ANADARKO PETROLEUM CORP - FORM 10-Q

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EX-31.(I) - RULE 13A-14(A)/15D-14(A) CERTIFICATION-CHIEF EXECUTIVE OFFICER - ANADARKO PETROLEUM CORP	apc20143q-exhibit31i.htm
EX-31.(II) - RULE 13A-14(A)/15D-14(A) CERTIFICATION-CHIEF FINANCIAL OFFICER - ANADARKO PETROLEUM CORP	apc20143q-exhibit31ii.htm
EX-32 - SECTION 1350 CERTIFICATIONS - ANADARKO PETROLEUM CORP	apc20143q-exhibit32.htm
10-Q - ANADARKO PETROLEUM CORP 3RD QTR 2014 FORM 10-Q - PDF - ANADARKO PETROLEUM CORP	apc20143q10q.pdf
EXCEL - IDEA: XBRL DOCUMENT - ANADARKO PETROLEUM CORP	Financial_Report.xls

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 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 September 30, 2014, is shown below:



Title of Class		Number of Shares Outstanding
Common Stock, par value $0.10 per share		506,450,402

TABLE OF CONTENTS




PART I		Page
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2014 and 2013	2
	Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2014 and 2013	3
	Consolidated Balance Sheets at September 30, 2014, and December 31, 2013	4
	Consolidated Statement of Equity for the Nine Months Ended September 30, 2014	5
	Consolidated Statements of Cash Flows for the Nine Months Ended September 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	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 4.	Controls and Procedures	49
PART II
Item 1.	Legal Proceedings	50
Item 1A.	Risk Factors	50
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51
Item 6.	Exhibits	52

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
millions except per-share amounts	2014			2013			2014			2013
Revenues and Other
Natural-gas sales	$	830		$	805		$	3,038		$	2,547
Oil and condensate sales	2,637			2,389			7,766			6,761
Natural-gas liquids sales	424			325			1,221			889
Gathering, processing, and marketing sales	339			270			928			750
Gains (losses) on divestitures and other, net	780			64			2,340			296
Total	5,010			3,853			15,293			11,243
Costs and Expenses
Oil and gas operating	275			277			861			769
Oil and gas transportation and other	322			255			869			763
Exploration	199			272			1,000			714
Gathering, processing, and marketing	269			217			771			638
General and administrative	381			255			984			787
Depreciation, depletion, and amortization	1,163			996			3,335			2,958
Other taxes	306			294			981			819
Impairments	394			593			514			632
Algeria exceptional profits tax settlement	—			—			—			33
Deepwater Horizon settlement and related costs	3			5			96			12
Total	3,312			3,164			9,411			8,125
Operating Income (Loss)	1,698			689			5,882			3,118
Other (Income) Expense
Interest expense	204			177			573			513
(Gains) losses on derivatives, net	(323		)	72			453			(393		)
Other (income) expense, net	24			(23		)	12			69
Tronox-related contingent loss	19			—			4,338			—
Total	(76		)	226			5,376			189
Income (Loss) Before Income Taxes	1,774			463			506			2,929
Income tax expense (benefit)	627			240			1,719			1,263
Net Income (Loss)	1,147			223			(1,213		)	1,666
Net income attributable to noncontrolling interests	60			41			142			95
Net Income (Loss) Attributable to Common Stockholders	$	1,087		$	182		$	(1,355	)	$	1,571

Per Common Share
Net income (loss) attributable to common stockholders—basic	$	2.13		$	0.36		$	(2.69	)	$	3.11
Net income (loss) attributable to common stockholders—diluted	$	2.12		$	0.36		$	(2.69	)	$	3.10
Average Number of Common Shares Outstanding—Basic	506			503			505			502
Average Number of Common Shares Outstanding—Diluted	508			505			505			504
Dividends (per common share)	$	0.27		$	0.18		$	0.72		$	0.36

See accompanying Notes to Consolidated Financial Statements.

Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,				Nine Months Ended September 30,
millions	2014		2013		2014			2013
Net Income (Loss)	$	1,147	$	223	$	(1,213	)	$	1,666
Other Comprehensive Income (Loss), net of taxes
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net ⁽¹⁾	1		2		4			5
Adjustments for pension and other postretirement plans
Amortization of net actuarial (gain) loss to general and administrative expense ⁽²⁾	5		18		14			56
Amortization of net prior service (credit) cost to general and administrative expense	—		1		—			1
Total adjustments for pension and other postretirement plans	5		19		14			57
Total	6		21		18			62
Comprehensive Income (Loss)	1,153		244		(1,195		)	1,728
Comprehensive income attributable to noncontrolling interests	60		41		142			95
Comprehensive Income (Loss) Attributable to Common Stockholders	$	1,093	$	203	$	(1,337	)	$	1,633

__________________________________________________________________


⁽¹⁾	Net of income tax benefit (expense) of $(1) million for the three months ended September 30, 2014 and 2013, and $(3) million for the nine months ended September 30, 2014 and 2013.


⁽²⁾	Net of income tax benefit (expense) of $(2) million for the three months ended September 30, 2014, $(11) million for the three months ended September 30, 2013, $(7) million for the nine months ended September 30, 2014, and $(32) million for the nine months ended September 30, 2013.

See accompanying Notes to Consolidated Financial Statements.

Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)



millions	September 30, 2014			December 31, 2013
ASSETS
Current Assets
Cash and cash equivalents	$	8,335		$	3,698
Accounts receivable (net of allowance of $7 million and $5 million)
Customers	1,350			1,481
Others	1,362			1,241
Other current assets	692			688
Total	11,739			7,108
Properties and Equipment
Cost	72,677			71,244
Less accumulated depreciation, depletion, and amortization	31,573			30,315
Net properties and equipment	41,104			40,929
Other Assets	2,321			2,082
Goodwill and Other Intangible Assets	5,501			5,662
Total Assets	$	60,665		$	55,781

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	3,653		$	3,530
Current asset retirement obligations	403			409
Accrued expenses	1,646			1,264
Current portion of long-term debt	—			500
Deepwater Horizon settlement and related costs	93			—
Tronox-related contingent liability	5,188			—
Total	10,983			5,703
Long-term Debt	14,728			13,065
Other Long-term Liabilities
Deferred income taxes	7,512			9,245
Asset retirement obligations	1,464			1,613
Tronox-related contingent liability	—			850
Other	3,415			1,655
Total	12,391			13,363

Equity
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 525.6 million and 522.5 million shares issued)	52			52
Paid-in capital	9,190			8,629
Retained earnings	12,633			14,356
Treasury stock (19.2 million and 18.8 million shares)	(931		)	(895		)
Accumulated other comprehensive income (loss)	(267		)	(285		)
Total Stockholders’ Equity	20,677			21,857
Noncontrolling interests	1,886			1,793
Total Equity	22,563			23,650
Total Liabilities and Equity	$	60,665		$	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)	—		—		(1,355		)	—			—			142			(1,213		)
Common stock issued	—		240		—			—			—			—			240
Dividends—common stock	—		—		(368		)	—			—			—			(368		)
Repurchase of common stock	—		—		—			(36		)	—			—			(36		)
Subsidiary equity transactions	—		321		—			—			—			108			429
Distributions to noncontrolling interest owners	—		—		—			—			—			(157		)	(157		)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	—		—		—			—			4			—			4
Adjustments for pension and other postretirement plans	—		—		—			—			14			—			14
Balance at September 30, 2014	$	52	$	9,190	$	12,633		$	(931	)	$	(267	)	$	1,886		$	22,563

See accompanying Notes to Consolidated Financial Statements.

Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
millions	2014			2013
Cash Flows from Operating Activities
Net income (loss)	$	(1,213	)	$	1,666
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, and amortization	3,335			2,958
Deferred income taxes	(210		)	535
Dry hole expense and impairments of unproved properties	743			423
Impairments	514			632
(Gains) losses on divestitures, net	(2,194		)	(165		)
Total (gains) losses on derivatives, net	462			(396		)
Operating portion of net cash received (paid) in settlement of derivative instruments	(138		)	37
Other	195			174
Changes in assets and liabilities
Deepwater Horizon settlement and related costs	93			3
Algeria exceptional profits tax settlement	—			730
Tronox-related contingent loss	4,338			—
(Increase) decrease in accounts receivable	104			246
Increase (decrease) in accounts payable and accrued expenses	710			(37		)
Other items—net	(225		)	(22		)
Net cash provided by (used in) operating activities	6,514			6,784
Cash Flows from Investing Activities
Additions to properties and equipment and dry hole costs	(7,289		)	(5,327		)
Acquisition of businesses	(4		)	(473		)
Divestitures of properties and equipment and other assets	4,770			451
Other—net	(372		)	(552		)
Net cash provided by (used in) investing activities	(2,895		)	(5,901		)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	2,370			843
Repayments of debt	(1,255		)	(495		)
Financing portion of net cash paid in settlement of derivative instruments	(222		)	—
Increase (decrease) in outstanding checks	134			63
Dividends paid	(368		)	(182		)
Repurchase of common stock	(36		)	(30		)
Issuance of common stock, including tax benefit on share-based compensation awards	117			123
Sale of subsidiary units	434			418
Distributions to noncontrolling interest owners	(157		)	(111		)
Contributions from noncontrolling interest owners	—			2
Net cash provided by (used in) financing activities	1,017			631
Effect of Exchange Rate Changes on Cash	1			(46		)
Net Increase (Decrease) in Cash and Cash Equivalents	4,637			1,468
Cash and Cash Equivalents at Beginning of Period	3,698			2,471
Cash and Cash Equivalents at End of Period	$	8,335		$	3,939

See accompanying Notes to Consolidated Financial Statements.

Table of Contents

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

General Anadarko Petroleum Corporation is engaged in the exploration, development, production, and marketing of natural gas, 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 September 30, 2014, and December 31, 2013, the Consolidated Statements of Income and Comprehensive Income for the three and nine months ended September 30, 2014 and 2013, the Consolidated Statements of Cash Flows for the nine months ended September 30, 2014 and 2013, and the Consolidated Statement of Equity for the nine months ended September 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.

Table of Contents

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Acquisitions and Divestitures

For the nine months ended September 30, 2014, the Company received $4.8 billion in proceeds from divestitures and recognized net gains of $2.2 billion, primarily related to assets included in the oil and gas exploration and production reporting segment. In the third quarter of 2014, the Company sold its Chinese subsidiary for $1.075 billion, recognizing a gain of $510 million, and sold its interest in certain unproved properties in the Gulf of Mexico for $500 million, recognizing a gain of $216 million. In the first quarter of 2014, the Company sold a 10% working interest in Rovuma Offshore Area 1 in Mozambique for $2.64 billion, recognizing a gain of $1.5 billion, and sold its interest in the Pinedale/Jonah assets in Wyoming for $581 million.

On October 28, 2014, Anadarko’s consolidated subsidiary, Western Gas Partners, LP (WES), entered into an agreement to acquire a privately held company with gathering and processing assets located in the Delaware basin in West Texas for $1.5 billion in cash. The acquisition is expected to close and be funded in the fourth quarter of 2014 and is subject to regulatory approvals and other customary closing conditions.

3. Inventories

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



millions	September 30, 2014		December 31, 2013
Crude oil	$	187	$	88
Natural gas	23		43
NGLs	122		79
Total inventories	$	332	$	210

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

4. Impairments

The following summarizes impairments by segment:



	Three Months Ended September 30,				Nine Months Ended September 30,
millions	2014		2013		2014		2013
Oil and gas exploration and production
Long-lived assets held for use
U.S. onshore properties	$	387	$	—	$	387	$	—
Gulf of Mexico properties	—		593		115		593
Cost-method investment	—		—		2		10
Midstream
Long-lived assets held for use	7		—		10		29
Total impairments	$	394	$	593	$	514	$	632

In the third quarter of 2014, a U.S. onshore oil and gas property was impaired due to lower forecasted natural-gas prices. In the second quarter of 2014, the Company impaired a Gulf of Mexico property due to a reduction in estimated future cash flows. In the third quarter of 2013, certain Gulf of Mexico properties were impaired due to a reduction in estimated future net cash flows and downward revisions of reserves resulting from changes to the Company’s development plans. 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, which was measured using the income approach and Level 3 inputs:



millions	2014		2013
Long-lived assets held for use	$	661	$	266
Cost-method investment⁽¹⁾	32		32

__________________________________________________________________


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

5. Suspended Exploratory Well Costs

The Company’s suspended exploratory well costs were $1.5 billion at September 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 nine months ended September 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.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 WES previously owned by Anadarko. During the third quarter of 2014, Anadarko sold 5.75 million WGP limited partner units to the public, raising net proceeds of $335 million. At September 30, 2014, Anadarko’s ownership interest in WGP consisted of an 88.3% limited partner interest and the entire non-economic general partner interest. The remaining 11.7% limited partner interest in WGP was owned by the public.

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 nine months ended September 30, 2014, WES also sold 1.1 million common units to the public under its continuous offering program, raising net proceeds of $81 million. At September 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 September 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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ANADARKO 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 Oil and Natural-Gas Production/Processing Derivative Activities at September 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 11 billion cubic feet (Bcf) at September 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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ANADARKO 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 prior periods, the Company extended the reference-period start dates for derivatives included in the interest-rate swap portfolio without settling the related interest-rate derivative obligations. As a result, these derivatives contain an other-than-insignificant financing element and, therefore 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 September 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	September 30,		December 31,		September 30,			December 31,
Balance Sheet Classification	2014		2013		2014			2013
Commodity derivatives
Other current assets	$	255	$	181	$	(49	)	$	(102	)
Other assets	27		89		(11		)	(66		)
Accrued expenses	6		106		(10		)	(149		)
Other liabilities	1		4		(2		)	(15		)
	289		380		(72		)	(332		)
Interest-rate and other derivatives
Accrued expenses	—		—		—			(480		)
Other liabilities	—		—		(925		)	(174		)
	—		—		(925		)	(654		)
Total derivatives	$	289	$	380	$	(997	)	$	(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 September 30,						Nine Months Ended September 30,
Classification of (Gain) Loss Recognized	2014			2013			2014			2013
Commodity derivatives
Gathering, processing, and marketing sales ⁽¹⁾	$	(1	)	$	(8	)	$	9		$	(3	)
(Gains) losses on derivatives, net	(419		)	146			(40		)	35
Interest-rate and other derivatives
(Gains) losses on derivatives, net	96			(74		)	493			(428		)
Total (gains) losses on derivatives, net	$	(324	)	$	64		$	462		$	(396	)

__________________________________________________________________


⁽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 September 30, 2014, $156 million of the Company’s $997 million 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, such as if the Company’s credit rating from major credit rating agencies declined to a level below investment grade. 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. The aggregate fair value of unsecured derivative instruments with credit-risk-related contingent features for which a net liability position existed was $89 million at September 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 fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. Inputs used to estimate the fair value of swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and, for Black-Scholes option valuations, discount factors and implied market volatility.

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



millions
September 30, 2014	Level 1		Level 2			Level 3		Netting ⁽¹⁾			Collateral		Total
Assets
Commodity derivatives
Financial institutions	$	—	$	265		$	—	$	(68	)	$	—	$	197
Other counterparties	—		24			—		—			—		24
Total derivative assets	$	—	$	289		$	—	$	(68	)	$	—	$	221
Liabilities
Commodity derivatives
Financial institutions	$	—	$	(70	)	$	—	$	68		$	1	$	(1	)
Other counterparties	—		(2		)	—		—			—		(2		)
Interest-rate and other derivatives	—		(925		)	—		—			—		(925		)
Total derivative liabilities	$	—	$	(997	)	$	—	$	68		$	1	$	(928	)

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	September 30, 2014			December 31, 2013
Total debt at face value	$	16,347		$	15,202
Net unamortized discounts and premiums ⁽¹⁾	(1,627		)	(1,645		)
Total borrowings	$	14,720		$	13,557
Capital lease obligation	8			8
Less current portion of long-term debt	—			500
Total long-term debt	$	14,728		$	13,065

__________________________________________________________________


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

Anadarko’s Zero-Coupon Senior Notes due 2036 (Zero Coupons) can be put to the Company in October of each year, in whole or in part, for the then-accreted value of the outstanding Zero Coupons. None of the Zero Coupons (accreted value of $756 million) were 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 $17.3 billion at September 30, 2014, and $15.3 billion at December 31, 2013.

Debt Activity The following summarizes the Company’s debt activity during the nine months ended September 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
	624			3.450% Senior Notes due 2024
	621			4.500% Senior Notes due 2044
Borrowings	650			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	28			Amortization of debt discounts and premiums
Balance at September 30, 2014	$	14,720

During the third quarter of 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 September 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 unless the Company should elect to seek an extension on terms mutually agreeable to the lenders. 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% depending on WES’s credit rating, or rates at a margin above the one-month LIBOR, the federal funds rate, or prime rates offered by certain designated banks. At September 30, 2014, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $170 million at an interest rate of 1.46%, and had available borrowing capacity of approximately $1.0 billion ($1.2 billion maximum capacity, less $170 million of outstanding borrowings and $13 million of outstanding letters of credit).

Interest Expense The following summarizes interest expense:



	Three Months Ended September 30,						Nine Months Ended September 30,
millions	2014			2013			2014			2013
Debt and other	$	250		$	240		$	723		$	710
Capitalized interest	(46		)	(63		)	(150		)	(197		)
Total interest expense	$	204		$	177		$	573		$	513

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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 September 30,				Nine Months Ended September 30,
millions except per-share amounts	2014		2013		2014			2013
Net income (loss)
Net income (loss) attributable to common stockholders	$	1,087	$	182	$	(1,355	)	$	1,571
Less distributions on participating securities	2		—		3			1
Less undistributed income allocated to participating securities	6		1		—			9
Basic	$	1,079	$	181	$	(1,358	)	$	1,561
Diluted	$	1,079	$	181	$	(1,358	)	$	1,561
Shares
Average number of common shares outstanding—basic	506		503		505			502
Dilutive effect of stock options	2		2		—			2
Average number of common shares outstanding—diluted	508		505		505			504
Excluded ⁽¹⁾	3		3		11			4
Net income (loss) per common share
Basic	$	2.13	$	0.36	$	(2.69	)	$	3.11
Diluted	$	2.12	$	0.36	$	(2.69	)	$	3.10

Dividends per common share	$	0.27	$	0.18	$	0.72		$	0.36

__________________________________________________________________


⁽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	4			14			18
Balance at September 30, 2014	$	(50	)	$	(217	)	$	(267	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Contingencies

Litigation The Company is a defendant in a number of lawsuits, is involved in governmental proceedings, and is subject to regulatory controls arising in the ordinary course of business, including, but not limited to, personal injury claims; property damage claims; title disputes; tax disputes; royalty claims; contract claims; contamination claims relating to oil and gas production, transportation, and processing; and environmental claims, including claims involving assets owned by acquired companies and claims involving assets previously sold to third parties and no longer a part of the Company’s current operations. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that, 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 financial condition, 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 presided over 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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ANADARKO PETROLEUM CORPORATION

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 in early 2015. 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 $38 million, included in Tronox-related contingent loss in the Company’s Consolidated Statement of Income, during the nine months ended September 30, 2014, for an aggregate $5.19 billion Tronox-related contingent liability on the Company’s Consolidated Balance Sheet at September 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 which found Anadarko liable for civil penalties under the CWA. In September 2014, Anadarko filed a letter notifying the Fifth Circuit that the Louisiana District Court issued Findings of Fact and Conclusions of Law in the first phase of the Deepwater Horizon trial (Phase I Findings and Conclusions), which included facts that contradict certain key facts assumed by the Fifth Circuit panel in its June 2014 decision.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Contingencies (Continued)

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

The actual amount of a CWA penalty is subject to uncertainty, including whether the Company will be able to reach a settlement with the DOJ or will 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. In addition, in its Phase I Findings and Conclusions, the Louisiana District Court did not allocate any fault to Anadarko. Given the subjective nature of the CWA criteria used to determine penalty assessments and the Louisiana District Court’s prior rulings related to culpability and allocation of fault, the Company currently cannot reasonably estimate the amount of any such penalty to be assessed or determine a reasonable range of potential loss if the matter is resolved by the Louisiana District Court following trial. 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, the Phase I Findings and Conclusions that did not allocate any fault to Anadarko, and the subjective criteria of the CWA, the Company believes that its exposure to CWA penalties will not materially impact the Company’s financial condition, 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. In October 2014, the United States Supreme Court denied the Parish District Attorneys’ petition to review the case. While that denial ends further appeal of that decision by the Parish District Attorneys, any other party subject to the decision who has not yet appealed, including private parties who opted out of the BP settlement, the states, and other local governments, may do so after obtaining a final judgment on their damages claims. 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 (PSC) entered into a settlement agreement to resolve a substantial majority of the 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Contingencies (Continued)

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

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, the PSC, BP, BPAP, 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.

The State of Alabama previously brought actions against the Company and other parties for claims arising from the Deepwater Horizon event, including claims for penalties and fines under state environmental laws, which were subsequently dismissed by the Louisiana District Court. The Louisiana District Court has selected this case as its test case for valuing the damages sought by states for claims under federal laws arising from the Deepwater Horizon event. Trial is set for November 2015 and the parties are conducting discovery. The Louisiana District Court’s previous rulings apply to Alabama’s claims, including the court’s decision that only federal law, and not state law, applies; its decision allocating fault and liability among BP and BPAP, Transocean, and Halliburton; and its orders precluding evidence of alleged culpability by Anadarko, leaving only damages to be decided. The Company, pursuant to the Settlement Agreement, is fully indemnified by BP against losses arising as a result of claims for damages.

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 12, 2009, and June 9, 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. In March 2014, the parties reached a settlement in this matter, which was approved by the Texas District Court in September 2014. The settlement was directly funded by the Company’s insurers.

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Contingencies (Continued)

Remaining Liability Outlook It is possible that the Company may recognize additional Deepwater Horizon event-related liabilities for potential fines and penalties and certain other claims not covered by the indemnification provisions of the Settlement Agreement; 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 financial condition, 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, and BP’s creditworthiness.

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 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 purported to bring claims on behalf of Anadarko and alleged, 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 August 2014, the 215^th District Court approved the settlement. The settlement did not have a material impact on the Company’s financial condition, 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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ANADARKO 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 September 30,						Nine Months Ended September 30,
millions except percentages	2014			2013			2014			2013
Income tax expense (benefit)	$	627		$	240		$	1,719		$	1,263
Effective tax rate	35		%	52		%	340		%	43		%

For the three months ended September 30, 2014, the Company’s effective tax rate was the same as the 35% U.S. federal statutory rate. The effective tax rate increase related to the Algerian exceptional profits taxes was offset by the tax impact from foreign operations. The increase from the 35% U.S. federal statutory rate for the three and nine months ended September 30, 2013, was primarily attributable to the tax impact from foreign operations and Algerian exceptional profits taxes.

The increase from the 35% U.S. federal statutory rate for the nine months ended September 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 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.

During the nine months ended September 30, 2014, the Company identified $155 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.

At September 30, 2014, accrued expenses on the Company’s Consolidated Balance Sheet included $793 million of accrued income taxes.

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:



	Nine Months Ended September 30,
millions	2014		2013
Cash paid (received)
Interest, net of amounts capitalized	$	600	$	569
Income taxes, net of refunds	$	661	$	137
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	$	88	$	—

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ANADARKO 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 September 30,						Nine Months Ended September 30,
millions	2014			2013			2014		2013
Income (loss) before income taxes	$	1,774		$	463		$	506	$	2,929
Exploration expense	199			272			1,000		714
DD&A	1,163			996			3,335		2,958
Impairments	394			593			514		632
Interest expense	204			177			573		513
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	(276		)	36			324		(359		)
Deepwater Horizon settlement and related costs	3			5			96		12
Algeria exceptional profits tax settlement	—			—			—		33
Tronox-related contingent loss	19			—			4,338		—
Certain other nonoperating items	22			(10		)	22		75
Less net income attributable to noncontrolling interests	60			41			142		95
Consolidated Adjusted EBITDAX	$	3,442		$	2,491		$	10,566	$	7,412

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14. Segment Information (Continued)

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



millions	Oil and Gas Exploration & Production		Midstream		Marketing			Other and Intersegment Eliminations			Total
Three Months Ended September 30, 2014
Sales revenues	$	2,192	$	119	$	1,919		$	—		$	4,230
Intersegment revenues	1,604		364		(1,774		)	(194		)	—
Gains (losses) on divestitures and other, net	724		1		—			55			780
Total revenues and other	4,520		484		145			(139		)	5,010
Operating costs and expenses ⁽¹⁾	1,090		249		188			26			1,553
Net cash from settlement of commodity derivatives	—		—		—			(48		)	(48		)
Other (income) expense, net ⁽²⁾	—		—		—			2			2
Net income attributable to noncontrolling interests	—		60		—			—			60
Total expenses and other	1,090		309		188			(20		)	1,567
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—		—		(1		)	—			(1		)
Adjusted EBITDAX	$	3,430	$	175	$	(44	)	$	(119	)	$	3,442

Three Months Ended September 30, 2013
Sales revenues	$	1,916	$	95	$	1,778		$	—		$	3,789
Intersegment revenues	1,516		287		(1,629		)	(174		)	—
Gains (losses) on divestitures and other, net	7		—		—			57			64
Total revenues and other	3,439		382		149			(117		)	3,853
Operating costs and expenses ⁽¹⁾	930		216		164			(12		)	1,298
Net cash from settlement of commodity derivatives	—		—		—			26			26
Other (income) expense, net⁽²⁾	—		—		—			(13		)	(13		)
Net income attributable to noncontrolling interests	—		41		—			—			41
Total expenses and other	930		257		164			1			1,352
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—		—		(10		)	—			(10		)
Adjusted EBITDAX	$	2,509	$	125	$	(25	)	$	(118	)	$	2,491

__________________________________________________________________


⁽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 items are excluded from Adjusted EBITDAX.

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ANADARKO 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
Nine Months Ended September 30, 2014
Sales revenues	$	6,804	$	358		$	5,791		$	—		$	12,953
Intersegment revenues	4,947		1,010			(5,369		)	(588		)	—
Gains (losses) on divestitures and other, net	2,194		(2		)	—			148			2,340
Total revenues and other	13,945		1,366			422			(440		)	15,293
Operating costs and expenses ⁽¹⁾	3,128		732			555			51			4,466
Net cash from settlement of commodity derivatives	—		—			—			132			132
Other (income) expense, net ⁽²⁾	—		—			—			(10		)	(10		)
Net income attributable to noncontrolling interests	—		142			—			—			142
Total expenses and other	3,128		874			555			173			4,730
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—		—			3			—			3
Adjusted EBITDAX	$	10,817	$	492		$	(130	)	$	(613	)	$	10,566

Nine Months Ended September 30, 2013
Sales revenues	$	5,044	$	267		$	5,636		$	—		$	10,947
Intersegment revenues	4,904		805			(5,234		)	(475		)	—
Gains (losses) on divestitures and other, net	12		—			—			284			296
Total revenues and other	9,960		1,072			402			(191		)	11,243
Operating costs and expenses ⁽¹⁾	2,656		613			492			15			3,776
Net cash from settlement of commodity derivatives	—		—			—			(46		)	(46		)
Other (income) expense, net ⁽²⁾	—		—			—			(6		)	(6		)
Net income attributable to noncontrolling interests	—		95			—			—			95
Total expenses and other	2,656		708			492			(37		)	3,819
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—		—			(12		)	—			(12		)
Adjusted EBITDAX	$	7,304	$	364		$	(102	)	$	(154	)	$	7,412

__________________________________________________________________


⁽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 items are excluded from Adjusted EBITDAX.

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ANADARKO 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 September 30
Service cost	$	25		$	21		$	1		$	2
Interest cost	25			19			4			3
Expected return on plan assets	(27		)	(22		)	—			—
Amortization of net actuarial loss (gain)	9			29			(2		)	—
Amortization of net prior service cost (credit)	—			—			—			1
Net periodic benefit cost	$	32		$	47		$	3		$	6

Nine Months Ended September 30
Service cost	$	74		$	64		$	5		$	7
Interest cost	75			58			11			10
Expected return on plan assets	(80		)	(68		)	—			—
Amortization of net actuarial loss (gain)	26			88			(5		)	—
Amortization of net prior service cost (credit)	—			—			—			1
Net periodic benefit cost	$	95		$	142		$	11		$	18

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


•	other factors discussed below and elsewhere in “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates” included in the Company’s 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, New Zealand, Colombia, South Africa, and other countries.

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

Overall


•	Anadarko’s third-quarter sales volumes averaged 849 thousand barrels of oil equivalent per day (MBOE/d), representing a 10% increase over the third quarter of 2013.


•	Anadarko’s third-quarter liquids sales volumes averaged 433 thousand barrels per day (MBbls/d), representing a 29% increase over the third quarter of 2013, primarily due to increased sales volumes in the Wattenberg field, the Eagleford shale, the Delaware basin, and the liquids-rich East Texas/North Louisiana horizontal development.

•

During the third quarter, the Company closed several transactions totaling $2.2 billion, including the sale of its Chinese subsidiary, interest in unproved properties in the Gulf of Mexico, and interests in other U.S. onshore oil and gas properties. In addition, the Company sold 5.75 million Western Gas Equity Partners, LP (WGP) limited partner units to the public, raising net proceeds of $335 million.


•	The Company’s overall sales product mix increased to 51% liquids in the third quarter of 2014 compared to 43% in the third quarter of 2013.

U.S. Onshore


•	U.S. onshore third-quarter sales volumes averaged 681 MBOE/d, representing a 13% increase over the third quarter of 2013, primarily due to increased sales volumes from the Wattenberg field, the Marcellus and Eagleford shales, the Delaware basin, and the liquids-rich East Texas/North Louisiana horizontal development.


•	Wattenberg third-quarter oil sales volumes doubled to 82 MBbls/d, primarily driven by the Company’s horizontal drilling program.

Gulf of Mexico


•	Gulf of Mexico third-quarter sales volumes averaged 77 MBOE/d, representing a 5% decrease from the third quarter of 2013, primarily due to natural production declines.

International


•	International third-quarter sales volumes averaged 91 MBOE/d, representing a 2% decrease over the third quarter of 2013, primarily due to the sale of the Company’s Chinese subsidiary.

Financial


•	Anadarko’s net income attributable to common stockholders for the third quarter of 2014 totaled $1.1 billion, which included a $394 million pretax expense for impairments primarily related to a U.S. onshore oil and gas property.


•	The Company generated $2.3 billion of cash flow from operations and ended the quarter with $8.3 billion of cash on hand.


•	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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The following discussion pertains to Anadarko’s results of operations, financial condition, and changes in financial condition. Any increases or decreases “for the three months ended September 30, 2014,” refer to the comparison of the three months ended September 30, 2014, to the three months ended September 30, 2013, and any increases or decreases “for the nine months ended September 30, 2014,” refer to the comparison of the nine months ended September 30, 2014, to the nine months ended September 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 September 30,					Nine Months Ended September 30,
millions except per-share amounts	2014			2013		2014			2013
Financial Results
Revenues and other	$	5,010		$	3,853	$	15,293		$	11,243
Costs and expenses	3,312			3,164		9,411			8,125
Other (income) expense	(76		)	226		5,376			189
Income tax expense (benefit)	627			240		1,719			1,263
Net income (loss) attributable to common stockholders	$	1,087		$	182	$	(1,355	)	$	1,571
Net income (loss) per common share attributable to common stockholders—diluted	$	2.12		$	0.36	$	(2.69	)	$	3.10
Average number of common shares outstanding—diluted	508			505		505			504

Operating Results
Adjusted EBITDAX ⁽¹⁾	$	3,442		$	2,491	$	10,566		$	7,412
Sales volumes (MMBOE)	78			71		229			211

________________________________________________________________________________________________________

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 September 30,
millions except percentages	Natural Gas			Oil and Condensate			NGLs			Total
2013 sales revenues	$	805		$	2,389		$	325		$	3,519
Changes associated with sales volumes	(41		)	569			136			664
Changes associated with prices	66			(321		)	(37		)	(292		)
2014 sales revenues	$	830		$	2,637		$	424		$	3,891
Increase (Decrease) vs. 2013	3		%	10		%	30		%	11		%

	Nine Months Ended September 30,
millions except percentages	Natural Gas			Oil and Condensate			NGLs			Total
2013 sales revenues	$	2,547		$	6,761		$	889		$	10,197
Changes associated with sales volumes	(49		)	1,294			290			1,535
Changes associated with prices	540			(289		)	42			293
2014 sales revenues	$	3,038		$	7,766		$	1,221		$	12,025
Increase (Decrease) vs. 2013	19		%	15		%	37		%	18		%

Anadarko’s sales revenues increased for the three months ended September 30, 2014, due to higher crude-oil and NGLs volumes and higher average natural-gas prices, partially offset by lower average crude-oil and NGLs prices and lower natural-gas volumes. Sales revenues increased for the nine months ended September 30, 2014, due to higher crude-oil and NGLs volumes and higher average natural-gas and NGLs prices, partially offset by lower average crude-oil prices and slightly lower natural-gas sales volumes.



	Three Months Ended September 30,				Nine Months Ended September 30,
Sales Volumes	2014	Inc/(Dec) vs. 2013		2013	2014	Inc/(Dec) vs. 2013		2013
Barrels of Oil Equivalent (MMBOE except percentages)
United States	70	11	%	63	204	9	%	187
International	8	(2	)	8	25	6		24
Total barrels of oil equivalent	78	10		71	229	9		211

Barrels of Oil Equivalent per Day (MBOE/d except percentages)
United States	758	11	%	682	747	9	%	686
International	91	(2	)	93	92	6		87
Total barrels of oil equivalent per day	849	10		775	839	9		773

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 September 30,						Nine Months Ended September 30,
	2014		Inc/(Dec) vs. 2013		2013		2014		Inc/(Dec) vs. 2013		2013
United States
Sales volumes—Bcf	230		(5	)%	242		711		(2	)%	725
MMcf/d	2,494		(5	)	2,629		2,603		(2	)	2,655
Price per Mcf	$	3.62	9		$	3.33	$	4.27	22		$	3.51
Natural-gas sales revenues (millions)	$	830	3		$	805	$	3,038	19		$	2,547

_______________________________________________________________________________

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

Mcf—thousand cubic feet

The Company’s natural-gas sales volumes decreased by 135 MMcf/d for the three months ended September 30, 2014, and 52 MMcf/d for the nine months ended September 30, 2014.

•

Sales volumes in the Company’s Rocky Mountain Region (Rockies) decreased by 137 MMcf/d for the three months ended September 30, 2014, and 90 MMcf/d for the nine months ended September 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 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. Also, for the three months ended September 30, 2014, sales volumes decreased due to a natural production decline at Greater Natural Buttes.


•	Sales volumes in the Gulf of Mexico decreased by 49 MMcf/d for the three months ended September 30, 2014, and 80 MMcf/d for the nine months ended September 30, 2014, primarily due to natural production declines.

•

Sales volumes in the Southern and Appalachia Region increased by 51 MMcf/d for the three months ended September 30, 2014, and 118 MMcf/d for the nine months ended September 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 nine months ended September 30, 2014, primarily due to a decrease in year-over-year industry storage levels as a result of colder than average temperatures.

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014		Inc/(Dec) vs. 2013		2013		2014		Inc/(Dec) vs. 2013		2013
United States
Sales volumes—MMBbls	20		40	%	14		54		27	%	42
MBbls/d	213		40		152		197		27		155
Price per barrel	$	92.59	(10	)	$	103.15	$	95.30	(3	)	$	98.48
International
Sales volumes—MMBbls	8		(3	)%	8		25		5	%	24
MBbls/d	90		(3	)	93		91		5		87
Price per barrel	$	99.24	(10	)	$	110.82	$	105.58	(3	)	$	108.94
Total
Sales volumes—MMBbls	28		24	%	22		79		19	%	66
MBbls/d	303		24		245		288		19		242
Price per barrel	$	94.56	(11	)	$	106.05	$	98.57	(4	)	$	102.23
Oil and condensate sales revenues (millions)	$	2,637	10		$	2,389	$	7,766	15		$	6,761

_______________________________________________________________________________

MMBbls—million barrels

MBbls/d—thousand barrels per day

Anadarko’s crude-oil and condensate sales volumes increased by 58 MBbls/d for the three months ended September 30, 2014, and 46 MBbls/d for the nine months ended September 30, 2014.


•	Sales volumes in the Rockies increased by 42 MBbls/d for the three months ended September 30, 2014, and 32 MBbls/d for the nine months ended September 30, 2014, primarily in the Wattenberg field due to increased horizontal drilling and favorable impacts from an exchange of certain oil and gas properties with a third party in October 2013.


•	Southern and Appalachia Region sales volumes increased by 18 MBbls/d for the three months ended September 30, 2014, and 15 MBbls/d for the nine months ended September 30, 2014, primarily as a result of increased horizontal drilling and 2013 infrastructure expansion in the Eagleford shale and increased horizontal drilling in the Delaware basin.


•	Sales volumes in the Gulf of Mexico increased by 3 MBbls/d for the three months ended September 30, 2014, primarily due to maintenance downtime in 2013 and sales volumes from a new well in 2014 and decreased by 2 MBbls/d for the nine months ended September 30, 2014, primarily due to natural production declines, partially offset by sales volumes from a new well in 2014.

•

International sales volumes decreased by 3 MBbls/d for the three months ended September 30, 2014, primarily due to the sale of the Company’s Chinese subsidiary in August 2014, partially offset by higher sales volumes in Ghana due to timing of liftings. International sales volumes increased by 4 MBbls/d for the nine months ended September 30, 2014, primarily due to higher sales volumes in Algeria due to additional facilities and wells brought online at El Merk, partially offset by lower sales volumes in China due to maintenance downtime in the first half of 2014 and the sale of the Company’s Chinese subsidiary.

Anadarko’s average crude-oil price received decreased for the three and nine months ended September 30, 2014, primarily due to lower 2014 Brent crude-oil prices as a result of diminished concern over supply disruptions in North Africa and continued economic weakness in Europe and China, which have contributed to low demand growth forecasts for crude oil throughout the year.

Table of Contents

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014		Inc/(Dec) vs. 2013		2013		2014		Inc/(Dec) vs. 2013		2013
United States
Sales volumes—MMBbls	11		41	%	9		31		32	%	24
MBbls/d	129		41		92		116		32		88
Price per barrel	$	35.11	(9	)	$	38.49	$	38.21	3		$	37.07
International
Sales volumes—MMBbls	—		NM		—		—		NM		—
MBbls/d	1		NM		—		1		NM		—
Price per barrel	$	65.55	NM		$	—	$	66.14	NM		$	—
Total
Sales volumes—MMBbls	11		42	%	9		31		33	%	24
MBbls/d	130		42		92		117		33		88
Price per barrel	$	35.35	(8	)	$	38.49	$	38.38	4		$	37.07
Natural-gas liquids sales revenues (millions)	$	424	30		$	325	$	1,221	37		$	889

_________________________________________________________________________

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 38 MBbls/d for the three months ended September 30, 2014, and 29 MBbls/d for the nine months ended September 30, 2014.


•	Sales volumes in the Rockies increased by 25 MBbls/d for the three months ended September 30, 2014, and 17 MBbls/d for the nine months ended September 30, 2014, primarily in the Wattenberg field due to increased horizontal drilling, the Lancaster plant coming online in April 2014, and favorable impacts from an exchange of certain oil and gas properties with a third party in October 2013.


•	Sales volumes in the Southern and Appalachia Region increased by 12 MBbls/d for the three months ended September 30, 2014, and 11 MBbls/d for the nine months ended September 30, 2014, as a result of increased horizontal drilling and 2013 infrastructure expansion in the Eagleford shale and increased horizontal drilling in the Delaware basin.


•	International sales volumes for the three and nine months ended September 30, 2014, reflect the commencement of NGLs sales in 2014 from the Company’s El Merk facility in Algeria.

Anadarko’s average NGLs price received decreased for the three months ended September 30, 2014, primarily due to a higher incidence of chemical industry downtime, reducing ethane demand. Anadarko’s average NGLs price received increased for the nine months ended September 30, 2014, primarily due to colder than average temperatures across much of the United States in early 2014.

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Gathering, Processing, and Marketing



	Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2014		Inc/(Dec) vs. 2013		2013		2014		Inc/(Dec) vs. 2013		2013
Gathering, processing, and marketing sales	$	339	26	%	$	270	$	928	24	%	$	750
Gathering, processing, and marketing expense	269		24		217		771		21		638
Total gathering, processing, and marketing, net	$	70	32		$	53	$	157	40		$	112

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

Gathering, processing, and marketing, net increased by $17 million for the three months ended September 30, 2014, and $45 million for the nine months ended September 30, 2014, primarily due to higher gathering and processing revenue associated with higher volumes and increased infrastructure, as well as increased prices for processing sales, partially offset by higher processing and transportation expenses due to the increased volumes. Also, for the three months ended September 30, 2014, marketing sales decreased primarily due to lower natural-gas margins.

Gains (Losses) on Divestitures and Other, net

During the three and nine months ended September 30, 2014, the Company recognized a gain of $510 million associated with the divestiture of its Chinese subsidiary for sales proceeds of $1.075 billion and a gain of $216 million associated with the divestiture of its interest in certain unproved properties in the Gulf of Mexico for sales proceeds of $500 million. In addition, during the nine months ended September 30, 2014, the Company recognized a gain of $1.5 billion related to its divestiture of a 10% working interest in Rovuma Offshore Area 1 in Mozambique for sales proceeds of $2.64 billion. During the nine months ended September 30, 2013, the Company recognized a $140 million gain associated with the divestiture of its interests in a soda ash joint venture.

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Costs and Expenses



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014		Inc/(Dec) vs. 2013		2013		2014		Inc/(Dec) vs. 2013		2013
Oil and gas operating (millions)	$	275	(1	)%	$	277	$	861	12	%	$	769
Oil and gas operating—per BOE	3.53		(9	)	3.88		3.76		3		3.65
Oil and gas transportation and other (millions)	322		26		255		869		14		763
Oil and gas transportation and other—per BOE	4.12		15		3.58		3.79		5		3.62

For the three months ended September 30, 2014, oil and gas operating expense was relatively flat compared to the three months ended September 30, 2013, as higher costs associated with increased sales volumes in the Rockies and the Southern and Appalachia Region were offset by lower workover costs, primarily in the Gulf of Mexico. The related per-barrel of oil equivalent (BOE) costs decreased by $0.35 primarily due to increased sales volumes. For the nine months ended September 30, 2014, oil and gas operating expense increased by $92 million, primarily due to higher costs associated with increased sales volumes in the Rockies and the Southern and Appalachia Region and increased activity in the Gulf of Mexico. The related per-BOE costs increased $0.11 for the nine months ended September 30, 2014, as the higher costs were only partially offset by increased sales volumes.

Oil and gas transportation and other expense increased by $67 million for the three months ended September 30, 2014, and $106 million for the nine months ended September 30, 2014, due to higher gas-gathering and transportation costs primarily 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 increased by $0.54 for the three months ended September 30, 2014, and $0.17 for the nine months ended September 30, 2014, as the higher costs were only partially offset by increased sales volumes.



	Three Months Ended September 30,				Nine Months Ended September 30,
millions	2014		2013		2014		2013
Exploration Expense
Dry hole expense	$	104	$	77	$	527	$	301
Impairments of unproved properties	30		83		216		122
Geological and geophysical expense	13		51		93		111
Exploration overhead and other	52		61		164		180
Total exploration expense	$	199	$	272	$	1,000	$	714

For the three months ended September 30, 2014, exploration expense decreased by $73 million. Impairments of unproved properties decreased by $53 million due to a 2013 impairment of a U.S. onshore property as a result of changes to the Company’s drilling plans. Geological and geophysical expense decreased by $38 million due to lower seismic purchases in Colombia, the Gulf of Mexico, and the Rockies. Dry hole expense increased by $27 million primarily due to unsuccessful 2014 drilling activities in Mozambique, Côte d’Ivoire, and the Gulf of Mexico, compared to unsuccessful 2013 drilling activities in Kenya.

For the nine months ended September 30, 2014, exploration expense increased by $286 million. Dry hole expense increased by $226 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 and Kenya. Impairments of unproved properties increased by $94 million primarily due to 2014 impairments 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 the expiration of leases, partially offset by a 2013 impairment of a U.S. onshore property. Geological and geophysical expense decreased by $18 million due to lower seismic purchases in the Gulf of Mexico.

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	Three Months Ended September 30,						Nine Months Ended September 30,
millions except percentages	2014		Inc/(Dec) vs. 2013		2013		2014		Inc/(Dec) vs. 2013		2013
General and administrative	$	381	49	%	$	255	$	984	25	%	$	787
Depreciation, depletion, and amortization	1,163		17		996		3,335		13		2,958
Other taxes	306		4		294		981		20		819
Impairments	394		(34	)	593		514		(19	)	632

For the three months ended September 30, 2014, general and administrative (G&A) expense increased by $126 million primarily due to higher employee-related expenses of $112 million primarily due to increased headcount and higher bonus plan expense and $18 million for higher legal fees. For the nine months ended September 30, 2014, G&A expense increased by $197 million primarily due to higher employee-related expenses of $132 million primarily due to increased headcount and higher bonus plan expense, higher legal fees of $32 million, and higher consulting fees of $12 million.

Depreciation, depletion, and amortization (DD&A) expense increased by $167 million for the three months ended September 30, 2014, and $377 million for the nine months ended September 30, 2014, primarily due to higher sales volumes in 2014 and increased capital costs associated with additional gathering and processing facilities. DD&A expense also increased for the nine months ended September 30, 2014, due to increased asset retirement costs for fully depleted wells in the Gulf of Mexico.

For the three months ended September 30, 2014, other taxes increased by $12 million primarily due to higher ad valorem taxes of $21 million due to increased activity related to U.S. onshore properties and higher Algerian exceptional profits taxes of $8 million due to increased volumes, partially offset by lower Chinese windfall profits tax of $19 million due to the sale of the Company’s Chinese subsidiary. For the nine months ended September 30, 2014, other taxes increased by $162 million primarily due to higher Algerian exceptional profits taxes of $107 million attributable to higher crude-oil sales volumes, higher U.S. onshore ad valorem taxes of $68 million attributable to increased activity and higher U.S. severance taxes of $25 million attributable to higher crude-oil and NGLs volumes, partially offset by lower Chinese windfall profits tax of $32 million resulting from maintenance downtime in the first half of 2014 and the sale of the Company’s Chinese subsidiary.

Impairment expense for the three and nine months ended September 30, 2014, included $387 million for a U.S. onshore oil and gas property due to lower forecasted natural-gas prices. In addition, for the nine months ended September 30, 2014, impairment expense 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 nine months ended September 30, 2013, included $593 million for certain oil and gas properties in the Gulf of Mexico due to a reduction in estimated future net cash flows and downward revisions of reserves resulting from changes to the Company’s development plans. Impairment expense for the nine months ended September 30, 2013, also included $29 million related to a midstream property that was impaired due to a reduction in estimated future cash flows and $10 million related to the Company’s Venezuelan cost-method investment due to declines in estimated recoverable value.



	Three Months Ended September 30,				Nine Months Ended September 30,
millions	2014		2013		2014		2013
Deepwater Horizon settlement and related costs	$	3	$	5	$	96	$	12

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 September 30,								Nine Months Ended September 30,
millions except percentages	2014			Inc/(Dec) vs. 2013		2013			2014			Inc/(Dec) vs. 2013		2013
Interest Expense
Debt and other	$	250		4	%	$	240		$	723		2	%	$	710
Capitalized interest	(46		)	27		(63		)	(150		)	24		(197		)
Total interest expense	$	204		15		$	177		$	573		12		$	513

Interest expense increased by $27 million for the three months ended September 30, 2014, and $60 million for the nine months ended September 30, 2014, primarily due to a decrease in capitalized interest related to lower construction-in-progress balances for the Mozambique LNG project and the completion of certain U.S. pipeline projects in 2013.



	Three Months Ended September 30,						Nine Months Ended September 30,
millions	2014			2013			2014			2013
(Gains) Losses on Derivatives, net
(Gains) losses on commodity derivatives, net	$	(419	)	$	146		$	(40	)	$	35
(Gains) losses on interest-rate and other derivatives, net	96			(74		)	493			(428		)
Total (gains) losses on derivatives, net	$	(323	)	$	72		$	453		$	(393	)

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 months ended September 30, 2014, the fair market value of derivative instruments increased due to lower commodity prices, partially offset by lower interest rates. For the nine months ended September 30, 2014, the fair market value of derivative instruments decreased due to lower interest rates, partially offset by lower commodity prices.



	Three Months Ended September 30,							Nine Months Ended September 30,
millions except percentages	2014			Inc/(Dec) vs. 2013	2013			2014			Inc/(Dec) vs. 2013		2013
Other (Income) Expense, net
Interest income	$	(13	)	NM	$	(4	)	$	(20	)	150	%	$	(8	)
Other	37			NM	(19		)	32			58		77
Total other (income) expense, net	$	24		NM	$	(23	)	$	12		83		$	69

Other income decreased by $47 million for the three months ended September 30, 2014, and increased by $57 million for the nine months ended September 30, 2014. During the second quarter of 2013, as a result of a Chapter 11 bankruptcy declaration by a third party, the U.S. Department of the Interior ordered Anadarko to perform the decommissioning of the facility and related wells, which were previously sold to the third party. At that time, the Company accrued costs of $141 million to decommission the production facilities and related wells. During the third quarter of 2013, the Company recorded a 2013 adjustment of $10 million to reduce the estimated decommissioning costs. In addition, during the third quarter of 2014, the Company recorded a $22 million adjustment to increase the estimated decommissioning costs. Anadarko completed decommissioning of the production facilities in 2014 and expects to complete decommissioning of the wells in 2015. In addition, other income decreased $21 million for the three months ended September 30, 2014, and increased $6 million for the nine months ended September 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. The increases for the nine months ended September 30, 2014, 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 September 30,				Nine Months Ended September 30,
millions	2014		2013		2014		2013
Tronox-related contingent loss	$	19	$	—	$	4,338	$	—

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 for the three months ended September 30, 2014, and $38 million for the nine months ended September 30, 2014. The aggregate Tronox-related contingent liability included on the Company’s Consolidated Balance Sheet at September 30, 2014, was $5.19 billion. 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 September 30,						Nine Months Ended September 30,
millions except percentages	2014			2013			2014			2013
Income tax expense (benefit)	$	627		$	240		$	1,719		$	1,263
Effective tax rate	35		%	52		%	340		%	43		%

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Net Income Attributable to Noncontrolling Interests

The Company’s net income attributable to noncontrolling interests for the three and nine months ended September 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 September 30, 2014, and 54.5% at September 30, 2013. Public ownership in WGP consisted of an 11.7% limited partnership interest at September 30, 2014, and 9.0% at September 30, 2013.

During the third quarter of 2014, Anadarko sold 5.75 million WGP limited partner units to the public, raising net proceeds of $335 million. 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 September 30,								Nine Months Ended September 30,
millions except percentages	2014			Inc/(Dec) vs. 2013		2013			2014			Inc/(Dec) vs. 2013		2013
Income (loss) before income taxes	$	1,774		NM		$	463		$	506		(83	)%	$	2,929
Exploration expense	199			(27	)%	272			1,000			40		714
DD&A	1,163			17		996			3,335			13		2,958
Impairments	394			(34	)	593			514			(19	)	632
Interest expense	204			15		177			573			12		513
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	(276		)	NM		36			324			190		(359		)
Deepwater Horizon settlement and related costs	3			(40	)	5			96			NM		12
Algeria exceptional profits tax settlement	—			NM		—			—			(100	)	33
Tronox-related contingent loss	19			NM		—			4,338			NM		—
Certain other nonoperating items	22			NM		(10		)	22			(71	)	75
Less net income attributable to noncontrolling interests	60			46		41			142			49		95
Consolidated Adjusted EBITDAX	$	3,442		38		$	2,491		$	10,566		43		$	7,412
Adjusted EBITDAX by reporting segment
Oil and gas exploration and production	$	3,430		37	%	$	2,509		$	10,817		48	%	$	7,304
Midstream	175			40		125			492			35		364
Marketing	(44		)	(76	)	(25		)	(130		)	(27	)	(102		)
Other and intersegment eliminations	(119		)	(1	)	(118		)	(613		)	NM		(154		)

Oil and Gas Exploration and Production Adjusted EBITDAX for the three months ended September 30, 2014, increased primarily due to higher sales volumes for crude oil, and gains associated with the divestitures of the Company’s Chinese subsidiary and its interest in certain unproved properties in the Gulf of Mexico. These increases were partially offset by lower crude-oil prices. Adjusted EBITDAX for the nine months ended September 30, 2014, increased primarily due to higher sales volumes for crude oil and NGLs, and higher natural-gas prices. These increases were partially offset by lower crude-oil prices, and higher oil and gas transportation expenses and other taxes, which increased as a result of higher sales volumes. Adjusted EBITDAX for the nine months ended September 30, 2014, was also impacted by gains associated with the Company’s 2014 divestitures of a 10% working interest in Rovuma Offshore Area 1 in Mozambique, its Chinese subsidiary, and its interest in certain unproved properties in the Gulf of Mexico.

Midstream The increase in Adjusted EBITDAX for the three months ended September 30, 2014 was primarily due to higher gathering and processing revenue associated with higher volumes, partially offset by higher processing expenses primarily due to increased volumes. For the nine months ended September 30, 2014, Adjusted EBITDAX increased due to higher gathering revenue and processing fees due to higher volumes.

Marketing Marketing earnings primarily represent the margin earned on sales of natural gas, oil, and NGLs purchased from third parties. For the three and nine months ended September 30, 2014, Adjusted EBITDAX decreased due to lower marketing margins and 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. Adjusted EBITDAX for the three months ended September 30, 2014, was relatively flat compared to the three months ended September 30, 2013. Adjusted EBITDAX for the nine months ended September 30, 2014, decreased primarily due to higher payments for the settlement of commodity derivatives in 2014 and a 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 nine months ended September 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 September 30, 2014, Anadarko had no scheduled debt maturities during the next year. Anadarko’s Zero-Coupon Senior Notes due 2036 (Zero Coupons) can be put to the Company in October of each year, in whole or in part, for the then-accreted value of the outstanding Zero Coupons. None of the Zero Coupons, which had an accreted value of $756 million, were put to the Company in October 2014. The Zero Coupons can be put to the Company in October 2015, in whole or in part, for the then-accreted value of $796 million. 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 by the New York District Court 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 in early 2015. 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 September 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 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 unless the Company should elect to seek an extension on terms mutually agreeable to the lenders.

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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 September 30, 2014, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $170 million at an interest rate of 1.46%, and had available borrowing capacity of approximately $1.0 billion ($1.2 billion maximum capacity, less $170 million of outstanding borrowings and $13 million of outstanding letters of credit). See Financing Activities below.

During the nine months ended September 30, 2014, WES sold 1.1 million common units to the public under its continuous offering program, which authorized the issuance of up to an aggregate of $125 million of common units, raising net proceeds of $81 million. At September 30, 2014, WES had used all the capacity to issue units under this program.

In August 2014, WES filed a registration statement with the Securities and Exchange Commission for a continuous offering program, authorizing the issuance of up to an aggregate of $500 million of common units, in amounts, at prices, and on terms to be determined by market conditions and other factors at the time of the offerings. At September 30, 2014, WES had not issued any common units under this program.

Sources of Cash

Operating Activities Anadarko’s cash flow from operating activities during the nine months ended September 30, 2014, was $6.5 billion, compared to $6.8 billion for the same period of 2013. The decrease is due to $730 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 higher operating expenses, substantially offset by higher average natural-gas prices 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 impacted by the costs related to continued operations and debt service.

Investing Activities During the nine months ended September 30, 2014, Anadarko received pretax proceeds of $4.8 billion primarily related to the Company’s divestitures of a 10% working interest in Rovuma Offshore Area 1 in Mozambique for $2.64 billion, its Chinese subsidiary for $1.075 billion, its interest in the Pinedale/Jonah assets in Wyoming for $581 million, and its interest in certain unproved properties in the Gulf of Mexico for $500 million.

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Financing Activities During the nine months ended September 30, 2014, Anadarko’s consolidated subsidiary, WES, borrowed $650 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 nine months ended September 30, 2014, WES also sold 1.1 million common units under its continuous offering program, raising net proceeds of $81 million, as discussed in WES Funding Sources. In the third quarter of 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 were used for general corporate purposes. Also, during the third quarter of 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:



	Nine Months Ended September 30,
millions	2014		2013
Property acquisitions
Exploration	$	110	$	236
Development	108		320
Exploration	1,040		1,071
Development	4,636		2,929
Capitalized interest	137		170
Total oil and gas capital expenditures	6,031		4,726
Gathering, processing, and marketing and other ⁽¹⁾	1,056		1,185
Total capital expenditures ⁽²⁾	$	7,087	$	5,911

________________________________________________________________________________________


⁽¹⁾	Includes WES capital expenditures of $490 million for the nine months ended September 30, 2014, and $622 million for the nine months ended September 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 $1.2 billion for the nine months ended September 30, 2014, due to increased development drilling primarily in the Wattenberg field of $688 million, the Eagleford shale of $604 million, and Ghana of $181 million, as well as a spar lease buyout of $110 million in the Gulf of Mexico. 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 2014 increases were partially offset by 2013 acquisitions of certain oil and gas properties and related assets in the Moxa area of Wyoming for $310 million, primarily representing the fair value of the oil and gas properties acquired, and a 33.75% interest in gas-gathering systems located in the Marcellus shale in north-central Pennsylvania from a third party by WES for $135 million.

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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 September 30, 2014, $297 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, which was fully funded during the second quarter of 2014, covered the majority of the Company’s expected capital costs through first production, which is expected to occur in the fourth quarter of 2014.

Investments During the nine months ended September 30, 2014, the Company made capital contributions of $103 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 nine months ended September 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 $368 million to its common stockholders during the nine months ended September 30, 2014, and $182 million during the nine months ended September 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 $128 million during the nine months ended September 30, 2014, and $94 million during the nine months ended September 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 $0.675 per common unit for the third quarter of 2014 (to be paid in November 2014).

WGP distributed to its unitholders other than Anadarko an aggregate of $16 million during the nine months ended September 30, 2014, and $8 million during the nine months ended September 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 $0.29125 per unit for the third quarter of 2014 (to be paid in November 2014).

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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 $9.2 billion to $9.5 billion. This amount includes $628 million to $678 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 allocated 60% to the U.S. onshore region and Alaska, 15% to the Gulf of Mexico, 15% to Midstream and other, and 10% to 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, once available. In addition, these items provide flexibility in funding the settlement payment related to the Adversary Proceeding.

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. To reduce commodity-price risk and increase the predictability of 2014 cash flows, Anadarko entered into strategic derivative positions covering approximately 63% of its remaining 2014 anticipated natural-gas sales volumes and 46% 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.

On October 28, 2014, WES entered into an agreement to acquire a privately held company with gathering and processing assets located in the Delaware basin in West Texas for $1.5 billion in cash. The acquisition is expected to close and be funded in the fourth quarter of 2014 and is subject to regulatory approvals and other 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.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Company’s primary market risks are attributable to fluctuations in energy prices and interest rates. 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.

Derivative Instruments Held for Non-Trading Purposes The Company had derivative instruments in place to reduce the price risk associated with future production of 379 Bcf of natural gas and 22 MMBbls of crude oil at September 30, 2014, with a net derivative asset position of $203 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $248 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $247 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 September 30, 2014, the Company had a net derivative asset position of $13 million (gains of $15 million and losses of $2 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. While a 10% change in LIBOR would not impact the Company’s interest cost on fixed-rate debt already outstanding, it would affect fair value of outstanding fixed-rate debt.

At September 30, 2014, the Company had a net derivative liability position of $925 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 $116 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.

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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 September 30, 2014, cash of $139 million was held in escrow. A 10% increase or decrease in the foreign-currency exchange rate would not materially impact the Company’s gain or loss related to foreign currency.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934. 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 September 30, 2014.

Changes in Internal Control over Financial Reporting

There were no changes in Anadarko’s internal control over financial reporting during the third 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; property damage claims; title disputes; tax disputes; royalty claims; contract claims; contamination claims relating to oil and gas production, transportation, and processing; and environmental claims, including claims involving assets owned by acquired companies and claims involving assets previously sold to third parties and no longer a part of the Company’s current operations. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that, 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 financial condition, results of operations, or cash flows.

As previously disclosed in the Company’s 2013 Annual Report on Form 10-K, in September 2013, Anadarko received a Notice of Proposed Penalty Assessment from the Bureau of Safety and Environmental Enforcement (BSEE) as the result of an incident that occurred in February 2012 relating to a drilling rig in the Gulf of Mexico. In the notice, BSEE alleged several violations of certain offshore operational requirements. Anadarko disputed many of the allegations and in October 2014 received a Revised Final Reviewing Officer’s Decision from BSEE for a penalty of $70,000.

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 factors 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.

State and local 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 exchange for the withdrawal of several initiatives relating to hydraulic fracturing and other oil and gas operations proposed for inclusion on the Colorado state ballot in November 2014, the governor of Colorado created the Task Force on State and Local Regulation of Oil and Gas Operations in September 2014 to make recommendations to the state legislature regarding the responsible development of Colorado’s oil and gas resources. Although it is early in the process, it is possible that, as a result of the Task Force’s recommendations, the Colorado state legislature could adopt new policies or legislation relating to oil and gas operations, including measures that 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 in early 2015, 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, 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 third 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
July	2,191	$	107.83	—
August	1,958	$	105.99	—
September	1,485	$	108.38	—
Third-Quarter 2014	5,634	$	107.34	—	$	—

____________________________________________________________


⁽¹⁾	During the third 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
	4	(i)	Trustee Indenture dated as of September 19, 2006, Anadarko Petroleum Corporation to the Bank of New York Trust Company, N.A., filed as Exhibit 4.1 to Form 8-K filed on September 19, 2006	1-8968
		(ii)	Officers’ Certificate of Anadarko Petroleum Corporation dated July 7, 2014 establishing the 3.45% Senior Notes due 2024 and the 4.50% Senior Notes due 2044, filed as Exhibit 4.1 to Form 8-K filed on July 7, 2014	1-8968
		(iii)	Form of 3.45% Senior Notes due 2024, filed as Exhibit 4.2 to Form 8-K filed on July 7, 2014	1-8968
		(iv)	Form of 4.50% Senior Notes due 2044, filed as Exhibit 4.3 to Form 8-K filed on July 7, 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
*	101	.LAB	XBRL Label Linkbase Document
*	101	.PRE	XBRL Presentation Linkbase Document

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SIGNATURES

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



		ANADARKO PETROLEUM CORPORATION
		(Registrant)

October 28, 2014	By:	/s/ ROBERT G. GWIN
		Robert G. Gwin Executive Vice President, Finance and Chief Financial Officer

ANADARKO PETROLEUM CORP - FORM 10-Q - October 28, 2014

Attached files

ANADARKO PETROLEUM CORP Reports