its affiliated companies, and their respective businesses, which shall have been obtained by the Executive during the Executive’s employment by the Company or any of its affiliated companies and which shall not be or become public knowledge (other than by acts by the Executive or representatives of the Executive in violation of this Agreement). After termination of the Executive’s employment with the Company, the Executive shall not, without the prior written consent of the Company or as may otherwise be required by law or legal process, communicate or divulge any such information, knowledge or data to anyone other than the Company and those designated by it. In no event shall an asserted violation of the provisions of this Section 10 constitute a basis for deferring or withholding any amounts otherwise payable to the Executive under this Agreement.

11. Successors.

(a) This Agreement is personal to the Executive and without the prior written consent of the Company shall not be assignable by the Executive otherwise than by will or the laws of descent and distribution. This Agreement shall inure to the benefit of and be enforceable by the Executive’s legal representatives.

(b) This Agreement shall inure to the benefit of and be binding upon the Company and its successors and assigns.

(c) The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company to assume expressly and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place. As used in this Agreement, the term “Company” shall mean the Company as hereinbefore defined and any successor to its business and/or assets as aforesaid which assumes and agrees to perform this Agreement by operation of law, or otherwise.

12. Miscellaneous.

(a) This Agreement shall be governed by and construed in accordance with the laws of the State of Texas, without reference to principles of conflict of laws. The captions of this Agreement are not part of the provisions hereof and shall have no force or effect. This Agreement may not be amended or modified otherwise than by a written agreement executed by the parties hereto or their respective successors and legal representatives.

(b) All notices and other communications hereunder shall be in writing and shall be given by hand delivery to the other party or by registered or certified mail, return receipt requested, postage prepaid, addressed, in the case of the Executive, to the Executive’s home address registered with the Company or, if to the Company, to the attention of the General Counsel at the Company’s home office address or to such other address as either party shall have furnished to the other in writing in accordance herewith. Notice and communications shall be effective when actually received by the addressee.

(c) The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement.

(d) The Company may withhold from any amounts payable under this Agreement such Federal, state, local or foreign taxes as shall be required to be withheld pursuant to any applicable law or regulation.

(e) The Executive’s or the Company’s failure to insist upon strict compliance with any provision of this Agreement or the failure to assert any right the Executive or the Company may have hereunder, including, without limitation, the right of the Executive to terminate employment for Good Reason pursuant to Section 5 of this Agreement, shall not be deemed to be a waiver of such provision or right or any other provision or right of this Agreement.

(f) The Executive and the Company acknowledge that, except as may otherwise be provided under any other written agreement between the Executive and the Company, the employment of the Executive by the Company is “at will” and, prior to the Change of Control Date, the Executive’s employment may be terminated by either the Executive or the Company at any time prior to the Change of Control Date, in which case the Executive shall have no further rights under this Agreement. From and after the Effective Date, this Agreement shall supersede any other agreement between the parties with respect to the subject matter hereof.

[Signature page follows.]

IN WITNESS WHEREOF, the Executive has hereunto set the Executive’s hand and, pursuant to the authorization from its Board of Directors, the Company has caused this Agreement to be executed in its name and on its behalf, to be effective as of the Effective Date.



EXECUTIVE:


By:	/s/ CHRISTOPHER O. CHAMPION

Name:	Christopher O. Champion

Date:	6/2/15


ANADARKO PETROLEUM CORPORATION


By:	/s/ JULIE STRUBLE

Name:	Julie Struble

Title:	VP, Human Resources

Date:	6/2/15

EXHIBIT 10(ii)

FIRST AMENDMENT TO TIME SHARING AGREEMENT

THIS FIRST AMENDMENT TO TIME SHARING AGREEMENT (this “Amendment”) is made as of June 2, 2015, by and between Anadarko Petroleum Corporation, a Delaware corporation (the “Operator” or the “Company”), and R. A. Walker (the “Passenger”).

RECITALS

A. The Operator and the Passenger have entered into a Time Sharing Agreement (the “Agreement”), dated as of May 15, 2012, pursuant to which (i) the Operator agreed to make Aircraft, with flight crew, when the Aircraft and flight crew are not otherwise needed for business purposes, available to the Passenger for the Passenger’s personal travel in accordance with the Aircraft Policy on a non-exclusive time-sharing basis in accordance with §91.501 of the FAR and (ii) the Passenger agreed to reimburse the Operator for the personal use of the Aircraft for certain flights as permitted under the FAR, in each case, in accordance with the terms and provisions of the Agreement.

B. The Operator and the Passenger desire to amend the Agreement in accordance with the terms and conditions set forth below.

C. Capitalized terms not otherwise defined herein shall have the meanings ascribed to them in the Agreement.

NOW, THEREFORE, in consideration of the premises and other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the parties agree as follows:

1. Amendments. The Agreement is hereby amended as follows:


(a)	By deleting existing Section 20A(I) in its entirety and inserting in place thereof the following:

20A. Subordination; Consent to Assignment

I. 5491 Aircraft

This Agreement, to the extent it relates to the 5491 Aircraft (as such term is defined below) is subject to the terms and provisions of:

(i)

that certain Aircraft Lease (S/N 5491) and related Lease Supplement (the Aircraft Lease, together with the Lease Supplement and all riders and addenda thereto, the “5491 Aircraft Lease”), each dated as of February 6, 2015, by and between Banc of America Leasing & Capital LLC, a Delaware limited liability company (“BALC”), and APC Aviation, Inc., a Delaware corporation (“APC”), regarding the Gulfstream Aerospace model GV-SP (G550) aircraft bearing United States Registration number N276A and manufacturer’s serial number 5491 (the “5491 Aircraft”);


(ii)	that certain Aircraft Sublease (S/N 5491) and related Sublease Supplement (the Aircraft Sublease, together with the Sublease Supplement and all riders and addenda thereto, the “5491 Aircraft Sublease”), each dated as of February 6, 2015, by and between APC and the Operator regarding the 5491 Aircraft;


(iii)	that certain Consent to Sublease and Assignment (the “5491 Consent”), dated as of February 6, 2015, by and between BALC, APC and the Operator; and


(iv)	any related documents, agreements or instruments of any kind whatsoever relating to the 5491 Aircraft Lease, the 5491 Aircraft Sublease or the 5491 Consent.

Without limiting the generality of the foregoing, the rights of APC, the Operator, the Passenger and any other party, person or entity of any kind whatsoever claiming through any of APC, the Operator or the Passenger with respect to the 5491 Aircraft (and any and all proceeds thereof, including, any insurance proceeds) shall be subject and subordinate in all respects to any and all of the rights, privileges, powers, entitlements, benefits, remedies, title or interests of BALC in or to the 5491 Aircraft (and any and all proceeds thereof, including, any insurance proceeds), including, all of BALC’s respective rights and remedies under or in connection with any of the 5491 Aircraft Lease, the 5491 Aircraft Sublease, the 5491 Consent and any related documents, agreements or instruments of any kind whatsoever (including, without limitation, BALC’s right to repossess the 5491 Aircraft and to terminate this Agreement with respect to the 5491 Aircraft pursuant to the 5491 Aircraft Lease and this Section). In addition, and notwithstanding anything to the contrary set forth in this Agreement or otherwise, upon the occurrence of any Event of Default (as such term is defined in 5491 Aircraft Lease) under or in connection with 5491 Aircraft Lease, this Agreement shall automatically and immediately terminate with respect to the 5491 Aircraft.


(b)	By adding a new Section 20A(III) immediately prior to the existing final paragraph of Section 20(A), which shall read as follows:

III. 2044 Aircraft

This Agreement, to the extent it relates to the 2044 Aircraft (as such term is defined below) is subject to the terms and provisions of:

(v)

that certain Aircraft Lease (S/N 2044) and related Lease Supplement (the Aircraft Lease, together with the Lease Supplement and all riders and addenda thereto, the “2044 Aircraft Lease”), each dated as of April 30, 2015, by and between WFEFI and APC regarding the Gulfstream Aerospace model IAI Ltd. Gulfstream 280 (G280) aircraft bearing United States Registration number N855A and manufacturer’s serial number 2044 (the “2044 Aircraft”);


(vi)	that certain Aircraft “Dry” Lease Agreement (together with all supplements, riders and addenda thereto, the “2044 Aircraft “Dry” Lease”), dated as of August 1, 2014, by and between APC and the Operator regarding the 2044 Aircraft;


(vii)	that certain Collateral Assignment of Aircraft “Dry” Lease Agreement (the “2044 Assignment”), dated as of April 30, 2015, by and between WFEFI, APC and the Operator; and


(viii)	any related documents, agreements or instruments of any kind whatsoever relating to the 2044 Aircraft Lease, the 2044 Aircraft “Dry” Lease or the 2044 Assignment.

Without limiting the generality of the foregoing, the rights of APC, the Operator, the Passenger and any other party, person or entity of any kind whatsoever claiming through any of APC, the Operator or the Passenger with respect to the 2044 Aircraft (and any and all proceeds thereof, including, any insurance proceeds) shall be subject and subordinate in all respects to any and all of the rights, privileges, powers, entitlements, benefits, remedies, title or interests of WFEFI in or to the 2044 Aircraft (and any and all proceeds thereof, including, any insurance proceeds), including, all of WFEFI’s respective rights and remedies under or in connection with any of the 2044 Aircraft Lease, the 2044 Aircraft “Dry” Lease, the 2044 Assignment and any related documents, agreements or instruments of any kind whatsoever (including, without limitation, WFEFI’s right to repossess the 2044 Aircraft and to terminate this Agreement with respect to the 2044 Aircraft). In addition, and notwithstanding anything to the contrary set forth in this Agreement or otherwise, upon the occurrence of any Event of Default (as such term is defined in 2044 Aircraft Lease) under or in connection with 2044 Aircraft Lease, this Agreement shall automatically and immediately terminate with respect to the 2044 Aircraft.


(c)	By deleting the existing final paragraph of Section 20(A) in its entirety and inserting in place thereof the following:

Without limiting the generality of any terms or provisions of this Agreement or otherwise, Passenger hereby acknowledges and consents to the assignment by Operator of Operator’s right, title and interest in and to this Agreement (i) as it relates to the 5491 Aircraft to BALC and its successors and assigns and (ii) as it relates to the 5307 Aircraft and the 2044 Aircraft to WFEFI and its successors and assigns.


(d)	By deleting in its entirety Schedule A attached to the Agreement and replacing it in its entirety with the Schedule A attached hereto.

2. References to Agreement. From and after the date of this Amendment, each and every reference to “this Agreement” in the Agreement or to “the Agreement” in the Agreement and any related documents is deemed for all purposes to reference the Agreement as amended pursuant to this Amendment unless the context clearly indicates or dictates a contrary meaning.

3. Miscellaneous.


(a)	This Amendment constitutes the entire agreement among the Operator and the Passenger with respect to the amendment of the Agreement contemplated hereby and completely and fully supersedes all other prior agreements, both written and oral, among the Operator and the Passenger relating thereto.


(b)	The Operator and the Passenger each hereby ratifies and confirms in all respects all of its obligations under the Agreement and agrees that, except to the extent expressly modified by this Amendment, the Agreement continues in full force and effect as if set forth specifically herein.


(c)	All of the terms and conditions of this Amendment shall survive the execution and delivery of this Amendment. This Amendment may be executed in any number of counterparts, all of which when taken together shall constitute but a single instrument. The headings in this Amendment are for convenience only and shall not limit or otherwise affect any of the terms hereof.


(d)	In the event that any provision of this Amendment is for any reason held to be invalid, illegal or unenforceable, in whole or in part or in any respect, then such provision only shall be deemed null and void and shall not affect any other provision hereof, and the remaining provisions shall remain operative and in full force and effect.


(e)	This Amendment shall be construed and enforced in accordance with, and the rights of the parties shall be governed by, the internal laws of the State of Texas, without regard to its choice of law principles

[SIGNATURES ON NEXT PAGE]

IN WITNESS WHEREOF, the parties have caused this Amendment to be executed by their respective duly authorized representatives as of the date first above written.



Operator:

ANADARKO PETROLEUM CORPORATION


By:	/s/ ROBERT K. REEVES
Name:	Robert K. Reeves
Title:	EVP, General Counsel and CAO


Passenger:

	/s/ R. A. WALKER
Name:	R.A. Walker

SCHEDULE A



Type of Aircraft	U.S. Registration Number	Manufacturer Serial Number
Gulfstream G280	N855A	2044
Gulfstream G550	N288A	5307
Gulfstream G550	N273A	5273
Gulfstream G550	N276A	5491

EXHIBIT 31(i)

CERTIFICATIONS

I, R. A. Walker, certify that:


1.	I have reviewed this quarterly report on Form 10-Q of Anadarko Petroleum Corporation;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

July 28, 2015

/s/ R. A. WALKER

R. A. Walker

Chairman, President and Chief Executive Officer

EXHIBIT 31(ii)

CERTIFICATIONS

I, Robert G. Gwin, certify that:


1.	I have reviewed this quarterly report on Form 10-Q of Anadarko Petroleum Corporation;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

July 28, 2015

/s/ ROBERT G. GWIN

Robert G. Gwin

Executive Vice President, Finance and Chief Financial Officer

EXHIBIT 32

SECTION 1350 CERTIFICATION OF PERIODIC REPORT

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, R. A. Walker, Chairman, President and Chief Executive Officer of Anadarko Petroleum Corporation (Company), and Robert G. Gwin, Executive Vice President, Finance and Chief Financial Officer of the Company, certify to the best of our knowledge that:


(1)	the Quarterly Report on Form 10-Q of the Company for the period ended June 30, 2015, as filed with the Securities and Exchange Commission on the date hereof (Report), fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



July 28, 2015

		/s/ R. A. WALKER
		R. A. Walker
		Chairman, President and Chief Executive Officer

July 28, 2015

		/s/ ROBERT G. GWIN
		Robert G. Gwin
		Executive Vice President, Finance and Chief Financial Officer

This certification is made solely pursuant to 18 U.S.C. Section 1350, and not for any other purpose. A signed original of this written statement required by Section 906 will be retained by Anadarko and furnished to the Securities and Exchange Commission or its staff upon request.

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