ANADARKO PETROLEUM CORP (Form: 10-Q, Received: 07/29/2014 16:18:11)

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, 2014

[ ] 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, 2014 , is shown below:



Title of Class		Number of Shares Outstanding
Common Stock, par value $0.10 per share		505,962,939

TABLE OF CONTENTS




PART I		Page
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three and Six Months Ended June 30, 2014 and 2013	2
	Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2014 and 2013	3
	Consolidated Balance Sheets at June 30, 2014, and December 31, 2013	4
	Consolidated Statement of Equity for the Six Months Ended June 30, 2014	5
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4.	Controls and Procedures	46
PART II
Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	48
Item 6.	Exhibits	49

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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	2014			2013			2014			2013
Revenues and Other
Natural-gas sales	$	991		$	935		$	2,208		$	1,742
Oil and condensate sales	2,705			1,995			5,129			4,372
Natural-gas liquids sales	411			261			797			564
Gathering, processing, and marketing sales	278			249			589			480
Gains (losses) on divestitures and other, net	54			57			1,560			232
Total	4,439			3,497			10,283			7,390
Costs and Expenses
Oil and gas operating	273			245			586			492
Oil and gas transportation and other	281			253			547			508
Exploration	502			178			801			442
Gathering, processing, and marketing	250			222			502			421
General and administrative	305			260			603			532
Depreciation, depletion, and amortization	1,048			940			2,172			1,962
Other taxes	361			245			675			525
Impairments	117			10			120			39
Algeria exceptional profits tax settlement	—			—			—			33
Deepwater Horizon settlement and related costs	93			4			93			7
Total	3,230			2,357			6,099			4,961
Operating Income (Loss)	1,209			1,140			4,184			2,429
Other (Income) Expense
Interest expense	186			172			369			336
(Gains) losses on derivatives, net	323			(656		)	776			(465		)
Other (income) expense, net	(13		)	98			(12		)	92
Tronox-related contingent loss	19			—			4,319			—
Total	515			(386		)	5,452			(37		)
Income (Loss) Before Income Taxes	694			1,526			(1,268		)	2,466
Income tax expense (benefit)	428			567			1,092			1,023
Net Income (Loss)	266			959			(2,360		)	1,443
Net income attributable to noncontrolling interests	39			30			82			54
Net Income (Loss) Attributable to Common Stockholders	$	227		$	929		$	(2,442	)	$	1,389

Per Common Share
Net income (loss) attributable to common stockholders—basic	$	0.45		$	1.84		$	(4.84	)	$	2.75
Net income (loss) attributable to common stockholders—diluted	$	0.45		$	1.83		$	(4.84	)	$	2.74
Average Number of Common Shares Outstanding—Basic	505			502			505			501
Average Number of Common Shares Outstanding—Diluted	507			504			505			504
Dividends (per common share)	$	0.27		$	0.09		$	0.45		$	0.18

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	2014		2013		2014			2013
Net Income (Loss)	$	266	$	959	$	(2,360	)	$	1,443
Other Comprehensive Income (Loss), net of taxes
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net ⁽¹⁾	2		1		3			3
Amortization of net actuarial (gain) loss to general and administrative expense ⁽²⁾	4		19		9			38
Total	6		20		12			41
Comprehensive Income (Loss)	272		979		(2,348		)	1,484
Comprehensive income attributable to noncontrolling interests	39		30		82			54
Comprehensive Income (Loss) Attributable to Common Stockholders	$	233	$	949	$	(2,430	)	$	1,430

__________________________________________________________________


⁽¹⁾	Net of income tax benefit (expense) of $(1) million for the three months ended June 30, 2014 and 2013 , and $(2) million for the six months ended June 30, 2014 and 2013 .


⁽²⁾	Net of income tax benefit (expense) of $(3) million for the three months ended June 30, 2014 , $(11) million for the three months ended June 30, 2013 , $(5) million for the six months ended June 30, 2014 , and $(21) million for the six months ended June 30, 2013 .

See accompanying Notes to Consolidated Financial Statements.

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)



millions	June 30, 2014			December 31, 2013
ASSETS
Current Assets
Cash and cash equivalents	$	5,365		$	3,698
Accounts receivable (net of allowance of $7 million and $5 million)
Customers	1,484			1,481
Others	1,595			1,241
Other current assets	536			688
Total	8,980			7,108
Properties and Equipment
Cost	72,529			71,244
Less accumulated depreciation, depletion, and amortization	31,042			30,315
Net properties and equipment	41,487			40,929
Other Assets	2,352			2,082
Goodwill and Other Intangible Assets	5,595			5,662
Total Assets	$	58,414		$	55,781

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	3,979		$	3,530
Current asset retirement obligations	511			409
Accrued expenses	1,009			1,264
Current portion of long-term debt	—			500
Deepwater Horizon settlement and related costs	92			—
Tronox-related contingent liability	5,169			—
Total	10,760			5,703
Long-term Debt	13,414			13,065
Other Long-term Liabilities
Deferred income taxes	9,186			9,245
Asset retirement obligations	1,499			1,613
Tronox-related contingent liability	—			850
Other	2,383			1,655
Total	13,068			13,363

Equity
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 525.1 million and 522.5 million shares issued)	52			52
Paid-in capital	8,798			8,629
Retained earnings	11,684			14,356
Treasury stock (19.2 million and 18.8 million shares)	(930		)	(895		)
Accumulated other comprehensive income (loss)	(273		)	(285		)
Total Stockholders’ Equity	19,331			21,857
Noncontrolling interests	1,841			1,793
Total Equity	21,172			23,650
Total Liabilities and Equity	$	58,414		$	55,781

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, 2013	$	52	$	8,629	$	14,356		$	(895	)	$	(285	)	$	1,793		$	23,650
Net income (loss)	—		—		(2,442		)	—			—			82			(2,360		)
Common stock issued	—		153		—			—			—			—			153
Dividends—common stock	—		—		(230		)	—			—			—			(230		)
Repurchase of common stock	—		—		—			(35		)	—			—			(35		)
Subsidiary equity transactions	—		16		—			—			—			68			84
Distributions to noncontrolling interest owners	—		—		—			—			—			(102		)	(102		)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	—		—		—			—			3			—			3
Adjustments for pension and other postretirement plans	—		—		—			—			9			—			9
Balance at June 30, 2014	$	52	$	8,798	$	11,684		$	(930	)	$	(273	)	$	1,841		$	21,172

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	2014			2013
Cash Flows from Operating Activities
Net income (loss)	$	(2,360	)	$	1,443
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, and amortization	2,172			1,962
Deferred income taxes	188			563
Dry hole expense and impairments of unproved properties	609			263
Impairments	120			39
(Gains) losses on divestitures, net	(1,468		)	(157		)
Total (gains) losses on derivatives, net	786			(460		)
Operating portion of net cash received (paid) in settlement of derivative instruments	(186		)	65
Other	108			121
Changes in assets and liabilities
Deepwater Horizon settlement and related costs	92			1
Algeria exceptional profits tax settlement	—			698
Tronox-related contingent loss	4,319			—
(Increase) decrease in accounts receivable	(183		)	257
Increase (decrease) in accounts payable and accrued expenses	21			221
Other items—net	(27		)	(11		)
Net cash provided by (used in) operating activities	4,191			5,005
Cash Flows from Investing Activities
Additions to properties and equipment and dry hole costs	(5,100		)	(3,531		)
Acquisition of businesses	(4		)	(135		)
Divestitures of properties and equipment and other assets	3,286			418
Other—net	(282		)	(341		)
Net cash provided by (used in) investing activities	(2,100		)	(3,589		)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	1,077			495
Repayments of debt	(1,255		)	(245		)
Financing portion of net cash paid in settlement of derivative instruments	(222		)	—
Increase (decrease) in outstanding checks	178			145
Dividends paid	(230		)	(92		)
Repurchase of common stock	(35		)	(30		)
Issuance of common stock, including tax benefit on share-based compensation awards	73			95
Sale of subsidiary units	92			415
Distributions to noncontrolling interest owners	(102		)	(68		)
Contributions from noncontrolling interest owners	—			1
Net cash provided by (used in) financing activities	(424		)	716
Effect of Exchange Rate Changes on Cash	—			(22		)
Net Increase (Decrease) in Cash and Cash Equivalents	1,667			2,110
Cash and Cash Equivalents at Beginning of Period	3,698			2,471
Cash and Cash Equivalents at End of Period	$	5,365		$	4,581

See accompanying Notes to Consolidated Financial Statements.

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A NADARKO 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, crude oil, condensate, natural gas liquids (NGLs), and anticipated production of liquefied natural gas (LNG). In addition, the Company engages in the gathering, processing, treating, and transporting of natural gas, crude 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 Balance Sheets at June 30, 2014 , and December 31, 2013 , the Consolidated Statements of Income and Comprehensive Income for the three and six months ended June 30, 2014 and 2013 , the Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013 , and the Consolidated Statement of Equity for the six months ended June 30, 2014 . 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 generally accepted accounting principles 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 issued Accounting Standards Update (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 2017 and is required to be adopted using one of two retrospective application methods, with no early adoption permitted. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.

ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, changes the criteria for reporting discontinued operations and requires additional disclosures, both for discontinued operations and for individually significant dispositions and assets classified as held for sale not qualifying as discontinued operations. This ASU is effective for annual and interim periods beginning in 2015, with early adoption permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. Anadarko early adopted this ASU on a prospective basis beginning with the first quarter of 2014. The adoption did not have a material impact on the Company’s consolidated financial statements.

ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, requires that an unrecognized tax benefit or a portion of an unrecognized tax benefit be presented in the financial statements as a reduction to a deferred tax asset, except in certain circumstances. This ASU is effective for annual and interim periods beginning in 2014. See Note 12—Income Taxes .

2. Divestitures and Assets Held for Sale

Divestitures For the six months ended June 30, 2014 , the Company received $3.3 billion in proceeds from divestitures and recognized net gains of $1.5 billion , primarily related to Mozambique and Pinedale/Jonah transactions during the first quarter of 2014. The Company sold a 10% working interest in Rovuma Offshore Area 1 in Mozambique for $2.64 billion and recognized a gain of $1.5 billion . The Company sold its interest in the Pinedale/Jonah assets in Wyoming for $581 million . The Mozambique and Pinedale/Jonah assets were both included in the oil and gas exploration and production reporting segment.

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A NADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Divestitures and Assets Held for Sale (Continued)

Assets Held for Sale The Company is marketing certain properties from the oil and gas exploration and production reporting segment to direct its operating activities and capital investments to other areas. In February 2014, the Company entered into an agreement to sell its Chinese subsidiary for $1.075 billion . The transaction is expected to close in the third quarter of 2014 and is subject to customary closing conditions. At June 30, 2014 , the Company’s Consolidated Balance Sheet included current assets of $181 million , long-term assets of $452 million , current liabilities of $66 million , and long-term liabilities of $45 million associated with assets held for sale, primarily related to its Chinese subsidiary.

3. Inventories

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



millions	June 30, 2014		December 31, 2013
Crude oil	$	153	$	88
Natural gas	6		43
NGLs	127		79
Total	$	286	$	210

4. Impairments

The following summarizes impairments by segment:



	Three Months Ended June 30,				Six Months Ended June 30,
millions	2014		2013		2014		2013
Oil and gas exploration and production
Long-lived assets held for use
Gulf of Mexico properties	$	115	$	—	$	115	$	—
Cost-method investment	1		10		2		10
Midstream
Long-lived assets held for use	1		—		3		29
Impairments	$	117	$	10	$	120	$	39

During the second quarter of 2014, the Company impaired a Gulf of Mexico property due to a reduction in estimated future cash flows. In the second quarter of 2013, the Company impaired its Venezuelan cost-method investment due to declines in estimated recoverable value. In addition, during the first quarter of 2013, a midstream property was impaired due to a reduction in estimated future cash flows.

The following summarizes the post-impairment fair value of the above-described assets, all of which were measured using the income approach and Level 3 inputs:



millions	2014		2013
Long-lived assets held for use	$	327	$	23
Cost-method investment ⁽¹⁾	32		32

__________________________________________________________________


⁽¹⁾	This represents the Company’s after-tax net investment.

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A NADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

5. Suspended Exploratory Well Costs

The Company’s suspended exploratory well costs were $1.6 billion at June 30, 2014 , and $2.2 billion at December 31, 2013 . The decrease in suspended exploratory well costs during 2014 primarily resulted from the Company’s sale of a 10% working interest in Rovuma Offshore Area 1 in Mozambique during the first quarter of 2014. 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, 2014 , no exploratory well costs previously capitalized as suspended exploratory well costs for greater than one year at December 31, 2013 , were charged to dry hole expense.

6. Noncontrolling Interests

Western Gas Equity Partners, LP (WGP) is a publicly traded consolidated subsidiary formed to own substantially all of the partnership interests in Western Gas Partners, LP (WES) previously owned by Anadarko. At June 30, 2014 , Anadarko’s ownership interest in WGP consisted of a 91.0% limited partner interest and the entire non-economic general partner interest. The remaining 9.0% limited partner interest in WGP was owned by the public.

In July 2014, Anadarko sold 5.75 million WGP limited partner units to the public, raising net proceeds of $335 million . After the sale, Anadarko’s ownership interest in WGP consisted of an 88.3% limited partner interest and the entire non-economic general partner interest.

WES, a publicly traded consolidated subsidiary, is a limited partnership formed by Anadarko to own, operate, acquire, and develop midstream assets. During the first quarter of 2014, WES issued 300,000 common units to the public pursuant to the partial exercise of the underwriters’ over-allotment option granted in connection with WES’s December 2013 equity offering, raising additional net proceeds of $18 million . During the second quarter of 2014, WES issued approximately one million common units to the public under its continuous offering program, raising net proceeds of $74 million . At June 30, 2014 , WGP’s ownership interest in WES consisted of a 40.6% limited partner interest, the entire 2.0% general partner interest, and all of the WES incentive distribution rights. At June 30, 2014 , Anadarko also owned a 0.6% limited partner interest in WES through other subsidiaries. The remaining 56.8% limited partner interest in WES was owned by the public.

7. Derivative Instruments

Objective and Strategy The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Futures, swaps, and options are used to manage exposure to commodity-price risk inherent in the Company’s oil and natural-gas production and natural-gas processing operations (Oil and Natural-Gas Production/Processing Derivative Activities). Futures contracts and commodity-price swap agreements are used to fix the price of expected future oil and natural-gas sales at major industry trading locations, such as 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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A NADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. 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 IntercontinentalExchange, Inc. (ICE) Brent Blend prices. The following is a summary of the Company’s derivative instruments related to its Oil and Natural-Gas Production/Processing Derivative Activities at June 30, 2014 :



	2014 Settlement		2015 Settlement
Natural Gas
Three-Way Collars (thousand MMBtu/d)	600		635
Average price per MMBtu
Ceiling sold price (call)	$	5.01	$	4.76
Floor purchased price (put)	$	3.75	$	3.75
Floor sold price (put)	$	2.75	$	2.75
Fixed-Price Contracts (thousand MMBtu/d)	1,000		—
Average price per MMBtu	$	4.23	$	—
Crude Oil
Three-Way Collars (MBbls/d)	—		25
Average price per barrel
Ceiling sold price (call)	$	—	$	117.55
Floor purchased price (put)	$	—	$	100.00
Floor sold price (put)	$	—	$	85.00
Fixed-Price Contracts (MBbls/d)	140		—
Average price per barrel	$	101.94	$	—

__________________________________________________________________

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 4 billion cubic feet (Bcf) at June 30, 2014 , and 16 Bcf at December 31, 2013 , that were entered into to mitigate commodity-price risk related to fixed-price purchase and sales contracts and storage activity.

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A NADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Derivative Instruments (Continued)

Interest-Rate Derivatives Anadarko has outstanding interest-rate swap contracts as a fixed-rate payer 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 include a provision that requires both the termination of the swaps and cash settlement in full at the start of the reference period.

During the second quarter of 2014, to align the interest-rate swap portfolio with anticipated debt financing, the Company extended the reference-period start dates from June 2014 to September 2016 and adjusted the related fixed interest rates for interest-rate swaps with an aggregate notional principal amount of $1.1 billion . In addition, in anticipation of the July 2014 issuance of an aggregate $1.25 billion of Senior Notes, interest-rate swap agreements with an aggregate notional principal amount of $750 million were settled in June 2014, resulting in a cash payment of $222 million .

Derivative settlements are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements are classified as cash flows from financing activities. In previous years, the Company extended the reference-period start dates for derivatives included in the interest-rate swap portfolio with no settlement of related interest-rate derivative obligations. As a result, current and future settlements 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, 2014 :



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	6.05%

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	2014		2013		2014			2013
Commodity derivatives
Other current assets	$	23	$	181	$	(8	)	$	(102	)
Other assets	28		89		(19		)	(66		)
Accrued expenses	36		106		(213		)	(149		)
Other liabilities	3		4		(6		)	(15		)
	90		380		(246		)	(332		)
Interest-rate and other derivatives
Accrued expenses	—		—		—			(480		)
Other liabilities	—		—		(829		)	(174		)
	—		—		(829		)	(654		)
Total derivatives	$	90	$	380	$	(1,075	)	$	(986	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Derivative Instruments (Continued)

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	2014		2013			2014		2013
Commodity derivatives
Gathering, processing, and marketing sales ⁽¹⁾	$	2	$	(3	)	$	10	$	5
(Gains) losses on derivatives, net	164		(394		)	379		(111		)
Interest-rate and other derivatives
(Gains) losses on derivatives, net	159		(262		)	397		(354		)
Total (gains) losses on derivatives, net	$	325	$	(659	)	$	786	$	(460	)

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

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, 2014 , $53 million of the Company’s $1.1 billion gross derivative liability balance, and at December 31, 2013 , $76 million of the Company’s $986 million 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.

Some of the Company’s derivative instruments are subject to provisions that can require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered. However, most of the Company’s derivative counterparties maintain secured positions with respect to the Company’s derivative liabilities under the Company’s $5.0 billion senior secured revolving credit facility maturing in September 2015 ($5.0 billion Facility). For information on the Company’s revolving credit facilities, see Note 8—Debt and Interest Expense —Anadarko Revolving Credit Facilities.

Unsecured derivative obligations may require immediate settlement or full collateralization if certain credit-risk-related provisions are triggered, such as the Company’s credit rating from major credit rating agencies declining to a level below investment grade. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $92 million at June 30, 2014 , and $42 million at December 31, 2013 . The current portion of these amounts was included in accrued expenses and the long-term portion of these amounts was included in other long-term liabilities — other on the Company’s Consolidated Balance Sheets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. 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 the fair value of swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and, for Black-Scholes option valuations, implied market volatility and discount factors. 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.

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, 2014	Level 1		Level 2			Level 3		Netting ⁽¹⁾			Collateral		Total
Assets
Commodity derivatives
Financial institutions	$	—	$	73		$	—	$	(65	)	$	—	$	8
Other counterparties	—		17			—		(1		)	—		16
Total derivative assets	$	—	$	90		$	—	$	(66	)	$	—	$	24
Liabilities
Commodity derivatives
Financial institutions	$	—	$	(225	)	$	—	$	65		$	14	$	(146	)
Other counterparties	—		(21		)	—		1			—		(20		)
Interest-rate and other derivatives	—		(829		)	—		—			—		(829		)
Total derivative liabilities	$	—	$	(1,075	)	$	—	$	66		$	14	$	(995	)

December 31, 2013
Assets
Commodity derivatives
Financial institutions	$	—	$	211		$	—	$	(153	)	$	—	$	58
Other counterparties	—		169			—		(126		)	—		43
Total derivative assets	$	—	$	380		$	—	$	(279	)	$	—	$	101
Liabilities
Commodity derivatives
Financial institutions	$	—	$	(200	)	$	—	$	153		$	7	$	(40	)
Other counterparties	—		(132		)	—		126			—		(6		)
Interest-rate and other derivatives	—		(654		)	—		—			—		(654		)
Total derivative liabilities	$	—	$	(986	)	$	—	$	279		$	7	$	(700	)

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⁽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)

8. Debt and Interest Expense

Debt The Company’s outstanding debt is senior unsecured, except for borrowings, if any, under the $5.0 billion Facility. The following summarizes the Company’s outstanding debt:



millions	June 30, 2014			December 31, 2013
Total debt at face value	$	15,037		$	15,202
Net unamortized discounts and premiums ⁽¹⁾	(1,631		)	(1,645		)
Total borrowings	$	13,406		$	13,557
Capital lease obligation	8			8
Less current portion of long-term debt	—			500
Total long-term debt	$	13,414		$	13,065

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

Anadarko’s Zero-Coupon Senior Notes due 2036 , which can be put to the Company in October 2014 (the next potential put date), in whole or in part, for the then-accreted value of $756 million , are classified as long-term debt on the Company’s Consolidated Balance Sheets, as the Company has the ability and intent to refinance this obligation using long-term debt should the notes be put to the Company in October 2014.

Fair Value The Company uses a market approach to determine fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was $16.2 billion at June 30, 2014 , and $15.3 billion at December 31, 2013 .

Debt Activity The following summarizes the Company’s debt activity during the six months ended June 30, 2014 :



	Carrying
millions	Value			Description
Balance at December 31, 2013	$	13,557
Issuances	101			WES 2.600% Senior Notes due 2018
	394			WES 5.450% Senior Notes due 2044
Borrowings	590			WES revolving credit facility
Repayments	(500		)	7.625% Senior Notes due 2014
	(275		)	5.750% Senior Notes due 2014
	(480		)	WES revolving credit facility
Other, net	19			Amortization of debt discounts and premiums
Balance at June 30, 2014	$	13,406

In July 2014, the Company issued $625 million aggregate principal amount of 3.450% Senior Notes due 2024 and $625 million aggregate principal amount of 4.500% Senior Notes due 2044 .

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Debt and Interest Expense (Continued)

Anadarko Revolving Credit Facilities At June 30, 2014 , the Company had no outstanding borrowings under the $5.0 billion Facility, there were no restrictions on its ability to use this borrowing capacity, and the Company was in compliance with all applicable covenants.

In June 2014, Anadarko entered into a $3.0 billion five -year senior unsecured revolving credit facility (Five-Year Credit Facility), which is expandable to $4.0 billion , and a $2.0 billion 364 -day senior unsecured revolving credit facility (364-Day Credit Facility). These facilities (collectively, the New Credit Facilities) will replace the existing secured $5.0 billion Facility upon satisfaction of certain conditions including (i) repaying amounts owed under the $5.0 billion Facility in full and all associated commitments and liens being terminated or released; (ii) the U.S. District Court for the Southern District of New York (New York District Court) entering an order approving the settlement agreement related to the Tronox Adversary Proceeding and issuing an injunction barring certain third-party claims; and (iii) Anadarko making payment pursuant to the terms of the settlement agreement related to the Tronox Adversary Proceeding. These conditions must be satisfied or waived by the lenders under each of the New Credit Facilities by December 1, 2014, or the commitments thereunder will terminate. For additional information, see Note 11—Contingencies —Tronox Litigation .

Borrowings under the New Credit Facilities generally will 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 Credit 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 Credit Facility and 0.00% to 1.675% for the 364-Day Credit Facility. The applicable margin will vary depending on Anadarko’s credit ratings.

The New Credit 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.

WES Borrowings During the first quarter of 2014, WES completed a public offering of $100 million aggregate principal amount of 2.600% Senior Notes due 2018 and $400 million aggregate principal amount of 5.450% Senior Notes due 2044 . In February 2014, WES amended and restated its then-existing $800 million senior unsecured revolving credit facility by entering into a five-year $1.2 billion senior unsecured revolving credit facility maturing in February 2019 (RCF), which is expandable to $1.5 billion . Borrowings under the RCF bear interest at LIBOR plus an applicable margin ranging from 0.975% to 1.45% , or rates at a margin above the one-month LIBOR, the federal funds rate, or prime rates offered by certain designated banks. At June 30, 2014 , WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $110 million at an interest rate of 1.46% , and had available borrowing capacity of approximately $1.1 billion ( $1.2 billion maximum capacity, less $110 million of outstanding borrowings and $13 million of outstanding letters of credit).

Interest Expense The following summarizes interest expense:



	Three Months Ended June 30,						Six Months Ended June 30,
millions	2014			2013			2014			2013
Debt and other	$	233		$	238		$	473		$	470
Capitalized interest	(47		)	(66		)	(104		)	(134		)
Interest expense	$	186		$	172		$	369		$	336

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

9. Stockholders’ Equity

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	2014		2013		2014			2013
Net income (loss)
Net income (loss) attributable to common stockholders	$	227	$	929	$	(2,442	)	$	1,389
Less distributions on participating securities	1		1		1			1
Less undistributed income allocated to participating securities	—		5		—			8
Basic	$	226	$	923	$	(2,443	)	$	1,380
Diluted	$	226	$	923	$	(2,443	)	$	1,380
Shares
Average number of common shares outstanding—basic	505		502		505			501
Dilutive effect of stock options	2		2		—			3
Average number of common shares outstanding—diluted	507		504		505			504
Excluded ⁽¹⁾	4		5		11			4
Net income (loss) per common share
Basic	$	0.45	$	1.84	$	(4.84	)	$	2.75
Diluted	$	0.45	$	1.83	$	(4.84	)	$	2.74

Dividends per common share	$	0.27	$	0.09	$	0.45		$	0.18

__________________________________________________________________


⁽¹⁾	Inclusion of certain shares would have had an anti-dilutive effect.

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, 2013	$	(54	)	$	(231	)	$	(285	)
Reclassifications to Consolidated Statement of Income	3			9			12
Balance at June 30, 2014	$	(51	)	$	(222	)	$	(273	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Contingencies

Litigation 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; 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, with the possible exception of the Tronox Litigation discussed below, the resolution of pending proceedings will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

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, 2013 .

Tronox Litigation On November 28, 2005, Tronox Incorporated (Tronox), at the time a subsidiary of Kerr-McGee Corporation, completed an initial public offering (IPO) and was subsequently spun-off from Kerr-McGee Corporation. In August 2006, Anadarko acquired all of the stock of Kerr-McGee Corporation. In January 2009, Tronox and certain of Tronox’s subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York (Bankruptcy Court), which is the court that is also hearing the Adversary Proceeding (defined below). In May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee Corporation and certain of its subsidiaries (collectively, Kerr-McGee) asserting several claims, including claims for actual and constructive fraudulent conveyance (Adversary Proceeding). Tronox alleged, among other things, that it was insolvent or undercapitalized at the date of its IPO and sought, among other things, to recover damages in excess of $18.85 billion from Kerr-McGee and Anadarko, as well as interest and attorneys’ fees and costs. In accordance with Tronox’s Bankruptcy Court-approved Plan of Reorganization (Plan), the Adversary Proceeding is being pursued by a litigation trust (Litigation Trust). Pursuant to the Plan, the Litigation Trust was “deemed substituted” for the Tronox plaintiffs in the Adversary Proceeding.

The U.S. government intervened in the Adversary Proceeding, and in May 2009 asserted separate claims against Anadarko and Kerr-McGee under the Federal Debt Collection Procedures Act (FDCPA Complaint). The Litigation Trust and the U.S. government agreed that the recovery of damages under the Adversary Proceeding, if any, would cover both the Adversary Proceeding and the FDCPA Complaint.

In February 2011, Tronox emerged from bankruptcy pursuant to the Plan. The terms of the Plan, which were confirmed by the Bankruptcy Court in the fourth quarter of 2010, contemplate that the claims of the U.S. government (together with other federal, state, local, and tribal governmental entities having regulatory authority or responsibilities for environmental laws, collectively, the Governmental Entities) related to Tronox’s environmental liabilities and tort claims asserted against Tronox by other creditors will be settled through certain environmental response trusts and the Litigation Trust. The Plan provides for an allocation of any proceeds from the Adversary Proceeding between the Governmental Entities and the other creditors.

Liability Accrual On April 3, 2014, Anadarko and Kerr-McGee entered into a settlement agreement with the Litigation Trust and the U.S. government (in its capacity as plaintiff-intervenor and acting for and on behalf of certain U.S. government agencies) to resolve all claims asserted in the Adversary Proceeding and FDCPA Complaint for $5.15 billion , which represents principal of approximately $3.98 billion plus 6% interest from the filing of the Adversary Proceeding on May 12, 2009, through April 3, 2014. In addition, interest will be paid on the above amount from April 3, 2014, through the date of payment of the settlement, with interest of 1.5% for the first 180 days and 1.5% plus the one-month LIBOR thereafter. Under the terms of the settlement agreement, the Litigation Trust, Anadarko, and Kerr-McGee agreed to mutually release all claims that were or could have been asserted in the Adversary Proceeding. The U.S. government (representing federal agencies that filed claims in the Tronox bankruptcy) and Anadarko and Kerr-McGee also provided covenants not to sue each other with respect to certain claims and causes of action. The U.S. government will also provide contribution protection from third-party claims seeking reimbursement from Anadarko and certain of its affiliates for the sites identified in the settlement agreement.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Contingencies (Continued)

The Adversary Proceeding has been stayed pending final approval of the settlement agreement. In May 2014, the Bankruptcy Court issued its Findings of Fact and Conclusions of Law recommending approval of the settlement agreement. The settlement agreement is subject to approval by the New York District Court and the issuance of an injunction by the New York District Court barring similar claims from third parties. The settlement payment will be made once both the New York District Court’s approval of the settlement agreement and the issuance of the injunction are final and non-appealable. The Company currently expects this process to be completed during the second half of 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 of $19 million , included in Tronox-related contingent loss in the Company’s Consolidated Statement of Income, during the second quarter of 2014, for an aggregate $5.17 billion Tronox-related contingent liability on the Company’s Consolidated Balance Sheet at June 30, 2014. For information on the tax effects of the settlement agreement, see Note 12—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, 2013.

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 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, which was affirmed in June 2014 by the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit), addresses liability only and does not address the amount of the civil penalty. The assessment of a civil penalty against Anadarko will follow a bench trial scheduled to begin in January 2015. In July 2014, Anadarko filed a motion for rehearing with the Fifth Circuit requesting that the full court sit to reconsider Anadarko’s appeal concerning that portion of the February 2012 declaratory judgment finding Anadarko liable for civil penalties under the CWA.

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 in the amount of $90 million . The parties have not reached a settlement, but the Company remains open to resolving the matter through settlement discussions. Under a settlement scenario, and based on the above accounting guidance, the Company believes that $90 million is a better estimate of loss at this time than any other amount, and therefore recorded a contingent liability for $90 million at June 30, 2014.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Contingencies (Continued)

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 proceed to trial in January 2015. The CWA sets forth subjective criteria to be considered by the court in assessing the magnitude of any CWA penalty, including the degree of fault of the owner. In the Phase I and II trials (defined 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 may be presented. Given the subjective nature of the CWA criteria used to determine penalty assessments and the Louisiana District Court’s prior rulings related to culpability, 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. In addition, the Company cannot reasonably estimate the outcome of any substantive settlement discussions that may occur. However, given the Company’s lack of direct operational involvement in the event, the Louisiana District Court’s rulings excluding any evidence of Anadarko’s alleged culpability or fault, and the subjective criteria of the CWA, the Company believes that its exposure to CWA penalties will not materially impact the Company’s consolidated financial position, results of operations, or cash flows.

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 (i) an assessment by the DOJ, (ii) a ruling by a court of competent jurisdiction, or (iii) 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. For example, eleven Louisiana Parish District Attorneys appealed that decision to the Fifth Circuit. In February 2014, the Fifth Circuit denied the appeal and upheld the Louisiana District Court’s decision. If any further appeal is taken 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. In March 2012, BP and the Plaintiffs’ Steering Committee entered into a settlement agreement to resolve the substantial majority of economic loss and medical claims stemming from the Deepwater Horizon events, which the Louisiana District Court approved in orders issued in December 2012 and January 2013. Only OPA claims seeking economic loss damages against the Company remain. In addition, certain state and local governments have appealed, or have 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. Certain Mexican states also have appealed the dismissal of their claims against BP, the Company, and others. The Company, pursuant to the Settlement Agreement, is fully indemnified by BP against losses arising as a result of claims for damages, irrespective of whether such claims are based on federal (including OPA) or state law.

The first phase of the trial in the MDL (Phase I) commenced in February 2013. In April 2013, all parties rested their Phase I cases. Findings of fact, post-trial briefs, and responsive briefs were submitted in July 2013. BP, BP p.l.c., the United States, state and local governments, Halliburton Energy Services, Inc. (Halliburton), and Transocean Ltd. (Transocean) participated in Phase I. Anadarko was excused from participation in Phase I. The issues tried in Phase I included the cause of the blow-out and all related events leading up to April 22, 2010, the date the Deepwater Horizon sank, as well as allocation of fault. The allocation of fault remained in the Phase I trial because Halliburton and Transocean have not settled with any of the parties and each wishes to prove to the Louisiana District Court that their respective company was not at fault. Any fault ruling against BP will be binding against it in the penalty phase trial. The second phase of trial (Phase II) began in September 2013 and in November 2013 the parties rested their Phase II cases. 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. The Company, BP, BP p.l.c., the United States, state and local governments, Halliburton, and Transocean participated in Phase II of the trial. The penalty phase of the trial, which is scheduled to begin in January 2015, will include Anadarko, BP, and the United States, and will assess findings and penalties under the CWA. In March 2014, the Louisiana District Court ruled that no evidence of Anadarko’s alleged culpability or fault may be presented during the penalty phase trial.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Contingencies (Continued)

Two separate class-action complaints were filed in June and August 2010, in the New York District Court on behalf of purported purchasers of the Company’s stock between June 9, 2009, and June 12, 2010, against Anadarko and certain of its officers. The consolidated action was subsequently transferred to the U.S. District Court for the Southern District of Texas - Houston Division (Texas District Court). The complaints allege causes of action arising pursuant to the Securities Exchange Act of 1934 for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. The parties reached a tentative settlement in this matter in March 2014, subject to approval by the Texas District Court. In June 2014, the Texas District Court issued a preliminary approval of the settlement and has scheduled a final hearing for August 2014. The tentative settlement was directly funded by the Company’s insurers into the plaintiffs’ settlement escrow account in June 2014.

Remaining Liability Outlook It is possible that the Company may recognize additional Deepwater Horizon event-related liabilities for potential fines and penalties, shareholder claims, and certain other claims not covered by the indemnification provisions of the Settlement Agreement; however, the Company does not believe that any potential liability attributable to the foregoing items, individually or in the aggregate, will have a material impact on the Company’s consolidated financial position, results of operations, or cash flows. This assessment takes into account certain qualitative factors, including the subjective and fault-based nature of CWA penalties, the Company’s indemnification by BP against certain damage claims as discussed above, BP’s creditworthiness, the merits of the shareholder claims, and directors’ and officers’ insurance coverage related to outstanding shareholder claims.

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.

Deepwater Horizon and Tronox Derivative Claims In May 2013, an Anadarko shareholder filed a derivative action in the 215 ^th District Court of Harris County, Texas (215 ^th District Court) against Anadarko and certain current and former directors and officers (DWH Derivative Action). The shareholder purports to bring claims on behalf of Anadarko and alleges, among other things, that certain current and former directors and officers breached their fiduciary duty in connection with the Company’s investment in the Macondo lease.

In addition, in April 2014, the Company’s Board of Directors received a letter from a current shareholder demanding that the Board undertake an independent investigation of certain current and former officers and directors for alleged breach of fiduciary duty related to the Company’s April 2014 settlement of the Adversary Proceeding (Tronox Derivative Demand).

In May 2014, the parties reached an agreement to jointly resolve the DWH Derivative Action and the Tronox Derivative Demand in one settlement. In order to achieve the joint settlement, the petition in the DWH Derivative Action was amended to include the allegations asserted in the Tronox Derivative Demand. In June 2014, the 215 ^th District Court preliminarily approved the settlement. A hearing to consider final approval of the settlement is scheduled for August 2014. The proposed settlement will not have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.

Environmental Matters Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. The Company continually monitors remediation and reclamation processes and adjusts its liability for these obligations as necessary.

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A NADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. 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	2014			2013			2014			2013
Income tax expense (benefit)	$	428		$	567		$	1,092		$	1,023
Effective tax rate	62		%	37		%	(86		)%	41		%

The increase from the 35% U.S. federal statutory rate for the three months ended June 30, 2014, was primarily due to the tax impact from foreign operations, Algerian exceptional profits taxes, uncertain tax positions, and the non-deductible contingent CWA-penalty accrual. The increase from the 35% U.S. federal statutory rate for the three and six months ended June 30, 2013 , was primarily attributable to the tax impact from foreign operations and Algerian exceptional profits taxes.

The Company reported a loss before income taxes for the six months ended June 30, 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, 2014 , was primarily attributable to net changes in uncertain tax positions related to the settlement agreement associated with the Adversary Proceeding, the tax impact from foreign operations, Algerian exceptional profits taxes, and the non-deductible contingent CWA-penalty accrual.

The Company previously recognized a deferred tax benefit of $274 million related to the $850 million loss recognized in 2013 with respect to the Tronox-related contingent liability. In the first quarter of 2014, the Company recognized an additional tax benefit of $282 million related to the additional $4.3 billion loss with respect to the Tronox-related contingent liability. This benefit is net of a $1.1 billion uncertain tax position due to the uncertainty related to the deductibility of the final settlement payment. This uncertain tax position is presented in deferred income taxes, as a reduction to the associated deferred tax asset, and in other long-term liabilities — other on the Company’s Consolidated Balance Sheet. The Company is a participant in the 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 11—Contingencies —Tronox Litigation .

For the three months ended June 30, 2014, the Company identified $115 million of uncertain tax positions. The Company estimates $100 million to $130 million of unrecognized tax positions that relate to adjustments to taxable income and credits recorded will reverse within the next 12 months due to expiration of statutes of limitation and settlements with tax authorities.

13. Supplemental Cash Flow Information

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



	Six Months Ended June 30,
millions	2014		2013
Cash paid (received)
Interest, net of amounts capitalized	$	342	$	313
Income taxes, net of refunds	$	655	$	103
Non-cash investing activities
Fair value of properties and equipment exchanged in non-cash transactions	$	5	$	13
Non-cash investing and financing activities
Floating production, storage, and offloading vessel construction period obligation	$	53	$	—

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A NADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14. 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, crude 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 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, Algeria exceptional profits tax settlement, 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	2014		2013			2014			2013
Income (loss) before income taxes	$	694	$	1,526		$	(1,268	)	$	2,466
Exploration expense	502		178			801			442
DD&A	1,048		940			2,172			1,962
Impairments	117		10			120			39
Interest expense	186		172			369			336
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	237		(641		)	600			(395		)
Deepwater Horizon settlement and related costs	93		4			93			7
Algeria exceptional profits tax settlement	—		—			—			33
Tronox-related contingent loss	19		—			4,319			—
Certain other nonoperating items	—		85			—			85
Less net income attributable to noncontrolling interests	39		30			82			54
Consolidated Adjusted EBITDAX	$	2,857	$	2,244		$	7,124		$	4,921

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A NADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14. Segment Information (Continued)

Information presented below as “Other and Intersegment Eliminations” includes results from hard-minerals royalty arrangements and corporate, financing, and certain derivative activities. 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, 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

Three Months Ended June 30, 2013
Sales revenues	$	1,587	$	88		$	1,765		$	—		$	3,440
Intersegment revenues	1,526		265			(1,639		)	(152		)	—
Gains (losses) on divestitures and other, net	1		—			—			56			57
Total revenues and other	3,114		353			126			(96		)	3,497
Operating costs and expenses ⁽¹⁾	845		209			164			7			1,225
Net cash from settlement of commodity derivatives	—		—			—			(21		)	(21		)
Other (income) expense, net ⁽²⁾	—		—			—			13			13
Net income attributable to noncontrolling interests	—		30			—			—			30
Total expenses and other	845		239			164			(1		)	1,247
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—		—			(6		)	—			(6		)
Adjusted EBITDAX	$	2,269	$	114		$	(44	)	$	(95	)	$	2,244

__________________________________________________________________


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


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

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A NADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14. Segment Information (Continued)



millions	Oil and Gas Exploration & Production		Midstream			Marketing			Other and Intersegment Eliminations			Total
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

Six Months Ended June 30, 2013
Sales revenues	$	3,128	$	172		$	3,858		$	—		$	7,158
Intersegment revenues	3,388		518			(3,605		)	(301		)	—
Gains (losses) on divestitures and other, net	5		—			—			227			232
Total revenues and other	6,521		690			253			(74		)	7,390
Operating costs and expenses ⁽¹⁾	1,726		397			328			27			2,478
Net cash from settlement of commodity derivatives	—		—			—			(72		)	(72		)
Other (income) expense, net ⁽²⁾	—		—			—			7			7
Net income attributable to noncontrolling interests	—		54			—			—			54
Total expenses and other	1,726		451			328			(38		)	2,467
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—		—			(2		)	—			(2		)
Adjusted EBITDAX	$	4,795	$	239		$	(77	)	$	(36	)	$	4,921

__________________________________________________________________


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


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

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A NADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15. 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	2014			2013			2014			2013
Three Months Ended June 30
Service cost	$	24		$	22		$	2		$	3
Interest cost	25			19			3			3
Expected return on plan assets	(26		)	(23		)	—			—
Amortization of net actuarial loss (gain)	8			30			(1		)	—
Net periodic benefit cost	$	31		$	48		$	4		$	6

Six Months Ended June 30
Service cost	$	49		$	43		$	4		$	5
Interest cost	50			39			7			7
Expected return on plan assets	(53		)	(46		)	—			—
Amortization of net actuarial loss (gain)	17			59			(3		)	—
Net periodic benefit cost	$	63		$	95		$	8		$	12

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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 and Section 21E of the Securities Exchange Act of 1934 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, crude 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, either nationally, internationally, or in the jurisdictions in which the Company or its subsidiaries are doing business


•	the Company’s inability to timely obtain or maintain permits, 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

•

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

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•	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


•	current and potential legal proceedings, or environmental or other obligations related to or arising from Tronox Incorporated (Tronox)


•	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 crude-oil cargo shipping activities


•	physical, digital, internal, and external security breaches


•	supply and demand, technological, political, 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 2013 Annual Report on Form 10-K, 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 2013 Annual Report on Form 10-K; and the information set forth in the Risk Factors under Part I, Item 1A of the 2013 Annual Report on Form 10-K.

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, crude oil, condensate, NGLs, and anticipated production of liquefied natural gas. The Company also engages in the gathering, processing, treating, and transporting of natural gas, crude oil, and NGLs. The Company has production and exploration activities worldwide, including activities in the United States, Algeria, Mozambique, Ghana, Brazil, Kenya, Côte d’Ivoire, Liberia, Sierra Leone, New Zealand, Colombia, South Africa, and other countries.

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Significant operating and financial activities for the second quarter of 2014 include the following:

Overall


•	Anadarko’s second -quarter sales volumes averaged 848 thousand barrels of oil equivalent per day (MBOE/d), representing a 13% increase over the second quarter of 2013 .


•	Anadarko’s second -quarter liquids sales volumes averaged 411 thousand barrels per day (MBbls/d), representing a 33% increase over the second quarter of 2013 , primarily due to increased sales volumes in the Wattenberg field, the Eagleford shale, the East Texas/North Louisiana horizontal development, the Delaware basin, and at El Merk in Algeria.

U.S. Onshore


•	U.S. onshore second -quarter sales volumes averaged 676 MBOE/d, representing a 17% increase over the second quarter of 2013 , primarily due to increased sales volumes from the Wattenberg field, the Marcellus and Eagleford shales, the East Texas/North Louisiana horizontal development, and the Delaware basin.

Gulf of Mexico


•	Gulf of Mexico second -quarter sales volumes averaged 76 MBOE/d, representing a 24% decrease from the second quarter of 2013 , primarily due to natural production declines.

International


•	International second -quarter sales volumes averaged 96 MBOE/d, representing a 35% increase over the second quarter of 2013 , primarily due to increased production at El Merk in Algeria as additional facilities and wells were brought online.

Financial

•

Anadarko and Kerr-McGee Corporation and certain of its subsidiaries entered into the Tronox settlement agreement to resolve all claims asserted in the Adversary Proceeding and under the Federal Debt Collection Procedures Act for $5.15 billion, plus additional interest from April 3, 2014, through the date of payment of the settlement. In May 2014, the U.S. Bankruptcy Court for the Southern District of New York issued its Findings of Fact and Conclusions of Law recommending approval of the settlement agreement. The settlement agreement is still subject to approval by the U.S. District Court for the Southern District of New York and the issuance of an injunction barring similar claims from being asserted by third parties.

•

In June 2014, Anadarko entered into a $3.0 billion five-year senior unsecured revolving credit facility, which is expandable to $4.0 billion, and a $2.0 billion 364-day senior unsecured revolving credit facility. These facilities (collectively, the New Credit Facilities) will replace the Company’s existing senior secured $5.0 billion revolving credit facility upon satisfaction of certain conditions, including payment of the settlement related to the Adversary Proceeding.


•	Anadarko’s net income attributable to common stockholders for the second quarter of 2014 totaled $227 million .


•	The Company generated $2.5 billion of cash flow from operations and ended the quarter with $5.4 billion of cash on hand.


•	Anadarko increased the quarterly dividend paid to common stockholders from $0.18 per share to $0.27 per share.


•	The Company repaid the $275 million 5.750% Senior Notes that matured in June 2014.


•	Subsequent to quarter end, the Company issued $625 million aggregate principal amount of 3.450% Senior Notes due 2024 and $625 million aggregate principal amount of 4.500% Senior Notes due 2044. These proceeds will be used for general corporate purposes.


•	Subsequent to quarter end, the Company sold 5.75 million Western Gas Equity Partners, LP (WGP) limited partner units to the public, raising net proceeds of $335 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, 2014, ” refer to the comparison of the three months ended June 30, 2014, to the three months ended June 30, 2013 , and any increases or decreases “for the six months ended June 30, 2014, ” refer to the comparison of the six months ended June 30, 2014, to the six months ended June 30, 2013 . The primary factors that affect the Company’s results of operations include commodity prices for natural gas, crude 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	2014		2013			2014			2013
Financial Results
Revenues and other	$	4,439	$	3,497		$	10,283		$	7,390
Costs and expenses	3,230		2,357			6,099			4,961
Other (income) expense	515		(386		)	5,452			(37		)
Income tax expense (benefit)	428		567			1,092			1,023
Net income (loss) attributable to common stockholders	$	227	$	929		$	(2,442	)	$	1,389
Net income (loss) per common share attributable to common stockholders—diluted	$	0.45	$	1.83		$	(4.84	)	$	2.74
Average number of common shares outstanding—diluted	507		504			505			504

Operating Results
Adjusted EBITDAX ⁽¹⁾	$	2,857	$	2,244		$	7,124		$	4,921
Sales volumes (MMBOE)	77		69			151			140

________________________________________________________________________________________________________

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
2013 sales revenues	$	935		$	1,995		$	261		$	3,191
Changes associated with sales volumes	(10		)	582			114			686
Changes associated with prices	66			128			36			230
2014 sales revenues	$	991		$	2,705		$	411		$	4,107
Increase (Decrease) vs. 2013	6		%	36		%	57		%	29		%

	Six Months Ended June 30,
millions except percentages	Natural Gas			Oil and Condensate			NGLs			Total
2013 sales revenues	$	1,742		$	4,372		$	564		$	6,678
Changes associated with sales volumes	(6		)	731			155			880
Changes associated with prices	472			26			78			576
2014 sales revenues	$	2,208		$	5,129		$	797		$	8,134
Increase (Decrease) vs. 2013	27		%	17		%	41		%	22		%

Anadarko’s total sales revenues increased for the three and six months ended June 30, 2014 , due to higher average commodity prices for all products and higher sales volumes for crude oil and NGLs, partially offset by slightly lower natural-gas sales volumes.



	Three Months Ended June 30,				Six Months Ended June 30,
Sales Volumes	2014	Inc/(Dec) vs. 2013		2013	2014	Inc/(Dec) vs. 2013		2013
Barrels of Oil Equivalent (MMBOE except percentages)
United States	68	11	%	62	134	8	%	124
International	9	35		7	17	11		16
Total	77	13		69	151	8		140

Barrels of Oil Equivalent per Day (MBOE/d except percentages)
United States	752	11	%	679	741	8	%	687
International	96	35		71	93	11		84
Total	848	13		750	834	8		771

Sales volumes represent production volumes adjusted for changes in commodity inventories. Production of natural gas, crude oil, and NGLs is usually not affected by seasonal swings in demand.

Anadarko employs marketing strategies to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. For additional information, see Note 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q 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,
	2014		Inc/(Dec) vs. 2013		2013		2014		Inc/(Dec) vs. 2013		2013
United States
Sales volumes—Bcf	238		(1	)%	241		481		—	%	483
MMcf/d	2,620		(1	)	2,647		2,658		—		2,668
Price per Mcf	$	4.16	7		$	3.88	$	4.59	27		$	3.61
Natural-gas sales revenues (millions)	$	991	6		$	935	$	2,208	27		$	1,742

_______________________________________________________________________________

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

Mcf—thousand cubic feet

The Company’s natural-gas sales volumes decreased by 27 MMcf/d for the three months ended June 30, 2014 , and 10 MMcf/d for the six months ended June 30, 2014 . Sales volumes in the Gulf of Mexico decreased by 104 MMcf/d for the three months ended June 30, 2014 , and 95 MMcf/d for the six months ended June 30, 2014 , primarily due to natural production declines. Sales volumes in the Company’s Rocky Mountain Region (Rockies) decreased by 52 MMcf/d for the three months ended June 30, 2014 , and 67 MMcf/d for the six months ended June 30, 2014 , primarily due to the sale of the Company’s Pinedale/Jonah assets in January 2014 and a natural production decline in the Powder River basin. These decreases in the Rockies were partially offset by higher sales volumes in the Wattenberg field due to increased horizontal drilling and an exchange of certain oil and gas properties with a third party in October 2013, and higher sales volumes in the Moxa field due to the acquisition of oil and gas properties in September 2013. In addition, sales volumes in the Southern and Appalachia Region increased by 129 MMcf/d for the three months ended June 30, 2014 , and 152 MMcf/d for the six months ended June 30, 2014 , primarily due to infrastructure expansions in 2013 that allowed the Company to bring wells online in the Marcellus and Eagleford shales, as well as continued horizontal drilling in the liquids-rich East Texas/North Louisiana horizontal development.

The average natural-gas price Anadarko received increased for the three and six months ended June 30, 2014, as colder than average winter weather throughout much of the United States led to higher than normal residential, commercial, and industrial demand, which reduced overall natural-gas end-of-winter storage levels below those of the previous year’s levels. Although industry production has increased and overall demand remained unchanged compared to the second quarter of 2013, the year-over-year storage deficit remains, further supporting higher natural-gas prices.

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Crude-Oil and Condensate Sales Volumes, Average Prices, and Revenues



	Three Months Ended June 30,						Six Months Ended June 30,
	2014		Inc/(Dec) vs. 2013		2013		2014		Inc/(Dec) vs. 2013		2013
United States
Sales volumes—MMBbls	18		27	%	14		34		20	%	28
MBbls/d	196		27		155		189		20		157
Price per barrel	$	98.69	4		$	94.99	$	96.86	1		$	96.17
International
Sales volumes—MMBbls	9		33	%	7		17		10	%	16
MBbls/d	95		33		71		92		10		84
Price per barrel	$	109.00	7		$	102.05	$	108.71	1		$	107.89
Total
Sales volumes—MMBbls	27		29	%	21		51		17	%	44
MBbls/d	291		29		226		281		17		241
Price per barrel	$	102.04	5		$	97.21	$	100.76	—		$	100.26
Oil and condensate sales revenues (millions)	$	2,705	36		$	1,995	$	5,129	17		$	4,372

_______________________________________________________________________________

MMBbls—million barrels

MBbls/d—thousand barrels per day

Anadarko’s total crude-oil and condensate sales volumes increased by 65 MBbls/d for the three months ended June 30, 2014 , and 40 MBbls/d for the six months ended June 30, 2014 . Sales volumes in the Rockies increased by 35 MBbls/d for the three months ended June 30, 2014 , and 26 MBbls/d for the six months ended June 30, 2014 , primarily in the Wattenberg field due to increased horizontal drilling and an exchange of certain oil and gas properties with a third party in October 2013. Southern and Appalachia Region sales volumes increased by 14 MBbls/d for the three months ended June 30, 2014 , and 13 MBbls/d for the six months ended June 30, 2014 , primarily as a result of increased horizontal drilling and 2013 infrastructure expansions in the Eagleford shale and increased horizontal drilling in the Delaware basin. Internationally, sales volumes increased by 25 MBbls/d for the three months ended June 30, 2014 , and 9 MBbls/d for the six months ended June 30, 2014 , primarily due to higher sales volumes in Algeria due to increased production at El Merk as additional facilities and wells were brought online, partially offset by lower sales volumes in China due to maintenance downtime. Also, for the six months ended June 30, 2014 , sales volumes in Ghana decreased due to timing of crude-oil liftings. Sales volumes in the Gulf of Mexico decreased by 5 MBbls/d for the three and six months ended June 30, 2014 , primarily due to natural production declines and maintenance downtime during the second quarter.

Anadarko’s average crude-oil price received increased slightly for the three months ended June 30, 2014, primarily due to new pipeline projects from Cushing to the Gulf Coast, which has improved domestic crude-oil pricing. Anadarko’s average crude-oil price also increased due to higher Brent prices. Anadarko’s average crude-oil price received remained flat for the six months ended June 30, 2014 .

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2014		Inc/(Dec) vs. 2013		2013		2014		Inc/(Dec) vs. 2013		2013
United States
Sales volumes—MMBbls	11		43	%	7		20		27	%	15
MBbls/d	119		43		83		109		27		85
Price per barrel	$	37.39	9		$	34.33	$	40.08	10		$	36.29
International
Sales volumes—MMBbls	—		NM		—		—		NM		—
MBbls/d	1		NM		—		1		NM		—
Price per barrel	$	66.69	NM		$	—	$	66.69	NM		$	—
Total
Sales volumes—MMBbls	11		44	%	7		20		28	%	15
MBbls/d	120		44		83		110		28		85
Price per barrel	$	37.66	10		$	34.33	$	40.22	11		$	36.29
Natural-gas liquids sales revenues (millions)	$	411	57		$	261	$	797	41		$	564

_________________________________________________________________________

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 37 MBbls/d for the three months ended June 30, 2014, and 25 MBbls/d for the six months ended June 30, 2014 . Sales volumes in the Rockies increased by 25 MBbls/d for the three months ended June 30, 2014, and 13 MBbls/d for the six months ended June 30, 2014 , primarily in the Wattenberg field due to increased horizontal drilling, the Lancaster plant coming online in 2014, and an exchange of certain oil and gas properties with a third party in October 2013, and in the Greater Natural Buttes area due to ethane recovery during 2014. Southern and Appalachia Region sales volumes increased by 11 MBbls/d for the three months ended June 30, 2014, and 12 MBbls/d for the six months ended June 30, 2014 , as a result of increased horizontal drilling and 2013 infrastructure expansion in the Eagleford shale, continued horizontal drilling in the liquids-rich East Texas/North Louisiana horizontal development, and increased horizontal drilling in the Delaware basin.

Anadarko’s average NGLs price received increased for the three and six months ended June 30, 2014, primarily due to colder than average weather across much of the United States, which led to increased propane demand for heating and to production outages thereby reducing NGL supply.

Gathering, Processing, and Marketing



	Three Months Ended June 30,						Six Months Ended June 30,
millions except percentages	2014		Inc/(Dec) vs. 2013		2013		2014		Inc/(Dec) vs. 2013		2013
Gathering, processing, and marketing sales	$	278	12	%	$	249	$	589	23	%	$	480
Gathering, processing, and marketing expense	250		13		222		502		19		421
Gathering, processing, and marketing, net	$	28	4		$	27	$	87	47		$	59

Marketing sales represent the margin earned from purchasing and selling third-party oil and natural gas. Processing sales and expenses relate to the purchase of third-party natural gas and the sale of the extracted NGLs and remaining residue gas. The Company also earns gathering revenue and processing fees by providing gathering and processing services to third parties. Other operating and transportation expenses included in gathering, processing, and marketing expense relate to the Company’s costs to perform these activities.

Gathering, processing, and marketing, net was flat for the three months ended June 30, 2014, and increased by $ 28 million for the six months ended June 30, 2014 . The increase for the six months ended June 30, 2014 , was primarily due to higher gathering revenue as a result of increased throughput across several of Anadarko’s systems, and increased marketing margins primarily associated with crude-oil sales, partially offset by increased transportation expenses due to increased activity.

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Gains (Losses) on Divestitures and Other, net

During the six months ended June 30, 2014 , the Company recognized a $1.5 billion gain associated with its divestiture of a 10% working interest in Rovuma Offshore Area 1 in Mozambique. During the six months ended June 30, 2013 , the Company recognized a $140 million gain associated with the Company’s divestiture of its interests in a soda ash joint venture.

Costs and Expenses



	Three Months Ended June 30,						Six Months Ended June 30,
	2014		Inc/(Dec) vs. 2013		2013		2014		Inc/(Dec) vs. 2013		2013
Oil and gas operating (millions)	$	273	11	%	$	245	$	586	19	%	$	492
Oil and gas operating—per BOE	3.53		(2	)	3.59		3.88		10		3.52
Oil and gas transportation and other (millions)	281		11		253		547		8		508
Oil and gas transportation and other—per BOE	3.64		(2	)	3.70		3.62		(1	)	3.64

Oil and gas operating expense increased by $28 million for the three months ended June 30, 2014, primarily due to higher costs associated with increased sales volumes, as well as increased surface maintenance costs primarily in the Rockies. Oil and gas operating expense increased by $94 million for the six months ended June 30, 2014 , primarily due to increased workover costs primarily in the Gulf of Mexico and the Rockies and increased surface maintenance costs primarily in the Rockies, as well as higher costs associated with increased volumes. The related per barrel of oil equivalent (BOE) costs decreased by $0.06 for the three months ended June 30, 2014, primarily due to increased sales volumes, partially offset by higher costs. The related per BOE costs increased $0.36 for the six months ended June 30, 2014 , as the higher costs were only partially offset by increased sales volumes.

Oil and gas transportation and other expense increased by $28 million for the three months ended June 30, 2014, and $39 million for the six months ended June 30, 2014 , primarily due to higher gas-gathering and transportation costs attributable to higher volumes related to the growth in the Company’s U.S. onshore asset base. Oil and gas transportation and other expense per BOE decreased by $0.06 for the three months ended June 30, 2014, and $0.02 for six months ended June 30, 2014 , due to increased sales volumes, which more than offset the higher costs discussed above.



	Three Months Ended June 30,				Six Months Ended June 30,
millions	2014		2013		2014		2013
Exploration Expense
Dry hole expense	$	302	$	66	$	423	$	224
Impairments of unproved properties	109		20		186		39
Geological and geophysical expense	37		23		80		60
Exploration overhead and other	54		69		112		119
Total exploration expense	$	502	$	178	$	801	$	442

For the three months ended June 30, 2014, exploration expense increased by $324 million . Dry hole expense increased by $236 million primarily due to unsuccessful 2014 drilling activities in the Gulf of Mexico and the Rockies. Impairments of unproved properties increased by $89 million primarily in the Gulf of Mexico due to expiration of leases and for certain U.S. onshore oil and gas properties as a result of changes in the Company’s drilling plans.

For the six months ended June 30, 2014 , exploration expense increased by $359 million . Dry hole expense increased by $199 million primarily due to unsuccessful 2014 drilling activities in the Gulf of Mexico, New Zealand, and the Rockies, compared to unsuccessful 2013 drilling activities in Sierra Leone, Côte d’Ivoire, and Kenya. Impairments of unproved properties increased by $147 million primarily in Sierra Leone and certain U.S. onshore oil and gas properties as a result of changes in the Company’s drilling plans and in the Gulf of Mexico due to expiration of leases. Geological and geophysical expense increased by $20 million primarily due to 2014 seismic purchases in Côte d’Ivoire, New Zealand, and Colombia, partially offset by 2013 seismic purchases in the Gulf of Mexico and South Africa.

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	Three Months Ended June 30,						Six Months Ended June 30,
millions except percentages	2014		Inc/(Dec) vs. 2013		2013		2014		Inc/(Dec) vs. 2013		2013
General and administrative	$	305	17	%	$	260	$	603	13	%	$	532
Depreciation, depletion, and amortization	1,048		11		940		2,172		11		1,962
Other taxes	361		47		245		675		29		525
Impairments	117		NM		10		120		NM		39

For the three months ended June 30, 2014, general and administrative (G&A) expense increased by $45 million primarily due to higher employee-related expenses of $20 million primarily due to increased headcount, higher legal fees of $13 million, increased insurance premiums of $5 million, and higher consulting fees of $5 million. For the six months ended June 30, 2014 , G&A expense increased by $71 million primarily due to higher employee-related expenses of $20 million primarily due to increased headcount, higher legal fees of $14 million, increased insurance premiums of $12 million, and higher consulting fees of $8 million.

Depreciation, depletion, and amortization (DD&A) expense increased by $108 million for the three months ended June 30, 2014, primarily due to higher sales volumes in 2014. DD&A expense increased by $210 million for the six months ended June 30, 2014 , primarily due to higher sales volumes in 2014 and increased asset retirement costs for fully depleted wells in the Gulf of Mexico.

For the three months ended June 30, 2014, other taxes increased by $116 million primarily due to higher Algerian exceptional profits taxes of $82 million due to increased crude-oil volumes in Algeria and higher ad valorem taxes of $30 million due to increased activity related to U.S. onshore properties. For the six months ended June 30, 2014, other taxes increased by $150 million primarily due to higher Algerian exceptional profits taxes of $100 million and higher U.S. onshore ad valorem taxes of $46 million as discussed above.

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. Impairment expense for the three and six months ended June 30, 2013, included $10 million related to the Company’s Venezuelan cost-method investment that was impaired due to declines in estimated recoverable value. Impairment expense for the six months ended June 30, 2013 , also included $29 million related to a midstream property that was impaired due to a reduction in estimated future cash flows.



	Three Months Ended June 30,				Six Months Ended June 30,
millions	2014		2013		2014		2013
Deepwater Horizon settlement and related costs	$	93	$	4	$	93	$	7

In the second quarter of 2014, the Company recorded a $90 million expense and contingent liability associated with a civil penalty under the Clean Water Act (CWA) related to the Deepwater Horizon event-related claims. For additional information, see Note 11—Contingencies —Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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Other (Income) Expense



	Three Months Ended June 30,								Six Months Ended June 30,
millions except percentages	2014			Inc/(Dec) vs. 2013		2013			2014			Inc/(Dec) vs. 2013		2013
Interest Expense
Debt and other	$	233		(2	)%	$	238		$	473		1	%	$	470
Capitalized interest	(47		)	29		(66		)	(104		)	22		(134		)
Interest expense	$	186		8		$	172		$	369		10		$	336

Interest expense increased by $14 million for the three months ended June 30, 2014, and $33 million for the six months ended June 30, 2014, primarily due to a decrease in capitalized interest related to lower construction-in-progress balances for long-term capital projects.



	Three Months Ended June 30,					Six Months Ended June 30,
millions	2014		2013			2014		2013
(Gains) Losses on Derivatives, net
(Gains) losses on commodity derivatives, net	$	164	$	(394	)	$	379	$	(111	)
(Gains) losses on interest-rate and other derivatives, net	159		(262		)	397		(354		)
(Gains) losses on derivatives, net	$	323	$	(656	)	$	776	$	(465	)

Anadarko enters into commodity derivatives to manage the risk of changes in the market prices for its anticipated sales of production and enters into interest-rate swaps to fix or float interest rates on existing or anticipated indebtedness to manage exposure to interest-rate changes. (Gains) losses on derivatives, net represents the changes in fair value of the Company’s derivative instruments. For the three and six months ended June 30, 2014 , the fair market value of derivative instruments decreased due to lower interest rates and higher commodity prices.



	Three Months Ended June 30,								Six Months Ended June 30,
millions except percentages	2014			Inc/(Dec) vs. 2013		2013			2014			Inc/(Dec) vs. 2013		2013
Other (Income) Expense, net
Interest income	$	(4	)	100	%	$	(2	)	$	(7	)	75	%	$	(4	)
Other	(9		)	109		100			(5		)	105		96
Total other (income) expense, net	$	(13	)	113		$	98		$	(12	)	113		$	92

Total other income increased by $111 million for the three months ended June 30, 2014, and $104 million for the six months ended June 30, 2014 . In June 2013, as a result of a Chapter 11 bankruptcy declaration by the third party, the U.S. Department of the Interior ordered Anadarko to perform the decommissioning of the facility and related wells, which were previously sold to a third party. The Company accrued $141 million during the second quarter of 2013 to decommission the production facilities and related wells. Anadarko completed decommissioning of the production facilities in 2014 and expects to complete decommissioning of the wells in 2015. In addition, other income increased $23 million for the three months ended June 30, 2014, and $28 million for the six months ended June 30, 2014 , due to changes in foreign currency gains/losses. These gains/losses reflected the 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. These increases were partially offset by the second-quarter 2013 reversal of the $56 million tax indemnification liability associated with the 2006 sale of the Company’s Canadian subsidiary. The indemnity was reversed as a result of certain Canadian tax legislative changes.

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	Three Months Ended June 30,				Six Months Ended June 30,
millions	2014		2013		2014		2013
Tronox-related contingent loss	$	19	$	—	$	4,319	$	—

In April 2014, Anadarko and Kerr-McGee Corporation and certain of its subsidiaries (collectively, Kerr-McGee) entered into a settlement agreement to resolve all claims asserted in the Adversary Proceeding and under the Federal Debt Collection Procedures Act (FDCPA Complaint) for $5.15 billion. In May 2014, the U.S. Bankruptcy Court for the Southern District of New York (Bankruptcy Court) issued its Findings of Fact and Conclusions of Law recommending approval of the settlement agreement. The settlement agreement is subject to approval by the U.S. District Court for the Southern District of New York (New York District Court) and the issuance of an injunction by the New York District Court barring similar claims from third parties. 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 of $19 million during the second quarter of 2014, for an aggregate $5.17 billion Tronox-related contingent liability included on the Company’s Consolidated Balance Sheet at June 30, 2014 . See Note 11—Contingencies —Tronox Litigation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Income Tax Expense



	Three Months Ended June 30,						Six Months Ended June 30,
millions except percentages	2014			2013			2014			2013
Income tax expense (benefit)	$	428		$	567		$	1,092		$	1,023
Effective tax rate	62		%	37		%	(86		)%	41		%

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Net Income Attributable to Noncontrolling Interests

The Company’s net income attributable to noncontrolling interests for the three and six months ended June 30, 2014 and 2013, related to public ownership interests in Western Gas Partners, LP (WES) and WGP. Public ownership in WES consisted of a 56.8% limited partnership interest at June 30, 2014, and 54.5% at June 30, 2013 . Public ownership in WGP consisted of a 9.0% limited partnership interest at June 30, 2014 and 2013 .

In July 2014, Anadarko sold 5.75 million WGP limited partner units to the public, raising net proceeds of $335 million . After the sale, public ownership in WGP consisted of an 11.7% limited partner interest. See Note 6—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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, Algeria exceptional profits tax settlement, 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	2014			Inc/(Dec) vs. 2013		2013			2014			Inc/(Dec) vs. 2013		2013
Income (loss) before income taxes	$	694		(55	)%	$	1,526		$	(1,268	)	(151	)%	$	2,466
Exploration expense	502			182		178			801			81		442
DD&A	1,048			11		940			2,172			11		1,962
Impairments	117			NM		10			120			NM		39
Interest expense	186			8		172			369			10		336
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	237			137		(641		)	600			NM		(395		)
Deepwater Horizon settlement and related costs	93			NM		4			93			NM		7
Algeria exceptional profits tax settlement	—			NM		—			—			(100	)	33
Tronox-related contingent loss	19			NM		—			4,319			NM		—
Certain other nonoperating items	—			(100	)	85			—			(100	)	85
Less net income attributable to noncontrolling interests	39			30		30			82			52		54
Consolidated Adjusted EBITDAX	$	2,857		27		$	2,244		$	7,124		45		$	4,921
Adjusted EBITDAX by reporting segment
Oil and gas exploration and production	$	2,997		32	%	$	2,269		$	7,387		54	%	$	4,795
Midstream	154			35		114			317			33		239
Marketing	(47		)	(7	)	(44		)	(86		)	(12	)	(77		)
Other and intersegment eliminations	(247		)	(160	)	(95		)	(494		)	NM		(36		)

Oil and Gas Exploration and Production Adjusted EBITDAX for the three and six months ended June 30, 2014, increased primarily due to higher sales volumes for crude oil and NGLs, and higher commodity prices. These increases were partially offset by higher operating expenses, primarily other taxes, which increased as a result of higher sales volumes and commodity prices. Adjusted EBITDAX for the six months ended June 30, 2014, was also impacted by a $1.5 billion gain associated with the Company’s 2014 divestiture of a 10% working interest in Rovuma Offshore Area 1 in Mozambique.

Midstream The increase in Adjusted EBITDAX for the three and six months ended June 30, 2014, was primarily due to higher gathering revenue as a result of increased throughput across several of Anadarko’s systems.

Marketing Marketing earnings primarily represent the margin earned on sales of natural gas, oil, and NGLs purchased from third parties. For the three and six months ended June 30, 2014, Adjusted EBITDAX decreased primarily due to higher transportation expenses.

Other and Intersegment Eliminations Other and intersegment eliminations consist primarily of corporate costs, income from hard-minerals royalties, and net cash from settlement of commodity derivatives. The decrease in Adjusted EBITDAX for the three and six months ended June 30, 2014, was primarily due to higher payments for the settlement of commodity derivatives in 2014 . The decrease in Adjusted EBITDAX for the six months ended June 30, 2014, was also due to a $140 million gain associated with the Company’s 2013 divestiture of its interest in a soda ash joint venture.

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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 to maintain the Company’s desired capital structure and to finance acquisition opportunities. Liquidity may also be enhanced through asset divestitures and joint ventures that reduce future capital expenditure requirements.

Consistent with this approach, during the six months ended June 30, 2014, cash flows from operating activities were the primary source for funding capital investments. 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, 2014 , Anadarko had no scheduled debt maturities during the next year. Anadarko’s Zero-Coupon Senior Notes due 2036, which can be put to the Company in October 2014 (the next potential put date), in whole or in part, for the then-accreted value of $756 million , are classified as long-term debt on the Company’s Consolidated Balance Sheets, as the Company has the ability and intent to refinance this obligation using long-term debt should the notes be put to the Company in October 2014. 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, and the Company’s $5.0 billion senior secured revolving credit facility maturing in September 2015 ($5.0 billion Facility) or the New Credit Facilities (see discussion below). Management believes that the Company’s liquidity position, asset portfolio, and continued strong operating and financial performance provide the necessary financial flexibility to fund the Company’s current and long-term operations.

Effects of Tronox Adversary Proceeding on Liquidity In April 2014, Anadarko and Kerr-McGee entered into a settlement agreement to resolve all claims asserted in the Adversary Proceeding and FDCPA Complaint for $5.15 billion, which represents principal of approximately $3.98 billion plus 6% interest from the filing of the Adversary Proceeding on May 12, 2009, through April 3, 2014. In addition, interest will be paid on the above amount from April 3, 2014, through the date of payment of the settlement, with interest of 1.5% for the first 180 days and 1.5% plus the one-month LIBOR thereafter. In May 2014, the Bankruptcy Court issued its Findings of Fact and Conclusions of Law recommending approval of the settlement agreement. The settlement agreement is still subject to approval by the New York District Court and the issuance of an injunction barring similar claims from third parties. Once the New York District Court’s approval of the settlement agreement and issuance of the injunction are final and non-appealable, the Company will have two business days to transmit the settlement payment. The Company’s significant cash position and available $5.0 billion Facility provide sufficient resources and flexibility to fund the settlement payment. The Company currently expects this process to be completed during the second half of 2014. See Note 11—Contingencies —Tronox Litigation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Revolving Credit Facilities Obligations incurred under the $5.0 billion Facility, as well as obligations Anadarko has to lenders or their affiliates pursuant to certain derivative instruments, as discussed in Note 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q, are guaranteed by certain of the Company’s wholly owned domestic subsidiaries, and are secured by a perfected first-priority security interest in certain exploration and production assets located in the United States and 65% of the capital stock of certain wholly owned foreign subsidiaries. At June 30, 2014 , the Company had no outstanding borrowings under the $5.0 billion Facility, there were no restrictions on its ability to use this borrowing capacity, and the Company was in compliance with all applicable covenants.

In June 2014, Anadarko entered into the New Credit Facilities, which will replace the existing secured $5.0 billion Facility upon satisfaction of certain conditions including (i) repaying amounts owed under the $5.0 billion Facility in full and all associated commitments and liens being terminated or released; (ii) the New York District Court entering an order approving the settlement agreement related to the Adversary Proceeding and issuing an injunction barring certain third-party claims; and (iii) Anadarko making payment pursuant to the terms of the settlement agreement related to the Adversary Proceeding. These conditions must be satisfied or waived by the lenders under each of the New Credit Facilities by December 1, 2014, or the commitments thereunder will terminate.

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WES Funding Sources Anadarko’s consolidated subsidiary, WES, 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.

In February 2014, WES entered into its RCF, which amended and restated its then-existing $800 million senior unsecured revolving credit facility. At June 30, 2014, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $110 million at an interest rate of 1.46% , and had available borrowing capacity of approximately $1.1 billion ( $1.2 billion maximum capacity, less $110 million of outstanding borrowings and $13 million of outstanding letters of credit). See Financing Activities below.

During the second quarter of 2014, WES sold common units under its continuous offering program, which authorizes the issuance of up to an aggregate of $125 million of common units. During the second quarter of 2014, WES issued approximately one million common units to the public under its continuous offering program, raising net proceeds of $74 million .

Sources of Cash

Operating Activities Anadarko’s cash flow from operating activities during the six months ended June 30, 2014, was $4.2 billion , compared to $5.0 billion for the same period of 2013 . The decrease is primarily due to $698 million of cash received in 2013 associated with the Algeria exceptional profits tax settlement, a $520 million income tax payment in 2014 associated with the Company’s divestiture of a 10% working interest in Rovuma Offshore Area 1 in Mozambique, net cash paid in settlement of commodity derivative instruments, and the unfavorable impact of changes in working capital items, partially offset by higher average commodity prices for all products and higher sales volumes for crude oil and NGLs.

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 dependent on the costs related to continued operations and debt service.

Investing Activities During the six months ended June 30, 2014, Anadarko received pretax proceeds of $3.3 billion primarily related to the Company’s divestitures of a 10% working interest in Rovuma Offshore Area 1 in Mozambique for $2.64 billion and its interest in the Pinedale/Jonah assets in Wyoming for $581 million.

Financing Activities During the six months ended June 30, 2014, Anadarko’s consolidated subsidiary, WES, borrowed $590 million under its RCF primarily to fund its February 2014 acquisition of Anadarko’s interests in Texas Express Pipeline LLC, Texas Express Gathering LLC, and Front Range Pipeline LLC, and for other general partnership purposes, including the funding of capital expenditures. In March 2014, WES completed a public offering of $100 million aggregate principal amount of 2.600% Senior Notes due 2018 and $400 million aggregate principal amount of 5.450% Senior Notes due 2044, with proceeds from the offering used to repay borrowings under its RCF and for general partnership purposes. Also during the first quarter of 2014, WES issued 300,000 common units to the public pursuant to the partial exercise of the underwriters’ over-allotment option granted in connection with WES’s December 2013 equity offering, raising additional net proceeds of $18 million . During the second quarter of 2014, WES also issued approximately one million common units under its continuous offering program, raising net proceeds of $74 million , as discussed in WES Funding Sources.

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In July 2014, the Company issued $625 million aggregate principal amount of 3.450% Senior Notes due 2024 and $625 million aggregate principal amount of 4.500% Senior Notes due 2044. These proceeds will be used for general corporate purposes. Also in July 2014, Anadarko sold 5.75 million WGP limited partner units to the public, raising net proceeds of $335 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.

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



	Six Months Ended June 30,
millions	2014		2013
Property acquisitions
Exploration	$	92	$	94
Development	112		8
Exploration	786		729
Development	3,149		1,842
Capitalized interest	93		117
Total oil and gas capital expenditures	4,232		2,790
Gathering, processing, and marketing and other ⁽¹⁾	738		823
Total capital expenditures ⁽²⁾	$	4,970	$	3,613

________________________________________________________________________________________


⁽¹⁾	Includes WES capital expenditures of $343 million for the six months ended June 30, 2014, and $437 million for the six months ended June 30, 2013 .


⁽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 increased by $1.4 billion for the six months ended June 30, 2014, due to increased U.S. onshore development drilling primarily in the Wattenberg field of $498 million, the Eagleford shale of $421 million, and the Delaware basin of $84 million, as well as a spar lease buyout of $110 million in the Gulf of Mexico, and increased exploration drilling of $57 million. The increase in the Eagleford shale was primarily due to the 2013 development drilling being funded by a third party as a result of a carried-interest agreement that was fully funded in June 2013. These increases were partially offset by lower gathering, processing, and marketing and other expenditures, primarily due to the 2013 acquisition of a 33.75% interest in gas-gathering systems located in the Marcellus shale in north-central Pennsylvania from a third party for $135 million.

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 majority of Anadarko’s expected future capital costs through first production, which is expected to occur by mid-2016. At June 30, 2014 , $241 million of the total $860 million obligation had been funded.

In the third quarter of 2012, the Company entered into a carried-interest arrangement that required a third-party partner to fund $556 million of Anadarko’s capital costs in exchange for a 7.2% working interest in the Lucius development, located in the Gulf of Mexico. During the second quarter of 2014, as dictated by the Unitization and Participation Agreement, the working interests of all partners in the Lucius development were recalculated. As a result, Anadarko’s working interest in the Lucius development was reduced from 27.8% to 23.8% and its capital expenditures were reduced by $44 million due to the re-determination. In addition, the working interest of the third party that participated in the carried-interest arrangement was reduced from 7.2% to 6.2%, which resulted in a reduction in the funding commitment from $556 million to $476 million. The funding commitment covered the majority of the Company’s expected capital costs through first production, which is expected to occur in the second half of 2014. At June 30, 2014, the $476 million funding commitment was fully funded.

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Investments During the six months ended June 30, 2014, the Company made capital contributions of $89 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 marine well containment and pipelines.

Debt Retirements and Repayments Anadarko repaid $775 million of Senior Notes that matured during the six months ended June 30, 2014 . Also, WES repaid $480 million of borrowings under its RCF with proceeds from its debt offering, as discussed in Sources of Cash.

Interest-rate Swaps Interest-rate swap agreements with an aggregate notional principal amount of $750 million were settled in June 2014, resulting in a cash payment of $222 million , classified within cash flows from financing activities. In addition, during the second quarter of 2014, to align the interest-rate swap portfolio with anticipated debt financing, the Company extended the reference-period start dates from June 2014 to September 2016 and adjusted the related fixed interest rates for interest-rate swaps with an aggregate notional principal amount of $1.1 billion. For additional information, see Note 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Common Stock Dividends and Distributions to Noncontrolling Interest Owners Anadarko paid dividends of $230 million to its common stockholders during the six months ended June 30, 2014, and $92 million during the six months ended June 30, 2013 . 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. The Company also increased the quarterly dividend paid to common stockholders from $0.09 per share to $0.18 per share during the third quarter of 2013. 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 $83 million during the six months ended June 30, 2014, and $59 million during the six months ended June 30, 2013 . 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 $0.65 per common unit for the second quarter of 2014 (to be paid in August 2014).

WGP distributed to its unitholders other than Anadarko an aggregate of $10 million during the six months ended June 30, 2014 , and $4 million during the six months ended June 30, 2013 . 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 $0.27125 per unit for the second quarter of 2014 (to be paid in August 2014).

Outlook

The Company is committed to the execution of its worldwide exploration, appraisal, and development programs. The Company estimates a 2014 capital spending range of $9.0 billion to $9.5 billion. This amount includes $614 million to $664 million of WES capital expenditures, excluding any acquisitions made by WES. The Company plans to allocate approximately 70% of its 2014 capital spending to development activities, 15% to exploration activities, and 15% to gas-gathering and processing activities and other business activities. The Company expects its 2014 capital spending by area to be approximately 60% for the U.S. onshore region and Alaska, 15% for the Gulf of Mexico, 15% for Midstream and other, and 10% for International.

Anadarko believes that its cash on hand and expected level of operating cash flows will be sufficient to fund the Company’s projected operational and capital programs for 2014 and continue to meet its other obligations. The Company’s cash on hand is available for use and could be supplemented, as needed, with available borrowing capacity under the $5.0 billion Facility or the New Credit Facilities. In addition, these items provide flexibility in funding the settlement payment related to the Adversary Proceeding.

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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. In order to reduce commodity-price risk and increase the predictability of 2014 cash flows, Anadarko entered into strategic derivative positions, which cover approximately 65% of its remaining 2014 anticipated natural-gas sales volumes and 47% of its remaining 2014 anticipated crude-oil sales volumes. In addition, the Company has derivative positions in place for 2015 . See Note 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

In February 2014, the Company entered into an agreement to sell its Chinese subsidiary for $1.075 billion. The transaction is expected to close in the third quarter of 2014 and is subject to customary closing conditions.

Recent Accounting Developments The Financial Accounting Standards Board issued Accounting Standards Update (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 2017 and is required to be adopted using one of two retrospective application methods, with no early adoption permitted. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.

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

COMMODITY PRICE RISK The Company’s most significant market risk relates to prices for natural gas, crude 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 and sustained decline. The types of commodity derivative instruments utilized 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.

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Derivative Instruments Held for Non-Trading Purposes The Company had derivative instruments in place to reduce the price risk associated with future production of 526 Bcf of natural gas and 35 MMBbls of crude oil at June 30, 2014 , with a net derivative liability position of $167 million . Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $476 million , while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $460 million . However, any cash received or paid to settle these derivatives would be substantially offset by the realized sales value of production covered by the derivative instruments.

Derivative Instruments Held for Trading Purposes At June 30, 2014 , the Company had a net derivative asset position of $12 million ( gains of $16 million and losses of $4 million ) on outstanding derivative instruments entered into for trading purposes. Based on actual derivative contractual volumes, a 10% increase or decrease in underlying commodity prices would not materially impact the Company’s gains or losses on these derivative instruments.

INTEREST-RATE RISK Any borrowings under the $5.0 billion Facility or the New Credit Facilities, and the WES RCF are subject to variable interest rates. The balance of Anadarko’s long-term debt on the Company’s Consolidated Balance Sheets is subject to fixed interest rates. The Company’s $2.9 billion of London Interbank Offered Rate (LIBOR) based obligations, which are presented on the Company’s Consolidated Balance Sheets net of preferred investments in two non-controlled entities, give rise to minimal net interest-rate risk because coupons on the related preferred investments are also LIBOR-based. A 10% increase in LIBOR would not impact the Company’s interest cost on fixed-rate debt already outstanding, but would affect fair value of outstanding fixed-rate debt.

At June 30, 2014 , the Company had a net derivative liability position of $829 million 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 approximately $114 million . However, any change in the interest-rate derivative gain or loss could be substantially offset by changes in actual borrowing costs associated with any future debt issuances. For a summary of the Company’s outstanding interest-rate derivative positions, see Note 7—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

FOREIGN-CURRENCY EXCHANGE-RATE RISK Anadarko’s operating revenues are realized in U.S. dollars, and the predominant portion of Anadarko’s capital and operating expenditures are 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, 2014 , cash of $154 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.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934. 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 Securities Exchange Act of 1934 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 Securities Exchange Act of 1934 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, 2014 .

Changes in Internal Control over Financial Reporting

There were no changes in Anadarko’s internal control over financial reporting during the second quarter of 2014 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; 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, with the possible exception of the Tronox Litigation discussed in Note 11—Contingencies —Tronox Litigation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q, the resolution of pending proceedings will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

Anadarko is currently in negotiations with the U.S. Environmental Protection Agency (EPA) concerning enforcement for alleged noncompliance with a consent decree entered into by the U.S. District Court of the District of Colorado on March 27, 2008. This consent decree was entered into to resolve certain Clean Air Act violations. The EPA has identified alleged violations of the consent decree at two of Anadarko’s compressor station facilities located in Utah. 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.

WGR Operating, LP, a wholly owned subsidiary of the Company, is currently in negotiations with the EPA concerning enforcement for 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 11—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, 2013 , and material matters that have arisen since the filing of such report.

Item 1A. Risk Factors

Consider carefully the risk factor included below, as well as those under the caption “Risk Factors” under Part I, Item 1A in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 , together with all of the other information included in this Form 10-Q; in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 ; and in the Company’s other public filings, press releases, and public discussions with Company management.

Colorado state and local ballot, legislative and regulatory initiatives relating to our oil and gas operations could result in increased costs, additional operating restrictions, delays or prohibitions, and could adversely affect our production.

Certain states in which we operate have adopted, and other states are considering adopting, measures that could impose new or more stringent permitting, disclosure, and additional well location and well-construction requirements related to our exploration or production operations. For example, in Colorado, several initiatives have been proposed for inclusion on the Colorado state ballot in November 2014. Although it is early in the political process, if approved these initiatives would give local governments in Colorado greater authority to limit hydraulic fracturing and other oil and gas operations and/or require greater distances between certain well sites and occupied structures. In the event state or local restrictions or prohibitions are adopted in areas where we currently conduct operations (such as in the Wattenberg field, which is among the largest and most cost-efficient oil and natural gas development projects in Anadarko’s U.S. onshore portfolio) or in the future plan to conduct operations, we may incur significant costs to comply with such requirements or we may experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves. Depending on the areas in which they are adopted, such restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

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In the event that the settlement agreement related to the Adversary Proceeding is not approved, post-trial proceedings related to the Adversary Proceeding would continue and we may incur liabilities in excess of the amount provided for in the settlement agreement, which could have a material adverse effect on our business, prospects, results of operations, cash flows, financial condition, and liquidity.

On April 3, 2014, Anadarko and Kerr-McGee Corporation and certain of its subsidiaries (collectively, Kerr-McGee) entered into a settlement agreement with the Litigation Trust and the U.S. government (in its capacity as plaintiff-intervenor and acting for and on behalf of certain U.S. government agencies) to resolve all claims asserted in the Adversary Proceeding and under the Federal Debt Collection Procedures Act for $5.15 billion, which represents principal of approximately $3.98 billion plus 6% interest from the filing of the Adversary Proceeding on May 12, 2009, through April 3, 2014. In addition, interest will be paid on the above amount from April 3, 2014, through the date of payment of the settlement, with interest of 1.5% for the first 180 days and 1.5% plus the one-month London Interbank Offered Rate thereafter. For additional information, see Note 11—Contingencies —Tronox Litigation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

The Adversary Proceeding has been stayed pending final approval of the settlement agreement. In May 2014, the U.S. Bankruptcy Court for the Southern District of New York (Bankruptcy Court) issued its Findings of Fact and Conclusions of Law recommending approval of the settlement agreement. The settlement agreement is subject to approval by the U.S. District Court for the Southern District of New York (New York District Court) and the issuance of an injunction by the New York District Court barring similar claims from third parties. The settlement payment will be made once both the New York District Court’s approval of the settlement agreement and the issuance of the injunction are final and non-appealable. Although the Company currently expects the approval process to be completed during the second half of 2014, the actual timing to complete the process is not certain. In the event the New York District Court does not approve the settlement agreement, the post-trial proceedings relating to the Adversary Proceeding would continue and Kerr-McGee could be subject to a judgment by the Bankruptcy Court regarding damages, including interest and attorneys’ fees. In such event, the Company’s liabilities relating to Tronox could exceed the amount provided for in the settlement agreement and we could incur additional liabilities that we are unable to estimate or predict at this time. These events could have a material adverse effect on our business, prospects, consolidated financial position, results of operations, cash flows, financial condition, and liquidity.

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 2014 .



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	1,726	$	98.07	—
May	3,412	$	99.74	—
June	3,366	$	102.98	—
Second-Quarter 2014	8,504	$	100.68	—	$	—

____________________________________________________________


⁽¹⁾	During the second quarter of 2014 , 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 not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith or double asterisk (**) and are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.



Exhibit Number			Description	File Number
	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	1-8968
		(ii)	By-Laws of Anadarko Petroleum Corporation, amended and restated as of May 15, 2012, filed as exhibit 3.1 to Form 8-K filed on May 15, 2012	1-8968
*	10	(i)	Anadarko Petroleum Corporation Deferred Compensation Plan (as amended and restated effective as of January 1, 2012)
*	10	(ii)	First Amendment, dated December 17, 2013, to the Anadarko Petroleum Corporation Deferred Compensation Plan (as amended and restated effective as of January 1, 2012)
	10	(iii)	Settlement Agreement dated as of April 3, 2014, by and among (1) the Anadarko Litigation Trust, (2) the United States of America in its capacity as plaintiff-intervenor in the Tronox Adversary Proceeding and acting for and on behalf of certain U.S. government agencies and (3) Anadarko Petroleum Corporation, Kerr-McGee Corporation, and certain other subsidiaries, filed as exhibit 10.1 to Form 8-K filed on April 3, 2014	1-8968
	10	(iv)	Credit Agreement, dated as of June 17, 2014, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, National Association, as Syndication Agent, Bank of America, N.A., Citibank, N.A., The Royal Bank of Scotland plc, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Co-Documentation Agents, and the additional lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on June 23, 2014	1-8968
	10	(v)	364-Day Revolving Credit Agreement, dated as of June 17, 2014, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, National Association, as Syndication Agent, Bank of America, N.A., Citibank, N.A., The Royal Bank of Scotland plc, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Co-Documentation Agents, and the additional lenders party thereto, filed as Exhibit 10.2 to Form 8-K filed on June 23, 2014	1-8968
*	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
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Table of Contents

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 29, 2014	By:	/s/ ROBERT G. GWIN
		Robert G. Gwin Executive Vice President, Finance and Chief Financial Officer

EXHIBIT 10(i)

Execution Copy

Anadarko Petroleum Corporation

Deferred Compensation Plan

Amended and Restated effective as of January 1, 2012

Table of Contents



			Page
PURPOSE			1

ARTICLE 1 - DEFINITIONS			1
	1.1	Account	1
	1.2	Administrator	1
	1.3	Annual Retainer Fees	1
	1.4	Base Pay	1
	1.5	Beneficiary	2
	1.6	Board	2
	1.7	Bonus	2
	1.8	Change of Control	2
	1.9	Code	3
	1.10	Company	4
	1.11	Compensation Committee	4
	1.12	Contingent Beneficiary	4
	1.13	Director	4
	1.14	Director Compensation	4
	1.15	Disabled	4
	1.16	Effective Date	4
	1.17	Eligible Employee	4
	1.18	ERISA	4
	1.19	Key Employee	4
	1.20	Meeting Fees	5
	1.21	Participant	5
	1.22	Plan	5
	1.23	Plan Year	5
	1.24	Retirement	5
	1.25	Section 16 Officer	5
	1.26	Separation from Service	5
	1.27	Unforeseeable Emergency	6
	1.28	Valuation Date	6

ARTICLE 2 - PARTICIPATION			6
	2.1	Participation	6
	2.2	Cessation of Active Participation	6

ARTICLE 3 - DEFERRAL ELECTIONS			6
	3.1	Deferral Agreement	6
	3.2	Election to Defer Base Pay	7
	3.3	Election to Defer Bonus	7
	3.4	Election to Defer Director Compensation	7
	3.5	Timing of Election to Defer	7
	3.6	Election of Payment Schedule and Form of Payment	8

ARTICLE 4 - PARTICIPANT ACCOUNT			10
	4.1	Individual Accounts	10



ARTICLE 5 - INVESTMENT OF CONTRIBUTIONS			11
	5.1	Investment Options	11
	5.2	Adjustment of Accounts	11
	5.3	Distributions from the Company Stock Fund	11

ARTICLE 6 - RIGHT TO BENEFITS			11
	6.1	Vesting	11
	6.2	Death	12
	6.3	Disability	13

ARTICLE 7 - DISTRIBUTION OF BENEFITS			13
	7.1	Amount of Benefits	13
	7.2	Method and Timing of Distributions	13
	7.3	Unforeseeable Emergency	13
	7.4	Cashouts of Minimal Interests	14
	7.5	Distribution to a Key Employee	14

ARTICLE 8 - AMENDMENT AND TERMINATION			14
	8.1	Amendment by Company	14
	8.2	Retroactive Amendments	15
	8.3	Special Plan and Deferral Election Amendments	15
	8.4	Plan Termination	15
	8.5	Distribution Upon Termination of the Plan	16

ARTICLE 9 - THE TRUST			16
	9.1	Establishment of Trust	16
	9.2	Grantor Trust	16
	9.3	Investment of Trust Funds	16
	9.4	Participants’ Rights under a Trust	16

ARTICLE 10 - MISCELLANEOUS			17
	10.1	Unsecured General Creditor of the Company	17
	10.2	Limitation of Rights	17
	10.3	The Company’s Liability	17
	10.4	Satisfaction of Benefit Obligation	17
	10.5	Spend-thrift Provision	18
	10.6	Incapacity of Participant or Beneficiary	18
	10.7	Waiver	18
	10.8	Notices	19
	10.9	Tax Withholding	19
	10.10	Governing Law	19
	10.11	Intention to Comply with Code Section 409A	19

ARTICLE 11 - PLAN ADMINISTRATION			20
	11.1	Powers and Responsibilities of the Administrator	20
	11.2	Interpretation of the Plan	20
	11.3	Claims and Review Procedures	21
	11.4	Plan Administrative Costs	21

PURPOSE

The Anadarko Petroleum Corporation Deferred Compensation Plan (the “Plan”) was originally established effective as of January 1, 2005, and is hereby amended and restated effective as of January 1, 2012. The purpose of the Plan is to permit eligible employees and non-employee directors to defer receipt of certain compensation into a subsequent tax year which would otherwise be payable to them in the then-current tax year.

The Plan is intended to be a “plan which is unfunded and is maintained by an employer primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees” within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of ERISA and shall be implemented and administered in a manner consistent therewith. The Plan is also intended to (i) be exempt from the participation and vesting, funding, and fiduciary responsibility requirements of Title I of ERISA and (ii) qualify for simplified reporting under the U.S. Department of Labor Regulation Section 2520.104-23, as may be amended from time to time.

ARTICLE 1 - DEFINITIONS

Pronouns used in the Plan are in the masculine gender but include the feminine gender unless the context clearly indicates otherwise. Wherever used herein, the following terms have the meanings set forth below, unless a different meaning is clearly required by the context:

1.1

“ Account ” means an account established by the Administrator for the purpose of recording amounts credited on behalf of each Participant under the Plan, and any income, expenses, gains, losses or distributions included thereon. The Account shall be a bookkeeping entry only and shall be utilized solely as a device for the measurement and determination of the amounts to be paid to each Participant pursuant to the Plan.

1.2

“ Administrator ” means the Vice President—Human Resources of Anadarko Petroleum Corporation and delegates operating under the authority of the Vice President—Human Resources, including authorized third-party service providers, except that for all matters pertaining to the establishment, continuance, availability to Plan participants, operation and termination of the Company Stock Fund (as defined in Section 5.3 of the Plan) and for all matters (including, without limitation, interpretation of the Plan) directly relating to participation, claims or benefits associated with individuals who are then Directors or Section 16 Officers, “Administrator” shall mean the Compensation Committee.


1.3	“ Annual Retainer Fees ” means the annual fees (other than Meeting Fees) paid to a Director by the Company for service on the Board or committee(s) of the Board, including the Board retainer, lead director retainer, committee chair and member retainers and any other forms of retainer paid to a Director for service on the Board.


1.4	“ Base Pay ” means base compensation per payroll period paid by the Company to an Eligible Employee (including amounts which the Eligible Employee could have received in cash had he not elected to contribute to an employee benefit plan maintained by the Company), excluding overtime pay, bonuses, employee benefits, added premiums,

differentials, components of foreign service assignments, and any other form of incentive compensation.

1.5

“ Beneficiary ” means the persons, trusts, estates or other entities designated under Section 6.2 to receive benefits under the Plan upon the death of a Participant. “Contingent Beneficiary” means the persons, trusts, estates or other entities designated under Section 6.2 to receive benefits under the Plan upon the death of a Participant and in the event that the designated Beneficiary predeceases a Participant.


1.6	“ Board ” means the Board of Directors of Anadarko Petroleum Corporation.

1.7

“ Bonus ” means the bonus otherwise payable currently to a Participant for the Plan Year under the Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, or any predecessor or successor plans thereto, or any other incentive or bonus arrangement implemented after the Effective Date by the Company if the Company designates payments under such program or arrangement as being Bonuses which may be deferred pursuant to this Plan.


1.8	“ Change of Control ” means that a Change of Control of the Company shall be deemed to have occurred on the date as of the first day any one or more of the following conditions shall have been satisfied:

(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: (A) any acquisition directly from the Company, (B) any acquisition by the Company, (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company or (D) any acquisition pursuant to a transaction which complies with clauses (i), (ii) or (iii) of Section 1.8(c); or

(b)

Individuals who, as of January 1, 2010, 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 January 1, 2010 whose election, or nomination for election by the Company’s stockholders, 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 sixty percent (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, twenty percent (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 stockholders of the Company of a complete liquidation or dissolution of the Company.

Notwithstanding the foregoing provisions of this Section 1.8 or any provision of this Plan to the contrary, to the extent that any payment or acceleration of payment of any amount under the Plan is subject to, and not exempt under, Code Section 409A, then the determination of whether a Change of Control has occurred hereunder as affecting the payment, or timing of payment, of such amount shall be made within the meaning of such term as set forth in Code Section 409A to the extent inconsistent with the foregoing provisions of this definition, as determined in the discretion of the Administrator.


1.9	“ Code ” means the Internal Revenue Code of 1986, as amended from time to time. All references herein to any Section of the Code shall include any successor provision thereto and the Treasury Regulations and other authority issued under such Section by the appropriate governmental authority.


1.10	“ Company ” means Anadarko Petroleum Corporation and its wholly owned subsidiaries, unless the context requires otherwise (such as, for example, in Section 1.8 where the term “Company” shall refer solely to Anadarko Petroleum Corporation).


1.11	“ Compensation Committee ” means the Compensation and Benefits Committee of the Board, the composition of which may change from time to time.


1.12	“ Contingent Beneficiary ” shall have the definition set forth in Section 1.5.


1.13	“ Director ” means a non-employee member of the Board.

1.14 “ Director Compensation" means Annual Retainer Fees and Meeting Fees.

1.15

“ Disabled ” or “ Disability ” means a Participant shall be deemed to have become permanently disabled if the Participant (i) is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, or (ii) is, by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, receiving income replacement benefits for a period of not less than three (3) months under a disability plan or an accident and health plan maintained by the Company, if applicable.

1.16 “Effective Date” means January 1, 2012, the effective date of this amendment and restatement of the Plan.

1.17

“ Eligible Employee ” means an employee of the Company who is paid on the Company’s U.S. payroll and (i) is “a member of a select group of management or highly compensated employees” (within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of ERISA) and (ii) is designated by the Company in its complete discretion as being an Eligible Employee for purposes of the Plan. An employee who does not satisfy these criteria is an “ Ineligible Employee .”


1.18	“ ERISA ” means the Employee Retirement Income Security Act of 1974, as may be amended from time to time. All references herein to any Section of ERISA shall include any successor provision thereto and the regulations and other authority issued under such Section by the appropriate governmental authority.

1.19

“ Key Employee ” means a Participant who is a “specified employee” as defined in Code Section 409A. For purposes of this definition, a “specified employee” under Code Section 409A is an employee who, as of the date of his Separation from Service, is a “key employee” (within the meaning of Code Section 416(i) without regard to paragraph 5 thereof relating to beneficiaries) of the Company or any entity which is considered to be a single employer with the Company under Code Section 414(b) or 414(c) (the “ Controlled Group ”). A Participant shall be a Key Employee if the Participant is (i) an officer of the Company having annual compensation greater than $165,000 for 2012 (and as indexed thereafter under Code Section 416(i)), (ii) a 5-percent (5%) owner of the Company, or (iii) a 1-percent (1%) owner of the Company having annual compensation

of more than $150,000, at any time during the twelve (12) month period ending on December 31, but only if a Controlled Group member has any stock that is publicly traded on an established securities market or otherwise. A Participant will be considered to be a Key Employee for the period April 1 through March 31 following such December 31 determination. The Company may apply an alternative method to identify Key Employees in accordance with Code Section 409A, provided that the alternative method (i) is reasonably designed to include all Key Employees, (ii) is an objectively determinable standard, and (iii) results in either all employees or no more than 200 employees being identified as Key Employees as of any date.


1.20	“ Meeting Fees ” means fees paid to a Director for attendance at meetings of the Board or meetings of the Board’s committees.


1.21	“ Participant ” means any Eligible Employee or any Director who becomes a participant in the Plan pursuant to Article 2. An individual who becomes a Participant as provided in the preceding sentence shall remain a Participant until he no longer has an undistributed Account balance under the Plan.


1.22	“ Plan ” means the Anadarko Petroleum Corporation Deferred Compensation Plan, as amended and restated as set forth herein, and as it may be further amended from time to time.


1.23	“ Plan Year ” means the twelve (12) consecutive month period beginning January 1st and ending December 31st of any given year.

1.24

“ Retirement ” means, in the case of an Eligible Employee who is eligible to retire under the Anadarko Retirement Plan (the “ Anadarko Plan ”), his Separation from Service; provided, however, that the Eligible Employee has, as of such date, both attained age fifty-five (55) and been credited with at least five (5) years of Credited Service as that term is defined under the Anadarko Plan. Retirement means, in the case of an Eligible Employee who is eligible to retire under the Kerr-McGee Corporation Retirement Plan (the “KMG Plan”), his Separation from Service; provided, however, that the Eligible Employee has, as of such date, both attained age fifty-two (52) and been credited with at least ten (10) years of Credited Service as that term is defined under the KMG Plan. Retirement means, in the case of a Director, Separation from Service from the Board after the first to occur of: (a) the Director having attained age sixty-five (65), (b) the Director having completed ten (10) years of service as a Director, or (c) the Director having attained both age fifty-five (55) and completed five (5) years of service as a Director. A Director’s total years of service as a Director as of any date shall be determined by dividing his total completed full months of service as a Director by twelve (12).


1.25	“ Section 16 Officer ” means an Eligible Employee who is subject to the requirements of Section 16 of the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.


1.26	“ Separation from Service ” means a “separation from service” of an Eligible Employee or Director within the meaning of Code Section 409A.

1.27

“ Unforeseeable Emergency ” means a severe financial hardship to the Participant resulting from an illness or accident of the Participant, the Participant’s spouse, the Participant’s Beneficiary, or a dependent (as defined in Code Section 152(a)) of the Participant, loss of the Participant’s property due to casualty, or other similar extraordinary and unforeseeable circumstance arising as a result of events beyond the control of the Participant.


1.28	“ Valuation Date ” means each business day of the Plan Year and such other date(s) as designated by the Company.

ARTICLE 2 - PARTICIPATION


2.1	Participation . Each Eligible Employee and Director shall become a Participant in the Plan by executing a deferral agreement in accordance with the provisions of Article 3.

2.2

Cessation of Active Participation . In the event that (i) the service on the Board of a Participant who is a Director terminates, or (ii) a Participant who is an Eligible Employee incurs a Separation from Service for any reason, such Director or Eligible Employee, as applicable, may not make deferral elections under Article 3 and any deferral election presently in effect for such Director or Eligible Employee shall terminate immediately; however, any compensation subject to a valid deferral election under the Plan and earned with respect to any period preceding the effective time of such cessation of the right to defer compensation hereunder shall be deferred pursuant to such election, even if such crediting of such amount to his Account occurs after such effective time. In the event that a Participant becomes an Ineligible Employee for any reason other than Separation from Service (including, without limitation, by reason of the Company, in its sole discretion, designating a Participant as an Ineligible Employee), such Participant may not make deferral elections under Article 3 immediately after the Participant becomes an Ineligible Employee; however, any irrevocable deferral election made prior to the time that the Participant became an Ineligible Employee shall remain in effect, unless voided as stated herein in connection with a subsequent Separation from Service. At the discretion of the Company or the Administrator, an individual who has become a Participant in the Plan shall cease to be entitled to defer compensation hereunder at the time and in such manner as determined by the Company or the Administrator to be necessary or appropriate to comply with applicable law or regulations or to coordinate with other benefit plans of the Company; provided, however, that such cessation is permitted and consistent with the requirements of Code Section 409A. Upon any termination of a Participant’s right to defer compensation hereunder, the provisions of Section 7.2 shall continue to apply to such Participant’s Account.

ARTICLE 3 - DEFERRAL ELECTIONS

3.1

Deferral Agreement . Each Eligible Employee and Director may elect to defer compensation amounts otherwise payable to him currently for a Plan Year by executing a deferral agreement in accordance with (a) rules and procedures established by the Administrator, (b) the provisions of this Article 3, and (c) Code Section 409A. The deferral agreement may separately specify for each discrete type of compensation ( e.g. ,

Base Pay, Bonus, Director Compensation, or individual components of each) the whole number percentage multiple (in one percent (1%) increments and subject to the percentage limitations otherwise described herein) that the Participant elects to defer, the payment schedule and form of payment of the deferred amount.

A new deferral agreement must be executed in a timely manner (as set forth in this Article 3) for each Plan Year during which the Eligible Employee or Director elects to defer compensation. An Eligible Employee or Director who does not execute a deferral agreement in a timely manner shall be deemed to have elected zero deferrals for such Plan Year.

A deferral agreement may be changed or revoked at any time during the respective election periods specified in Section 3.5. A deferral agreement becomes irrevocable at the close of the respective election period. However, with regard to a Participant who is first designated as an Eligible Employee during a Plan Year, the initial deferral election of that Participant under Section 3.5 for such Plan Year becomes irrevocable as of the time of such initial election. An irrevocable deferral election may be subsequently modified only as permitted in Section 7.2.


3.2	Election to Defer Base Pay . An Eligible Employee may elect to defer Base Pay for a Plan Year in an amount not exceeding seventy-five percent (75%) of Base Pay.

3.3

Election to Defer Bonus . An Eligible Employee may elect to defer up to one hundred percent (100%) of his Bonus for a Plan Year, subject to any limitation that may be established by the Administrator and specified on the deferral agreement. A Participant who is first designated as an Eligible Employee after January 1st of a Plan Year may not elect to defer his Bonus for that Plan Year but may elect to defer his Bonus for subsequent Plan Years.


3.4	Election to Defer Director Compensation . A Director may elect to defer up to one hundred (100%) of his Director Compensation for a Plan Year.

3.5

Timing of Election to Defer . Each Eligible Employee who desires to defer Base Pay otherwise payable during a Plan Year must execute a deferral agreement in accordance with the procedures established by the Administrator and within the election period preceding the Plan Year during which the Base Pay will be earned, as specified by the Administrator (but not later than December 31 ^st immediately preceding such Plan Year and will be irrevocable as of such date). Each Eligible Employee who is eligible to defer a Bonus which may be earned with respect to services performed during a Plan Year pursuant to Section 3.3 and who desires to defer such Bonus must execute a deferral agreement in accordance with the rules and procedures established by the Administrator (but not later than December 31st immediately preceding such Plan Year except that if the plan or arrangement providing for such Bonus is “performance-based compensation based on services performed over a period of at least 12 months” (as described in Code Section 409A(a)(4)(B)(iii)), then such deferral election must be executed no later than the date six (6) months before the end of the performance period over which the Bonus is earned (provided that (a) the Eligible Employee performs services continuously from the

later of the beginning of the performance period or the date the performance criteria are established through the date such election is made and (b) such compensation has not become readily ascertainable as of the date of such election), and such election will be irrevocable as of such date).

A Director who desires to defer his Director Compensation otherwise payable during a Plan Year must execute a deferral agreement in accordance with the procedures established by the Administrator (but not later than December 31 ^st immediately preceding such Plan Year and will be irrevocable as of such date).

An employee who is first designated as an Eligible Employee during a Plan Year may elect to defer Base Pay for such Plan Year in accordance with the rules of this Section 3.5, except that his initial deferral agreement must be executed within the thirty (30)-day period beginning on the date such employee is designated as an Eligible Employee. A new Director may elect to defer his Director Compensation in accordance with the rules of this Section 3.5 except that his initial deferral agreement must be executed within the thirty (30)-day period beginning on the date he first becomes a Director.

3.6

Election of Payment Schedule and Form of Payment . At the time an Eligible Employee or Director completes a deferral agreement provided by the Administrator, the Eligible Employee or Director may separately elect for each type of compensation being deferred ( i.e. , Base Pay, Bonus, Director Compensation, or individual components of each) the following items: (i) the date of distribution or commencement of distribution of each deferred amount, (ii) the form of payment in which each deferred amount will be distributed ( e.g. , lump sum or annual installments), and (iii) if applicable and as may be provided by the Administrator, whether the amount distributed will be in cash, Company Stock (as defined in Section 5.3) or a combination of cash and Company Stock. Subject to the provisions of Article 7, an Eligible Employee or Director may elect to receive distribution of his deferred amount in a single lump sum or annual installment distributions over a period certain not exceeding fifteen (15) years. If the Participant should elect installment payments over a designated time period, each installment payment shall be considered a separate payment for purposes of Code Section 409A.

The portion of the Participant’s Account that has been earned and vested as of January 1, 2010 (as well as any subsequent earnings, expenses, gains and losses attributed to such balance) (“ Pre-2010 Account ”) shall be distributed as follows:


(a)	If the Participant’s Separation from Service occurs before he becomes eligible for Retirement, notwithstanding any other election, his distribution shall be made as follows:


(1)	If the Participant initially elected to be paid upon his Separation from Service following Retirement, his distribution shall be made in a lump-sum payment no later than ninety (90) days after the date of his Separation from Service; or


(2)	If the Participant initially elected to be paid upon an identified and specific date that is at least three (3) years after the date the deferral agreement was effective, then if payment has not already commenced, his distribution shall be made or shall commence on such identified and specific date; or

(3)

If the Participant initially elected to be paid upon the earlier of (A) Separation from Service following Retirement or (B) an identified and specific date that is at least three (3) years after the date the deferral agreement was effective, then if payment has not already been made or commenced, his distribution shall be made in a lump sum payment no later than ninety (90) days after the date of his Separation from Service.


(b)	If the Participant’s Separation from Service occurs after he becomes eligible for Retirement, then the distribution or commencement of distribution shall be one of the following options as previously elected by the Participant:


(1)	Separation from Service; or


(2)	an identified and specific date that is at least three (3) years after the date the deferral agreement was executed; or

(3)

the earlier of (A) Separation from Service or (B) an identified and specific date that is at least three (3) years after the date the deferral agreement was executed. This option (3) provides that the date of distribution specified in the deferral agreement will be honored unless a Separation from Service intervenes before the scheduled date of distribution, in which case payment will be made, in the form originally elected by the Participant, not later than the date that is ninety (90) days after the Separation from Service date.

The portion of the Participant’s Account that is earned and vested on and after January 1, 2010 (as well as any subsequent earnings, expenses, gains and losses attributed to such balance) (“ Post-2009 Account ”) shall be distributed as follows:


(a)	If the Participant’s Separation from Service occurs before he becomes eligible for Retirement, notwithstanding any other election, his distribution shall be made as follows:


(1)	If the Participant initially elected to be paid upon his Separation from Service following Retirement, his distribution shall be made in a lump-sum payment no later than ninety (90) days after the date of his Separation from Service; or


(2)	If the Participant initially elected to be paid upon an identified and specific date that is at least one (1) year after the date the deferral agreement was effective, then if payment has not already commenced, his distribution shall be made or shall commence on such identified and specific date; or

(3)

If the Participant initially elected to be paid upon the earlier of (A) Separation from Service following Retirement or (B) an identified and specific date that is at least one (1) year after the date the deferral agreement was effective, then if payment has not already been made or commenced, his distribution shall be made in a lump sum payment no later than ninety (90) days after the date of his Separation from Service.


(b)	If the Participant’s Separation from Service occurs after he becomes eligible for Retirement, then the distribution or commencement of distribution shall be one of the following options as previously elected by the Participant:


(1)	Separation from Service; or


(2)	an identified and specific date which is at least one (1) year after the date the deferral agreement was executed; or

(3)

the earlier of (A) Separation from Service or (B) an identified and specific date which is at least one (1) year after the date the deferral agreement was executed. This option (3) provides that the date of distribution specified in the deferral agreement will be honored unless a Separation from Service intervenes before the scheduled date of distribution, in which case payment will be made, in the form originally elected by the Participant, not later than the date that is ninety (90) days after the Separation from Service date.

In addition, regardless of whether Retirement is attained by the Participant, he may elect a “Change of Control Override.” A Change of Control Override election provides that the date and form of distribution specified in the deferral agreement will be honored unless a Change of Control intervenes before the scheduled date of distribution, in which case, payment will be made in a single lump sum within ninety (90) days after the effective date of the Change of Control without regard to whether Participant has incurred a Separation from Service. Notwithstanding any provision in the Plan to the contrary, for purposes of effectuating an accelerated payment hereunder pursuant to a Change of Control Override, the term “Change of Control” shall mean a Change of Control (as defined in Section 1.8 of the Plan) but only to the extent that the event causing the Change of Control qualifies under Code Section 409A(a)(2)(A)(v).

ARTICLE 4 - PARTICIPANT ACCOUNT

4.1

Individual Accounts . The Administrator will establish and maintain an Account for each Participant that reflects deferrals made pursuant to Article 3, together with earnings, expenses, gains and losses that are attributable to investments of such Account as provided in Article 5. The amount a Participant elects to defer in accordance with Article 3 shall be credited to the Participant’s Account at the time the amount subject to the deferral election would otherwise have been payable to the Participant but for his deferral election. The Administrator will establish and maintain such other accounts and records

as it determines, in its discretion, to be reasonably required or appropriate to discharge its duties under the Plan.

ARTICLE 5 - INVESTMENT OF CONTRIBUTIONS


5.1	Investment Options . The amount credited to a Participant’s Account shall be treated as invested in the investment options as designated for this purpose by the Administrator. Such investment options may be different for Eligible Employees, Section 16 Officers and Directors, as determined by the Administrator in its discretion.

5.2

Adjustment of Accounts . The amount credited to a Participant’s Account shall be adjusted for hypothetical investment earnings or losses in an amount equivalent to the earnings or losses reported by the investment options selected by the Participant or Beneficiary from among the investment options provided in Section 5.1. A Participant may, in accordance with rules and procedures established by the Administrator, change the investments to be used for the purpose of calculating future hypothetical investment adjustments to the Participant’s Account or to future Participant deferrals, which election change shall be effective as of the Valuation Date coincident with or next following notice to the Administrator. The Account of each Participant shall be adjusted as of each Valuation Date to reflect: (a) the hypothetical investment earnings and/or losses described above; (b) Participant deferrals; and (c) distributions or withdrawals from the Account.

5.3

Distributions from the Company Stock Fund . To the extent that any portion (including a percentage thereof as provided by the Administrator) of a Participant’s Account is invested in an investment fund maintained under the Plan which invests primarily in the common stock of the Company (either directly or in the form of phantom shares) (“ Company Stock Fund ”), such Participant may have the right to elect to receive distribution in shares of common stock of the Company (“ Company Stock ”), but only with respect to the portion of his Account balance that is invested in the Company Stock Fund, with such election to be made at such time and in such form as determined by the Administrator. Any fractional shares of Company Stock allocated to the Participant’s Account shall be distributed in cash. If a Participant does not elect to receive his distribution in shares of Company Stock, then the entire balance shall be distributed in cash.

ARTICLE 6 - RIGHT TO BENEFITS

6.1

Vesting . At all times, each Participant has a one hundred percent (100%) nonforfeitable interest in all amounts credited to his Account. Notwithstanding the foregoing or any provision of the Plan to the contrary, if otherwise provided pursuant to a Company plan or program for which a benefit has been deferred under the Plan, a Participant may be subject to certain “claw back” or forfeiture of benefits in certain circumstances, in which case a Participant’s Account may be reduced in an amount necessary to satisfy such “claw back” or forfeiture.

6.2

Death . Notwithstanding any prior election regarding the form or timing of his distribution, the balance or remaining balance credited to a Participant’s Account shall be paid to his Beneficiary in a single lump-sum cash payment within ninety (90) days following the Participant’s death. If multiple Beneficiaries have been designated by the Participant, each Beneficiary shall receive a single lump-sum cash payment of his specified portion of the Participant’s Account balance within such ninety (90) day period. If the Participant has not specified percentages for multiple Beneficiaries, his Account will be divided and distributed to them on a per capita basis.

A Participant may designate a Beneficiary or Beneficiaries, or change any prior designation of Beneficiary or Beneficiaries in accordance with rules and procedures established by the Administrator (including, but not limited to, the right to require the consent of a Participant’s spouse in the event the spouse is not named as the sole primary Beneficiary).

If a designated Beneficiary predeceases a Participant, the amount apportioned to that designated Beneficiary shall be payable to the designated Contingent Beneficiary, if any. If a Beneficiary dies within thirty (30) days of the date the Participant dies, the Beneficiary shall be considered to have predeceased the Participant for purposes of this Section 6.2.

If the Administrator finds either that there is no designated Beneficiary for all or a portion of a Participant’s Account, or that the designated Beneficiary and any Contingent Beneficiary for all or a portion of a Participant’s account have predeceased the Participant, the amount in question shall be paid as follows: (a) if the Participant leaves a surviving spouse, the entire Account balance shall be paid to the surviving spouse, and (b) only if the Participant leaves no surviving spouse, the entire Account balance shall be paid (i) first to the executor or administrator of the Participant’s estate, or (ii) if there is no administration of his estate, to the Participant’s heirs at law, as determined by the Administrator.

Notwithstanding the preceding provisions of this Article 6 and to the extent not prohibited by state or federal law, if a Participant is divorced from his spouse and, at the time of his death, is not remarried to the person from whom he was divorced, any designation of such divorced spouse shall be null and void unless the contrary is expressly stated in a writing that is filed by the Participant with the Administrator and accepted by the Administrator. The amount that would otherwise have been paid to such divorced spouse shall instead be paid to the persons specified in accordance with the applicable provisions of this Article 6 as if such divorced spouse did not survive the Participant.

If the Administrator is in doubt as to the right of any person to receive any amount hereunder, the Administrator, in its discretion, may direct that the entire Account balance be paid into any court of competent jurisdiction in an interpleader action, and such payment shall be a full and complete discharge of any liability or obligation under the Plan to the full extent of such payment.


6.3	Disability . Notwithstanding any prior election regarding the form or timing of his distribution, the balance or remaining balance credited to a Participant’s Account shall be paid to the Participant in a single lump-sum cash payment within ninety (90) days following the date the Participant is determined to be Disabled.

ARTICLE 7 - DISTRIBUTION OF BENEFITS


7.1	Amount of Benefits . The amount credited to a Participant’s Account as determined under Articles 4, 5 and 6 shall determine and constitute the basis for the value of benefits payable to the Participant under the Plan.

7.2

Method and Timing of Distributions . Subject to Sections 7.3 and 7.4, distributions under the Plan shall be made at the time and in the manner provided in Section 3.6. If allowed by the Administrator, a Participant may elect to further delay the payment date for a minimum period of sixty (60) months from the originally scheduled date of payment, provided that such election to delay payment (a) is made at least twelve (12) months before a scheduled date of payment and (b) is not effective until at least twelve (12) months after the date on which the election is made. A re-deferral election must be made in accordance with procedures and rules established by the Administrator, which shall be construed and administered in accordance with Code Section 409A. The Participant may, at the same time the date of payment is re-deferred, change the form of payment provided that such change in the form of payment does not effectuate an acceleration of payment. Notwithstanding any provision contained herein to the contrary, a distribution made to a Key Employee due to his Separation from Service (for any reason except due to his death) shall not be made before the date which is six (6) months after the date the Key Employee has a Separation from Service unless otherwise permitted under Code Section 409A, such as in the event of his death.

7.3

Unforeseeable Emergency . A Participant may request a distribution due to an Unforeseeable Emergency. The request must be in writing and must be submitted to the Administrator along with evidence that the circumstances constitute an Unforeseeable Emergency. The Administrator has the discretion to require whatever evidence it deems necessary to determine whether a distribution is warranted. Whether a Participant has incurred an Unforeseeable Emergency will be determined by the Administrator on the basis of the relevant facts and circumstances in its sole discretion, but, in no event, will an Unforeseeable Emergency be deemed to exist if the hardship can be relieved: (a) through reimbursement or compensation by insurance or otherwise, (b) by liquidation of the Participant’s assets to the extent such liquidation would not itself cause severe financial hardship, or (c) by cessation of deferrals under the Plan. A distribution due to an Unforeseeable Emergency must be limited to the amount reasonably necessary to satisfy the emergency need and may also include any amount necessary to pay any federal, state or local income taxes or penalties that are reasonably anticipated to result from the distribution. The distribution will be made in the form of a single lump-sum cash payment without regard to any prior distribution election. Any distribution under this Section 7.3 shall be deducted from the Participant’s Account balance as of the date of the distribution.

7.4

Cashouts of Minimal Interests . If the amount credited to the Participant’s Account does not exceed the current dollar limitation under Code Section 402(g)(1)(B) ($17,000 in 2012, as adjusted under the Code in future years, or such higher dollar amount as Treasury Regulations may establish for cashouts of minimal interests under Code Section 409A), at the time he has a Separation from Service, and such Participant is not a Key Employee, the Company reserves the right to pay such amount to the Participant in accordance with the requirements of Code Section 409A in a single lump-sum cash payment within ninety (90) days following such Separation from Service, regardless of whether the Participant (i) had made a different election regarding time or form of payment or (ii) was receiving installment payments at the time of Separation from Service. In the case of a Key Employee, such cashout payment shall not be made before the date that is at least six (6) months from the date of his Separation from Service or such earlier date upon which such amount can be paid under Code Section 409A without being subject to taxation thereunder.


7.5	Distribution to a Key Employee . Notwithstanding any provision of the Plan to contrary, any lump sum or installment payment distribution payable to a Participant who is a Key Employee due to his Separation from Service (for any reason except due to his death) shall not be made before the date that is six (6) months after the date of his Separation from Service.

ARTICLE 8 - AMENDMENT AND TERMINATION

8.1

Amendment by Company . The Company reserves the right to amend the Plan through action of the Board or the Compensation Committee. An amendment must be in writing and executed by an officer authorized to take such action. Each amendment shall not be effective prior to approval by the Board or the Compensation Committee in its resolution, unless necessary to comply with applicable laws or regulations. No amendment can directly or indirectly deprive any current or former Participant or Beneficiary of all or any portion of his Account balance that has accrued as of the date of such amendment. In addition to amendments made by the Board or the Compensation Committee, the Chief Financial Officer of Anadarko Petroleum Corporation and the General Counsel of Anadarko Petroleum Corporation, acting jointly (the “ Authorized Officers ”), may approve, adopt and execute any amendment to the Plan that is necessary for purposes of legal compliance, to clarify ambiguities in the Plan document, and to simplify non-material administrative processes, as the Authorized Officers may, in their best judgment, so determine; provided further that the Authorized Officers may not terminate the Plan. The Authorized Officers together may delegate to another officer of the Company the authority to execute an amendment to the Plan that has been approved jointly by the Authorized Officers.

Notwithstanding the preceding paragraph of this Section 8.1, the Plan may be amended if required to ensure that the Plan is characterized as a “top-hat plan” of deferred compensation maintained for a select group of management or highly compensated employees as described under ERISA Sections 201(2), 301(a)(3), and 401(a)(1), or to conform the Plan to the requirements of ERISA for “top-hat plans” or the requirements of the Code for deferred compensation plans including Code Section 409A. No such

amendment for this exclusive purpose shall be considered prejudicial to the interest of a Participant or a Beneficiary hereunder.

8.2

Retroactive Amendments . An amendment made by the Company in accordance with Section 8.1 may be made effective on a date prior to the first day of the Plan Year in which it is adopted if such amendment is necessary or appropriate to enable the Plan to satisfy the applicable requirements of the Code, ERISA or to any other change in federal law or to any regulations or ruling thereunder. Any retroactive amendment by the Company shall be subject to the provisions of Section 8.1.

8.3

Special Plan and Deferral Election Amendments . Notwithstanding Sections 8.1 or 8.2 or any other provision of the Plan or a deferral election agreement to the contrary, the Company has reserved the unilateral right and discretion to amend the Plan and a Participant’s deferral elections hereunder to the extent necessary to comply with Code Section 409A, or to be exempt from the application of Code Section 409A, to the maximum extent permitted under Code Section 409A.


8.4	Plan Termination . The Plan has been adopted with the intention and expectation that it will be continued indefinitely. The Company, however, reserves the right to terminate the Plan at any time without any liability for any such discontinuance or termination.

In the event of the termination of the Plan, no additional vesting shall accrue on a Participant’s behalf after the termination date. In accordance with Code Section 409A, termination of the Plan shall not, by itself, create a distribution event.

Upon termination of the Plan, distribution of benefits shall be made to Participants and Beneficiaries in the same manner and at the same time as described in the Plan, unless one of the following termination events occurs, in which case, all such amounts shall be distributed in a lump sum upon termination, or upon the earliest date allowable under Code Section 409A:


(a)	the Company’s termination and liquidation of the Plan within twelve (12) months of a corporate dissolution taxed under Code Section 331, or with the approval of a bankruptcy court pursuant to 11 U.S.C. Section 503(b)(1)(A);

(b)

the Company’s termination and liquidation of the Plan pursuant to irrevocable action taken by the Company within the thirty (30) days preceding or twelve (12) months following a change of control event (within the meaning of Code Section 409A), provided that all agreements, methods, programs, and other arrangements sponsored by the Company or an affiliated entity that are aggregated under Code Section 409A are terminated and liquidated with respect to each Participant that experiences the change in control event; or


(c)	the Company’s termination and liquidation of the Plan, provided that (1) the termination and liquidation does not occur proximate to a downturn in the financial health of the Company; (2) the Company terminates and liquidates all agreements, methods, programs, and other arrangements sponsored by the Company that would be aggregated under Code Section 409A if the same

Participant had deferrals of compensation under all of the agreements, methods, programs, and other arrangements sponsored by the Company that are terminated and liquidated; (3) no payments in liquidation of the Plan are made within twelve (12) months of the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan other than payments that would have been payable absent the termination and liquidation; and (4) the Company does not adopt a new plan that would be aggregated with any terminated and liquidated plan under Code Section 409A if the same Participant participated in both plans, at any time within three (3) years following the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan.


8.5	Distribution Upon Termination of the Plan . Upon termination of the Plan, no further contributions that have not accrued as of the termination date shall be made under the Plan. Each Participant’s Account at the time of termination shall continue to be governed by the terms of the Plan until fully distributed in accordance with the terms of the Plan.

ARTICLE 9 - THE TRUST


9.1	Establishment of Trust . The Company may, but is not required to, establish a trust, or use an existing trust, to hold amounts which the Company may contribute from time to time to correspond to some or all amounts credited to Participants under Section 4.1. If the Company elects to establish a trust, the provisions of Sections 9.2 and 9.3 shall be operative.

9.2

Grantor Trust . The Company may establish a trust, or use an existing trust, between the Company and a trustee pursuant to a separate written trust agreement. Any such trust shall be created as a grantor trust under the Code Sections 671-678, and the establishment of the trust shall not cause the Participant to realize current income on amounts contributed to the trust. In the event that the Company establishes such a trust or uses an existing trust, the Company shall be under no obligation to place assets in such trust to secure the Company’s payment obligations under the Plan.

9.3

Investment of Trust Funds . Any amounts contributed to a trust described in this Article 9 may be invested by the trustee in accordance with the provisions of the trust agreement and the instructions of the Administrator or the Company. Trust investments need not reflect the hypothetical investments selected by Participants under Section 5.1 for the purpose of adjusting Account balances, and the investment results of the trust shall not affect the hypothetical investment adjustments to Accounts under the Plan.

9.4

Participants’ Rights under a Trust . The assets of any trust hereunder shall be held for the benefit of the Participants in accordance with the terms of the Plan and the trust agreement. The assets of the trust shall remain subject to the claims of the general creditors of the Company, and the rights of the Participants to the amounts in the trust shall be limited in the event that the Company becomes insolvent. No Participant or Beneficiary shall have any preferred claim to, or any beneficial ownership interest in, any assets of the trust fund.

ARTICLE 10 - MISCELLANEOUS

10.1

Unsecured General Creditor of the Company . Participants and their Beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interests or claims in any property or assets of the Company as the result of participating in the Plan. For purposes of the payment of benefits under the Plan, any and all of the Company’s assets shall be, and shall remain, the general, unpledged, unrestricted assets of the Company, and as such, shall remain subject to the claims of the general creditors of the Company. The Company’s obligation under the Plan shall be merely that of an unfunded and unsecured promise to pay compensation in the future.


10.2	Limitation of Rights . Nothing in this plan shall be construed to:


(a)	Give any individual who is employed by the Company any right to be a Participant unless and until such person is selected under the terms of the Plan;


(b)	Give any Participant any rights, other than as an unsecured general creditor of the Company;


(c)	Limit in any way the right of the Company to terminate an Eligible Employee’s employment;


(d)	Give a Participant or any other person any interest in any trust, fund or in any specific asset of the Company; or


(e)	Be evidence of any agreement or understanding, express or implied, that the Company will employ a Participant in any particular position, at any particular rate of remuneration, or for any particular time period.


10.3	The Company’s Liability . The Company’s liability for the payment of benefits under the Plan shall be defined only by the Plan and by the deferral agreements, and form and timing of payment elections, as entered into between a Participant and the Company under the Plan. The Company shall have no obligation or liability to a Participant under the Plan except as provided by the Plan.

10.4

Satisfaction of Benefit Obligation . The Company may, but is not obligated, to purchase an annuity or other insurance/financial product to satisfy the payment of benefit obligations for some or all of the Participants under the Plan. In the event that such an annuity or other product is utilized and a Participant or his Beneficiary has received the benefits entitled under the Plan from such annuity or other product, then such benefit obligation under the Plan shall be considered satisfied. Any annuity or other product used to provide funding under the Plan shall be an asset of the Company, and no Participant shall have any beneficial ownership interest in such asset of the Company.

In order to meet its contingent obligations under the Plan, the Company shall not set aside any assets or otherwise create any type of fund in which any Participant (or any person claiming under such Participant) has an interest other than that of an unsecured general creditor of the Company or that would provide any Participant, or any person claiming

under such Participant, with a legally enforceable right to priority over any general creditor of the Company in the event that the Company becomes insolvent.

10.5

Spend-thrift Provision . No amount payable or to become payable from the Plan will be subject to: (a) anticipation or assignment by any person entitled to receive benefits under the Plan; (b) attachment by, interference with, or control of any creditor of any person entitled to receive benefits under the Plan; or (c) being taken or reached by any legal or equitable process in satisfaction of any debt or liability of any person entitled to receive benefits under the Plan. Any attempted conveyance, transfer, assignment, mortgage, pledge, or encumbrance of the Plan, any part of it or any interest in it, by any person entitled to receive benefits under the Plan prior to distribution will be void, regardless of whether that conveyance, transfer, assignment, mortgage, pledge, or encumbrance is intended to be effective before or after any distribution of benefits under the Plan. In addition, the Administrator shall not recognize any conveyance, transfer, assignment, mortgage, pledge or encumbrance by any person entitled to receive benefits under the Plan, and shall not pay any amount to any creditor or assignee of such person for any cause whatsoever. However, this Section 10.5 shall not affect the provisions of Section 10.1 regarding the claims of general creditors of the Company.

In the event that any Participant’s or Beneficiary’s benefits hereunder are attempted to be garnished or attached by order of any court, the Company, in its discretion, may bring an action or a declaratory judgment in a court of competent jurisdiction to determine the proper recipient of the benefits to be paid under the Plan.

10.6

Incapacity of Participant or Beneficiary . If the Administrator determines, in its discretion, that any Participant or Beneficiary to whom a payment is payable under the Plan is unable to care for his affairs because of illness or accident or is under a legal disability, any payment due (unless a prior claim therefore shall have been made by a duly appointed legal representative), at the discretion of the Administrator, may be paid to the spouse, child, parent, sibling of such Participant or Beneficiary or to any person whom the Administrator has determined has incurred expense for such Participant or Beneficiary. In the event that a guardian, conservator or other person legally vested with the care of any person receiving a benefit under the Plan is appointed by a court of competent jurisdiction, payments shall be made to such guardian, conservator or other person, provided that proper proof of appointment is furnished in a form and manner acceptable to the Administrator. Any payment made in accordance with this Section 10.6 shall be a complete discharge of the obligations of the Company under the Plan.

10.7

Waiver . No term or condition of the Plan shall be deemed to have been waived, nor shall there be an estoppel against the enforcement of any provision of the Plan, except by written instrument of the party charged with such waiver or estoppel. No such written waiver shall be deemed a continuing waiver unless specifically stated therein, and each such waiver shall operate only as to the specific term or condition waived and shall not constitute a waiver of such term or condition for the future or as to any act other than that specifically waived.


10.8	Notices . Any notice or other communication in connection with the Plan shall be deemed delivered in writing if addressed as provided below and if either actually delivered at said address or, in the case of a letter, five (5) business days shall have elapsed after the same shall have been deposited in the U.S. mails, first-class postage prepaid and registered or certified:


(a)	The Company or Administrator — If the notice is sent to the Company or Administrator, it must be sent to the then-current corporate headquarters address of the Company, provided that the envelope includes “Attn: Benefits Department — Human Resources”; or


(b)	Participant — The mailing or electronic address of the Participant as reflected in the then-current records of the Company. Each Participant is responsible for ensuring that the Company or Administrator has the Participant’s current mailing address under the procedure for updating mailing addresses utilized by the Company or Administrator.

10.9

Tax Withholding . The Company shall have the right to deduct from all payments or deferrals made under the Plan any tax required by law to be withheld. If the Company concludes that tax is owing with respect to any deferral or payment hereunder, the Company shall withhold such amounts from any payments due the Participant, as permitted by law, or otherwise make appropriate arrangements with the Participant or his Beneficiary for satisfaction of such obligation. A tax, for purposes of this Section 10.9 means any federal, state, local or any other governmental income tax, employment or payroll tax, excise tax, or any other tax or assessment that is owed with respect to amounts deferred (and any earnings thereon) and any payments made to Participants under the Plan.

With respect to deferred compensation elections under the Plan, the Company shall withhold the required share of FICA, FUTA and other applicable employment and payroll taxes from the other non-deferred compensation of an Eligible Employee who is a Participant. These required payroll taxes shall be withheld at the same time that the deferred compensation contributions are credited to his Account.


10.10	Governing Law . The Plan will be construed, administered and enforced according to ERISA, the Code and other controlling federal law, and to the extent not preempted thereby, the laws of the State of Texas without regard to its conflicts of law principles.

10.11

Intention to Comply with Code Section 409A . The Plan is intended to comply with Code Section 409A and any ambiguous provision will be construed in a manner that is compliant with, or exempt from, the application of Code Section 409A. It is intended that since January 1, 2009, the Plan will comply with provisions of Code Section 409A and the final regulations and other authoritative guidance thereunder. It is also intended that during the period beginning January 1, 2005 and ending December 31, 2008, the Plan was operated in reasonable good faith compliance with the provisions of Code Section 409A and the interim authoritative guidance thereunder. If any provision of the Plan would cause a Participant to incur any additional tax or interest under Code Section

409A, the Company may reform such provision to comply with Code Section 409A to the maximum extent permitted under Code Section 409A as determined by the Company.

ARTICLE 11 - PLAN ADMINISTRATION


11.1	Powers and Responsibilities of the Administrator . The Administrator has the full power, full discretion and the full responsibility to administer the Plan in all of its details, subject, however, to the applicable requirements of applicable law. The Administrator’s powers and responsibilities include, but are not limited to, the following:


(a)	To make and enforce such rules and procedures as it deems necessary or proper for the efficient administration of the Plan;


(b)	To interpret the Plan, its interpretation thereof in good faith to be final and conclusive on all persons claiming benefits under the Plan;


(c)	To decide all questions concerning the Plan and the eligibility of any person to participate in the Plan;


(d)	To administer the claims and review procedures specified in Section 11.3, including determining all facts pertaining to a claim;


(e)	To compute the amount of benefits which will be payable to any Participant, former Participant or Beneficiary in accordance with the provisions of the Plan;


(f)	To determine the person or persons to whom such benefits will be paid;


(g)	To authorize the payment of benefits;


(h)	To comply with the reporting and disclosure requirements of Part I. of Subtitle B of Title I of ERISA;


(i)	To appoint such agents, counsel, accountants, and consultants as may be required to assist in administering the Plan;


(j)	By written instrument, to allocate and delegate its responsibilities hereunder to designated persons or entities, including without limitation, to employees of the Company; and


(k)	To address and resolve any and all matters that may arise with regard to the Plan and its administration.

11.2

Interpretation of the Plan . The Administrator shall interpret, construe and construct the Plan, including correcting any defect, supplying any omission or reconciling any inconsistency. The Administrator shall have all powers necessary or appropriate to implement and administer the terms and provisions of the Plan, including the power to make findings of fact. The determination of the Administrator as to the proper

interpretation, construction, or application of any term or provision of the Plan shall be final, binding, and conclusive with respect to all Participants and other interested persons.

11.3

Claims and Review Procedures . Claims for Plan benefits and reviews of appeals of benefit claims arising under the Plan that have been denied or modified are to be processed in accordance with written Plan claims procedures established by the Administrator and adopted by the Company. The Plan’s claims and appeal procedures shall be established and administered in accordance with the applicable requirements for such procedures under ERISA.


11.4	Plan Administrative Costs . Unless otherwise determined by the Administrator, all reasonable costs and expenses (including legal, accounting, and employee communication fees) incurred by the Administrator in administering the Plan shall be paid by the Company.

IN WITNESS WHEREOF, the Company, by its duly authorized officer, has caused the amended and restated Plan to be adopted on this 27 ^th day of December, 2012, to be effective as of January 1, 2012.



ANADARKO PETROLEUM CORPORATION


By:	/s/ Julia A. Struble
	Julia A. Struble
	Vice President, Human Resources

EXHIBIT 10(ii)

FIRST AMENDMENT TO THE

ANADARKO PETROLEUM CORPORATION

DEFERRED COMPENSATION PLAN

(As Amended and Restated Effective January 1, 2012)

WHEREAS , Anadarko Petroleum Corporation (the “Company” ) sponsors the Anadarko Petroleum Corporation Deferred Compensation Plan, as amended and restated effective January 1, 2012 (the “Plan” ), for the benefit of its eligible employees and their beneficiaries; and

WHEREAS , Section 8.1 of the Plan provides, in part, that the Company’s Chief Financial Officer and the Company’s General Counsel, acting jointly (the “Authorized Officers” ), may approve, adopt and execute any amendment to the Plan that is necessary for purposes of legal compliance, to clarify ambiguities in the Plan document, or to simplify non-material administrative processes, as the Authorized Officers may, in their best judgment, so determine; and

WHEREAS , the Authorized Officers have resolved that the Plan should be amended to clarify certain provisions regarding the timing of deferral elections by certain individuals eligible to participate in the Plan.

NOW THEREFORE, the Plan is hereby amended as follows, effective with respect to deferral elections made on or after July 1, 2013:

(1) The following new Section 1.4A shall be added to Article 1 of the Plan immediately following Section 1.4 of the Plan:

“ 1.4A

“Base Pay Deferral Election Period” means, with respect to each Plan Year, a period established by the Administrator that ends before the commencement of such Plan Year. For example, with respect to the Plan Year that begins on January 1, 2015, the Administrator may establish a Base Pay Deferral Election Period of any duration during the preceding Plan Year provided such period ends no later than December 31, 2014. If the Administrator takes no action to establish a Base Pay Deferral Election Period with respect to a particular Plan Year, then the Base Pay Deferral Election Period for such Plan Year shall begin on December 1 and end on December 31 of the preceding Plan Year.”

(2) The following new Section 1.14A shall be added to Article 1 of the Plan immediately following Section 1.14 of the Plan:

“ 1.14A

“Director Compensation Deferral Election Period” means, with respect to each Plan Year, a period established by the Administrator that ends before the commencement of such Plan Year. For example, with respect to the Plan Year that begins on January 1, 2015, the Administrator may establish a Director Compensation Deferral Election Period of any duration during the preceding Plan Year provided such period ends no later than December 31, 2014. If the Administrator takes no action to establish a Director Compensation Deferral Election Period with respect to a particular Plan Year, then the Director

Compensation Deferral Election Period for such Plan Year shall begin on December 1 and end on December 31 of the preceding Plan Year.”

(3) The third paragraph of Section 3.1 of the Plan is hereby amended by deleting such paragraph and replacing it with the following:

“A deferral agreement may be changed or revoked at any time during the respective election periods specified in Section 3.5. A deferral agreement becomes irrevocable at the close of the respective election period. An irrevocable deferral election may be subsequently modified only as permitted in Section 7.2.”

(4) The following shall be added to the end of Section 3.2 of the Plan:

“A Participant who is first designated as an Eligible Employee after the first day of the calendar month preceding the calendar month in which a Base Pay Deferral Election Period commences with respect to a Plan Year may not elect to defer his Base Pay for the Plan Year to which such period relates but may elect to defer his Base Pay for subsequent Plan Years.”

(5) The following shall be added to the end of Section 3.4 of the Plan:

“An individual who first becomes a Director on or after the first day of a Director Compensation Deferral Election Period with respect to a Plan Year may not elect to defer his Director Compensation for the Plan Year to which such period relates but may elect to defer his Director Compensation for subsequent Plan Years.”

(6) Section 3.5 of the Plan is hereby amended by deleting such section and replacing it with the following:

“ 3.5

Timing of Election to Defer . Each Eligible Employee who desires (and who is eligible pursuant to Section 3.2) to defer Base Pay otherwise payable during a Plan Year must execute a deferral agreement in accordance with the procedures established by the Administrator and within the Base Pay Deferral Election Period with respect to such Plan Year. A deferral agreement that is timely and properly executed in accordance with the preceding sentence shall be irrevocable as of the last day of the applicable Base Pay Deferral Election Period. Each Eligible Employee who is eligible to defer a Bonus which may be earned with respect to services performed during a Plan Year pursuant to Section 3.3 and who desires to defer such Bonus must execute a deferral agreement in accordance with the rules and procedures established by the Administrator (but not later than December 31st immediately preceding such Plan Year except that if the plan or arrangement providing for such Bonus is “performance-based compensation based on services performed over a period of at least 12 months” (as described in Code Section 409A(a)(4)(B)(iii)), then such deferral election must be executed no later than the Bonus Deferral Deadline Date (as hereinafter defined) (provided that (a) the Eligible Employee performs services continuously from the later of the beginning of the performance period or the date the performance criteria are established

through the date such election is made and (b) such compensation has not become readily ascertainable as of the date of such election), and such election will be irrevocable as of the earlier of the Bonus Deferral Deadline Date or the date upon which such compensation has become readily ascertainable). For purposes of the preceding sentence, the term “Bonus Deferral Deadline Date” means, with respect to a particular Bonus, the date six (6) months before the end of the performance period over which the Bonus is earned, or such earlier date as the Administrator may require in its sole discretion.

A Director who desires (and who is eligible pursuant to Section 3.4) to defer his Director Compensation otherwise payable during a Plan Year must execute a deferral agreement in accordance with the procedures established by the Administrator and within the Director Compensation Deferral Election Period with respect to such Plan Year. A deferral agreement that is timely and properly executed in accordance with the preceding sentence shall be irrevocable as of the last day of the applicable Director Compensation Deferral Election Period.”

Except as expressly amended hereby, the Plan is ratified and confirmed in all respects and shall remain in full force and effect.

IN WITNESS WHEREOF, the undersigned, being a duly authorized officer of the Company, has approved and executed this First Amendment on this 17 ^th day of December, 2013.



ANADARKO PETROLEUM CORPORATION

By:	Julia A. Struble
Name:	/s/ Julia A. Struble
Title:	VP, Human Resources

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 29, 2014

/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 29, 2014

/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, 2014 , 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 29, 2014

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

July 29, 2014

		/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.