Anadarko Petroleum 10-Q 2015 Q3 Quarterly report

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, 2015

or

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

EXCHANGE ACT OF 1934

For the transition period fromto

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  ☒    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  ☒    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  ☒    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  ☒

The number of shares outstanding of the Company’s common stock at October 19, 2015, is shown below:

Title of Class	Number of Shares Outstanding
Common Stock, par value $0.10 per share	508,142,751

TABLE OF CONTENTS

PART I		Page
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2015 and 2014	2
	Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2015 and 2014	3
	Consolidated Balance Sheets at September 30, 2015, and December 31, 2014	4
	Consolidated Statement of Equity for the Nine Months Ended September 30, 2015	5
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2015 and 2014	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	49
Item 4.	Controls and Procedures	50
PART II
Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	51
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51
Item 6.	Exhibits	52

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	2015			2014			2015			2014
Revenues and Other
Natural-gas sales	$	484		$	830		$	1,612		$	3,038
Oil and condensate sales	1,229			2,637			4,264			7,766
Natural-gas liquids sales	183			424			644			1,221
Gathering, processing, and marketing sales	334			339			932			928
Gains (losses) on divestitures and other, net	(542		)	780			(807		)	2,340
Total	1,688			5,010			6,645			15,293
Costs and Expenses
Oil and gas operating	262			275			784			861
Oil and gas transportation and other	271			322			921			869
Exploration	1,074			199			2,260			1,000
Gathering, processing, and marketing	289			269			798			771
General and administrative	345			381			933			984
Depreciation, depletion, and amortization	1,111			1,163			3,581			3,335
Other taxes	127			306			460			981
Impairments	758			394			3,571			514
Deepwater Horizon settlement and related costs	—			3			4			96
Total	4,237			3,312			13,312			9,411
Operating Income (Loss)	(2,549		)	1,698			(6,667		)	5,882
Other (Income) Expense
Interest expense	199			204			616			573
(Gains) losses on derivatives, net	282			(323		)	123			453
Other (income) expense, net	47			24			109			12
Tronox-related contingent loss	—			19			5			4,338
Total	528			(76		)	853			5,376
Income (Loss) Before Income Taxes	(3,077		)	1,774			(7,520		)	506
Income tax expense (benefit)	(917		)	627			(2,232		)	1,719
Net Income (Loss)	(2,160		)	1,147			(5,288		)	(1,213		)
Net income attributable to noncontrolling interests	75			60			154			142
Net Income (Loss) Attributable to Common Stockholders	$	(2,235	)	$	1,087		$	(5,442	)	$	(1,355	)
Per Common Share
Net income (loss) attributable to common stockholders—basic	$	(4.41	)	$	2.13		$	(10.73	)	$	(2.69	)
Net income (loss) attributable to common stockholders—diluted	$	(4.41	)	$	2.12		$	(10.73	)	$	(2.69	)
Average Number of Common Shares Outstanding—Basic	508			506			508			505
Average Number of Common Shares Outstanding—Diluted	508			508			508			505
Dividends (per common share)	$	0.27		$	0.27		$	0.81		$	0.72

See accompanying Notes to Consolidated Financial Statements.

2

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions	2015			2014			2015			2014
Net Income (Loss)	$	(2,160	)	$	1,147		$	(5,288	)	$	(1,213	)
Other Comprehensive Income (Loss)
Adjustments for derivative instruments
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	2			2			7			7
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	(1		)	(1		)	(3		)	(3		)
Total adjustments for derivative instruments, net of taxes	1			1			4			4
Adjustments for pension and other postretirement plans
Amortization of net actuarial (gain) loss to general and administrative expense	13			7			39			21
Income taxes on amortization of net actuarial (gain) loss to general and administrative expense	(5		)	(2		)	(14		)	(7		)
Amortization of net prior service (credit) cost to general and administrative expense	1			—			2			—
Income taxes on amortization of net prior service (credit) cost to general and administrative expense	(1		)	—			(1		)	—
Total adjustments for pension and other postretirement plans, net of taxes	8			5			26			14
Total	9			6			30			18
Comprehensive Income (Loss)	(2,151		)	1,153			(5,258		)	(1,195		)
Comprehensive income attributable to noncontrolling interests	75			60			154			142
Comprehensive Income (Loss) Attributable to Common Stockholders	$	(2,226	)	$	1,093		$	(5,412	)	$	(1,337	)

See accompanying Notes to Consolidated Financial Statements.

3

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

millions	September 30, 2015			December 31, 2014
ASSETS
Current Assets
Cash and cash equivalents	$	2,072		$	7,369
Accounts receivable (net of allowance of $8 million and $7 million)
Customers	833			1,118
Others	1,636			1,409
Other current assets	646			1,325
Total	5,187			11,221
Properties and Equipment
Cost	70,387			75,107
Less accumulated depreciation, depletion, and amortization	35,006			33,518
Net properties and equipment	35,381			41,589
Other Assets	2,271			2,310
Goodwill and Other Intangible Assets	6,343			6,569
Total Assets	$	49,182		$	61,689
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	3,074		$	3,683
Current asset retirement obligations	334			257
Accrued expenses	907			994
Short-term debt	33			—
Deepwater Horizon settlement and related costs	90			90
Tronox-related contingent liability	—			5,210
Total	4,438			10,234
Long-term Debt	15,892			15,092
Other Long-term Liabilities
Deferred income taxes	6,090			9,249
Asset retirement obligations	1,670			1,796
Other	4,040			3,000
Total	11,800			14,045
Equity
Stockholders’ equity
Common stock, par value $0.10 per share (1.0 billion shares authorized, 527.8 million and 525.9 million shares issued)	52			52
Paid-in capital	9,224			9,005
Retained earnings	6,268			12,125
Treasury stock (19.7 million and 19.3 million shares)	(978		)	(940		)
Accumulated other comprehensive income (loss)	(487		)	(517		)
Total Stockholders’ Equity	14,079			19,725
Noncontrolling interests	2,973			2,593
Total Equity	17,052			22,318
Total Liabilities and Equity	$	49,182		$	61,689

See accompanying Notes to Consolidated Financial Statements.

4

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

	Total Stockholders’ Equity
	Common Stock		Paid-in Capital		Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Non- controlling Interests			Total Equity
millions
Balance at December 31, 2014	$	52	$	9,005	$	12,125		$	(940	)	$	(517	)	$	2,593		$	22,318
Net income (loss)	—		—		(5,442		)	—			—			154			(5,288		)
Common stock issued	—		154		—			—			—			—			154
Dividends—common stock	—		—		(415		)	—			—			—			(415		)
Repurchase of common stock	—		—		—			(38		)	—			—			(38		)
Subsidiary equity transactions	—		65		—			—			—			86			151
Issuance of tangible equity units	—		—		—			—			—			348			348
Distributions to noncontrolling interest owners	—		—		—			—			—			(208		)	(208		)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net	—		—		—			—			4			—			4
Adjustments for pension and other postretirement plans	—		—		—			—			26			—			26
Balance at September 30, 2015	$	52	$	9,224	$	6,268		$	(978	)	$	(487	)	$	2,973		$	17,052

See accompanying Notes to Consolidated Financial Statements.

5

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended   September 30,
millions	2015			2014
Cash Flows from Operating Activities
Net income (loss)	$	(5,288	)	$	(1,213	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	3,581			3,335
Deferred income taxes	(2,627		)	(210		)
Dry hole expense and impairments of unproved properties	1,993			743
Impairments	3,571			514
(Gains) losses on divestitures, net	1,003			(2,194		)
Total (gains) losses on derivatives, net	123			462
Operating portion of net cash received (paid) in settlement of derivative instruments	251			(138		)
Other	219			195
Changes in assets and liabilities
Deepwater Horizon settlement and related costs	—			93
Tronox-related contingent liability	(5,210		)	4,338
(Increase) decrease in accounts receivable	23			104
Increase (decrease) in accounts payable and accrued expenses	(573		)	710
Other items—net	800			(225		)
Net cash provided by (used in) operating activities	(2,134		)	6,514
Cash Flows from Investing Activities
Additions to properties and equipment and dry hole costs	(4,861		)	(7,289		)
Divestitures of properties and equipment and other assets	1,248			4,770
Other—net	(83		)	(376		)
Net cash provided by (used in) investing activities	(3,696		)	(2,895		)
Cash Flows from Financing Activities
Borrowings, net of issuance costs	4,810			2,370
Repayments of debt	(4,024		)	(1,255		)
Financing portion of net cash received (paid) for derivative instruments	(44		)	(222		)
Increase (decrease) in outstanding checks	(103		)	134
Dividends paid	(415		)	(368		)
Repurchase of common stock	(38		)	(36		)
Issuance of common stock, including tax benefit on share-based compensation awards	21			117
Sale of subsidiary units	187			434
Issuance of tangible equity units — equity component	348			—
Distributions to noncontrolling interest owners	(208		)	(157		)
Net cash provided by (used in) financing activities	534			1,017
Effect of Exchange Rate Changes on Cash	(1		)	1
Net Increase (Decrease) in Cash and Cash Equivalents	(5,297		)	4,637
Cash and Cash Equivalents at Beginning of Period	7,369			3,698
Cash and Cash Equivalents at End of Period	$	2,072		$	8,335

See accompanying Notes to Consolidated Financial Statements.

6

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

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

Basis of Presentation  The information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the Company’s consolidated financial statements. Certain prior-period amounts have been reclassified to conform to the current-period presentation.

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

Recently Issued Accounting Standards  The Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2015-03, Interest—Imputation of Interest (Subtopic 835-30)—Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30)—Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. These ASUs will simplify the presentation of debt issuance costs by requiring such costs, except for those related to revolving credit facilities, to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, rather than as an asset. These ASUs are effective for annual and interim periods beginning in 2016 and are required to be adopted using a retrospective approach, with early adoption permitted. The Company does not expect the adoption to have a material impact on its consolidated financial statements.

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

The FASB issued ASU 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition, and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers—Deferral of the Effective Date, to annual and interim periods beginning in 2018 and is required to be adopted using one of two retrospective application methods, with early adoption permitted in 2017. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements.

7

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Acquisitions, Divestitures, and Assets Held for Sale

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

Divestitures and Assets Held for Sale  For the nine months ended September 30, 2015, the Company received $1.2 billion in proceeds from divestitures and recognized net losses of $1.0 billion.

Divestitures  During the third quarter of 2015, the Company sold certain coalbed methane properties in the Rocky Mountains Region (Rockies) for net proceeds of $107 million, after closing adjustments, and recognized a loss of $440 million. These properties were included in the oil and gas exploration and production reporting segment.

The sale of certain U.S. onshore oil and gas exploration and production properties and related midstream assets in East Texas, with an original sales price of $440 million, closed in July 2015 for net proceeds of $426 million after closing adjustments. During the nine months ended September 30, 2015, the Company recognized a loss of $110 million.

The sale of certain enhanced oil recovery (EOR) assets in the Rockies included in the oil and gas exploration and reporting segment, with an original sales price of $703 million, closed in April 2015 for net proceeds of $686 million after closing adjustments. During the nine months ended September 30, 2015, the Company recognized a loss of $344 million.

Assets Held for Sale  Certain coalbed methane midstream assets in the Rockies satisfied criteria to be considered held for sale during the third quarter of 2015, at which time the Company remeasured them to their current fair value using a market approach and Level 2 fair-value measurement and recognized a loss of $100 million. The sale of these assets is expected to close in the fourth quarter of 2015 for a sales price of $80 million, subject to closing adjustments.

Gains and losses on assets held for sale are included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income. At September 30, 2015, the balances of assets and liabilities associated with assets held for sale were not material.

3. Inventories

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

millions	September 30, 2015		December 31, 2014
Oil	$	108	$	133
Natural gas	37		27
NGLs	57		83
Total inventories	$	202	$	243

8

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

4. Impairments

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

	Three Months Ended				Nine Months Ended
millions	Impairment		Fair Value (1)		Impairment		Fair Value (1)
September 30, 2015
Oil and gas exploration and production
Long-lived assets held for use
U.S. onshore properties	$	641	$	634	$	2,944	$	1,904
Gulf of Mexico properties	101		94		126		94
Cost-method investment (2)	1		32		2		32
Midstream
Long-lived assets held for use	15		7		499		209
Total	$	758	$	767	$	3,571	$	2,239
September 30, 2014
Oil and gas exploration and production
Long-lived assets held for use
U.S. onshore properties	$	387	$	385	$	387	$	385
Gulf of Mexico properties	—		—		115		327
Cost-method investment (2)	—		—		2		32
Midstream
Long-lived assets held for use	7		—		10		—
Total	$	394	$	385	$	514	$	744

__________________________________________________________________

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

⁽²⁾  Represents the after-tax net investment.

Impairments during the three months ended September 30, 2015, were primarily related to U.S. onshore oil and gas properties primarily in the Southern and Appalachia Region and an oil and gas property in the Gulf of Mexico, all of which were impaired due to lower forecasted commodity prices. Impairments during the three months ended September 30, 2014, were primarily related to a U.S. onshore oil and gas property in the Southern and Appalachia Region that was impaired due to lower forecasted natural-gas prices.

Impairments during the nine months ended September 30, 2015, were primarily related to the Company’s Greater Natural Buttes oil and gas and midstream properties in the Rockies, certain other U.S. onshore oil and gas properties primarily in the Southern and Appalachia Region, and oil and gas properties in the Gulf of Mexico, all of which were impaired due to lower forecasted commodity prices. Impairments during the nine months ended September 30, 2014, were primarily related to the U.S. onshore oil and gas property in the Southern and Appalachia Region discussed above and an oil and gas property in the Gulf of Mexico that was impaired due to a reduction in estimated future cash flows. Additional impairments may be recognized in the fourth quarter of 2015 if commodity prices decline further. Impairments of proved properties are included in impairment expense in the Company’s Consolidated Statements of Income.

In addition to the proved property impairments above, during the third quarter of 2015, the Company recognized a $109 million impairment of unproved Utica properties resulting from an assignment of mineral interests in settlement of a legal matter. The Company also recognized a $935 million impairment of unproved Greater Natural Buttes properties during the nine months ended September 30, 2015, as a result of lower commodity prices. Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income.

9

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

5. Suspended Exploratory Well Costs

The Company’s suspended exploratory well costs were $1.1 billion at September 30, 2015, and $1.5 billion at December 31, 2014. During the nine months ended September 30, 2015, $602 million of suspended exploratory well costs previously capitalized for greater than one year at December 31, 2014, primarily related to Brazil, were charged to exploration expense. Given the current oil-price environment and other considerations, the Company does not expect to have substantive exploration and development activities in Brazil for the foreseeable future. The decrease in suspended exploratory well costs was partially offset by the capitalization of costs associated with exploration drilling in the Gulf of Mexico, Colombia, and Mozambique. Projects with suspended exploratory well costs are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development and where management is actively pursuing efforts to assess whether reserves can be attributed to these projects. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time.

6. Derivative Instruments

Objective and Strategy  The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Futures, swaps, and options are used to manage exposure to commodity-price risk inherent in the Company’s oil and natural-gas production and natural-gas processing operations (Oil and Natural-Gas Production/Processing Derivative Activities). Futures contracts and commodity-price swap agreements are used to fix the price of expected future oil and natural-gas sales at major industry trading locations, such as Henry Hub, Louisiana, for natural gas and Cushing, Oklahoma, or Sullom Voe, Scotland, for oil. Basis swaps are periodically used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities (Marketing and Trading Derivative Activities).

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

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

10

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6. Derivative Instruments (Continued)

Oil and Natural-Gas Production/Processing Derivative Activities  The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The oil prices listed below are a combination of NYMEX West Texas Intermediate and Intercontinental Exchange, Inc. (ICE) Brent Blend prices. The NGLs prices listed below are Oil Price Information Services prices (OPIS). The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at September 30, 2015:

	2015 Settlement		2016 Settlement
Natural Gas
Three-Way Collars (thousand MMBtu/d)	635		—
Average price per MMBtu
Ceiling sold price (call)	$	4.76	$	—
Floor purchased price (put)	$	3.75	$	—
Floor sold price (put)	$	2.75	$	—
Fixed-Price Contracts (thousand MMBtu/d)	—		34
Average price per MMBtu	$	—	$	3.18
Extendable Fixed-Price Contracts (thousand MMBtu/d) (1)	170		—
Average price per MMBtu	$	4.17	$	—
Oil
Three-Way Collars (MBbls/d)	—		28
Average price per barrel
Ceiling sold price (call)	$	—	$	69.29
Floor purchased price (put)	$	—	$	61.43
Floor sold price (put)	$	—	$	46.43
NGLs
Fixed-Price Contracts (MBbls/d)	7		3
Average price per barrel	$	14.09	$	14.87

__________________________________________________________________

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

MMBtu—million British thermal units

MMBtu/d—million British thermal units per day

MBbls/d—thousand barrels per day

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

Marketing and Trading Derivative Activities  The Company had financial derivative transactions with notional volumes of natural gas totaling 8 billion cubic feet (Bcf) at September 30, 2015, and 6 Bcf at December 31, 2014, which were entered into to mitigate commodity-price risk related to fixed-price purchase and sales contracts and storage activity.

11

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6. Derivative Instruments (Continued)

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

During the third quarter of 2015, the Company extended the reference-period start dates on interest-rate swaps with an aggregate notional principal amount of $1.0 billion to align the portfolio with anticipated debt refinancing. The Company also amended the mandatory termination dates on interest-rate swaps with an aggregate notional principal amount of $1.8 billion so that, at the start of the reference period, Anadarko will receive quarterly payments based on the floating rate and make semi-annual payments based on the fixed interest rate. The interest-rate swaps are required to be settled in full at the mandatory termination date. As part of these interest-rate swap modifications, the fixed interest rates on the swaps were also adjusted, and the Company recognized a loss of $137 million, which is included in gains (losses) on derivatives, net in the Company’s Consolidated Statements of Income, and increased the related derivative liability.

Derivative settlements and collateralization are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements and collateralization are classified as cash flows from financing activities. As a result of prior extensions of reference-period start dates without settlement of the related interest-rate derivative obligations, the interest-rate derivatives in the Company’s portfolio contain an other-than-insignificant financing element, and therefore, any settlements or collateralization related to these extended interest-rate derivatives are classified as cash flows from financing activities.

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

millions except percentages			Mandatory	Weighted-Average
Notional Principal Amount		Reference Period	Termination Date	Interest Rate
$	50	September 2016 – 2026	September 2016	5.910%
$	50	September 2016 – 2046	September 2016	6.290%
$	250	September 2016 – 2046	September 2018	6.310%
$	300	September 2016 – 2046	September 2020	6.509%
$	250	September 2016 – 2046	September 2021	6.724%
$	200	September 2017 – 2047	September 2018	6.049%
$	300	September 2017 – 2047	September 2020	6.569%
$	500	September 2017 – 2047	September 2021	6.654%

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	2015		2014		2015			2014
Commodity derivatives
Other current assets	$	246	$	421	$	(74	)	$	(118	)
Other assets	42		1		(16		)	—
Accrued expenses	27		71		(43		)	(114		)
Other liabilities	—		—		—			(6		)
	315		493		(133		)	(238		)
Interest-rate derivatives
Accrued expenses	—		—		(56		)	—
Other liabilities	—		—		(1,462		)	(1,217		)
	—		—		(1,518		)	(1,217		)
Total derivatives	$	315	$	493	$	(1,651	)	$	(1,455	)

12

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6. 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	2015			2014			2015			2014
Commodity derivatives
Gathering, processing, and marketing sales (1)	$	(1	)	$	(1	)	$	—		$	9
(Gains) losses on derivatives, net	(125		)	(419		)	(177		)	(40		)
Interest-rate derivatives
(Gains) losses on derivatives, net	407			96			300			493
Total (gains) losses on derivatives, net	$	281		$	(324	)	$	123		$	462

__________________________________________________________________

⁽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, 2015, $243 million of the Company’s $1.651 billion gross derivative liability balance, and at December 31, 2014, $289 million of the Company’s $1.455 billion gross derivative liability balance, would have been eligible for setoff against the Company’s gross derivative asset balance in the event of default. Other than in the event of default, the Company does not net settle across derivative types.

The Company’s derivative instruments are subject to individually negotiated credit provisions that may require collateral of cash or letters of credit depending on the derivative’s valuation versus negotiated credit thresholds. These credit thresholds may also require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered, such as if the Company’s credit rating from major credit rating agencies declines to below investment grade. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.3 billion (net of collateral) at September 30, 2015, and $97 million (net of collateral) at December 31, 2014. The increase is primarily a result of derivative counterparties no longer maintaining secured positions under the Company’s credit facilities, and therefore, the derivative instruments are now subject to credit-risk-related provisions. For information on the Company’s revolving credit facilities, see Note 8—Debt and Interest Expense—Anadarko Revolving Credit Facilities and Commercial Paper Program.

13

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6. Derivative Instruments (Continued)

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

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

millions
September 30, 2015	Level 1		Level 2			Level 3		Netting (1)			Collateral			Total
Assets
Commodity derivatives
Financial institutions	$	4	$	288		$	—	$	(115	)	$	(6	)	$	171
Other counterparties	—		23			—		(3		)	—			20
Total derivative assets	$	4	$	311		$	—	$	(118	)	$	(6	)	$	191
Liabilities
Commodity derivatives
Financial institutions	$	—	$	(126	)	$	—	$	115		$	—		$	(11	)
Other counterparties	—		(7		)	—		3			—			(4		)
Interest-rate derivatives	—		(1,518		)	—		—			67			(1,451		)
Total derivative liabilities	$	—	$	(1,651	)	$	—	$	118		$	67		$	(1,466	)
December 31, 2014
Assets
Commodity derivatives
Financial institutions	$	—	$	471		$	—	$	(187	)	$	(13	)	$	271
Other counterparties	—		22			—		(2		)	—			20
Total derivative assets	$	—	$	493		$	—	$	(189	)	$	(13	)	$	291
Liabilities
Commodity derivatives
Financial institutions	$	—	$	(234	)	$	—	$	187		$	—		$	(47	)
Other counterparties	—		(4		)	—		2			—			(2		)
Interest-rate derivatives	—		(1,217		)	—		—			23			(1,194		)
Total derivative liabilities	$	—	$	(1,455	)	$	—	$	189		$	23		$	(1,243	)

 __________________________________________________________________

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

14

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Tangible Equity Units

In June 2015, the Company issued 9.2 million 7.50% tangible equity units (TEUs) at a stated amount of $50.00 per TEU and raised net proceeds of $445 million. Each TEU is comprised of a prepaid equity purchase contract for common units of Western Gas Equity Partners, LP (WGP), a publicly traded consolidated subsidiary, and a senior amortizing note. Subsequent to issuance, each TEU may be legally separated into the two components. The prepaid equity purchase contract is considered a freestanding financial instrument, indexed to WGP common units, and meets the conditions for equity classification.

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

millions, except price per TEU	Equity Component		Debt Component		Total
Price per TEU	$	39.05	$	10.95	$	50.00
Gross proceeds	359		101		460
Less issuance costs	11		4		15
Net proceeds	$	348	$	97	$	445

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

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

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

 __________________________________________________________________

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

15

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Tangible Equity Units (Continued)

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

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

8. Debt and Interest Expense

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

millions	September 30, 2015			December 31, 2014
Total debt at face value	$	17,497		$	16,687
Net unamortized discounts and premiums (1)	(1,593		)	(1,616		)
Total borrowings	15,904			15,071
Capital lease obligation	21			21
Less short-term debt	33			—
Total long-term debt (2)	$	15,892		$	15,092

__________________________________________________________________

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

⁽²⁾  Includes WES debt of $2.6 billion at September 30, 2015, and $2.4 billion at December 31, 2014.

Anadarko’s $1.750 billion 5.950% Senior Notes due September 2016 are classified as long-term debt on the Company’s Consolidated Balance Sheet, as the Company currently intends to refinance these obligations at maturity with the Company’s $3.0 billion five-year senior unsecured revolving credit facility (Five-Year Facility). 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 $796 million) were put to the Company in October 2015.

Fair Value  The Company uses a market approach to determine the fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the variable interest rates are reflective of market rates. The estimated fair value of the Company’s total borrowings was $17.2 billion at September 30, 2015, and $17.4 billion at December 31, 2014.

16

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Debt and Interest Expense (Continued)

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

	Carrying
millions	Value			Description
Balance at December 31, 2014	$	15,071
Issuances	494			WES 3.950% Senior Notes due 2025
	101			Tangible equity units - senior amortizing notes
Borrowings	1,500			$5.0 billion revolving credit facility
	1,800			364-Day Facility
	280			WES revolving credit facility
	547			Commercial paper notes, net (1)
Repayments	(1,500		)	$5.0 billion revolving credit facility
	(1,800		)	364-Day Facility
	(610		)	WES revolving credit facility
	(8		)	Tangible equity units - senior amortizing notes
Other, net	29			Amortization of debt discounts and premiums
Balance at September 30, 2015	$	15,904

__________________________________________________________________

⁽¹⁾  Includes repayments of $106 million related to commercial paper notes with maturities greater than 90 days.

Anadarko Revolving Credit Facilities and Commercial Paper Program  In January 2015, upon satisfaction of certain conditions, including the settlement payment related to the Tronox Adversary Proceeding, the Company’s $5.0 billion senior secured revolving credit facility was replaced by the Five-Year Facility, which is expandable from $3.0 billion to $4.0 billion, and a $2.0 billion364-day senior unsecured revolving credit facility (364-Day Facility). For additional information, see Note 12—Contingencies—Tronox Litigation.

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

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

During the first quarter of 2015, the Company initiated a commercial paper program, which allows a maximum of $3.0 billion of unsecured commercial paper notes and is supported by the Five-Year Facility. The maturities of the commercial paper notes vary, but may not exceed 397 days. The commercial paper notes are sold under customary terms in the commercial paper market and are issued either at a discounted price to their principal face value or will bear interest at varying interest rates on a fixed or floating basis. Such discounted price or interest amounts are dependent on market conditions and the ratings assigned to the commercial paper program by credit rating agencies at the time of issuance of the commercial paper notes. At September 30, 2015, the Company had $547 million of commercial paper notes outstanding at a weighted-average interest rate of 0.51%. Anadarko classified the outstanding commercial paper notes as long-term debt on the Company’s Consolidated Balance Sheet, as the Company currently intends to refinance these obligations at maturity with additional commercial paper notes supported by the Five-Year Facility.

17

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Debt and Interest Expense (Continued)

WES Borrowings  During the second quarter of 2015, WES completed a public offering of $500 million aggregate principal amount of 3.950% Senior Notes due 2025. At September 30, 2015, WES was in compliance with all covenants contained in its five-year $1.2 billion senior unsecured revolving credit facility maturing in February 2019 (RCF), which is expandable to $1.5 billion. At September 30, 2015, WES had outstanding borrowings under its RCF of $180 million at an interest rate of 1.50%, had outstanding letters of credit of $13 million, and had available borrowing capacity of $1.0 billion.

Interest Expense  The following summarizes interest expense:

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions	2015			2014			2015			2014
Debt and other	$	245		$	250		$	743		$	723
Capitalized interest	(46		)	(46		)	(127		)	(150		)
Total interest expense	$	199		$	204		$	616		$	573

9. Stockholders’ Equity

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

The following provides a reconciliation between basic and diluted earnings per share attributable to common stockholders:

	Three Months Ended   September 30,					Nine Months Ended   September 30,
millions except per-share amounts	2015			2014		2015			2014
Net income (loss)
Net income (loss) attributable to common stockholders	$	(2,235	)	$	1,087	$	(5,442	)	$	(1,355	)
Less noncontrolling interest effect of TEUs	3			—		3			—
Less distributions on participating securities	1			2		4			3
Less undistributed income allocated to participating securities	—			6		—			—
Basic	$	(2,239	)	$	1,079	$	(5,449	)	$	(1,358	)
Diluted	$	(2,239	)	$	1,079	$	(5,449	)	$	(1,358	)
Shares
Average number of common shares outstanding—basic	508			506		508			505
Dilutive effect of stock options	—			2		—			—
Average number of common shares outstanding—diluted	508			508		508			505
Excluded due to anti-dilutive effect	10			3		11			11
Net income (loss) per common share
Basic	$	(4.41	)	$	2.13	$	(10.73	)	$	(2.69	)
Diluted	$	(4.41	)	$	2.12	$	(10.73	)	$	(2.69	)

18

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10. Accumulated Other Comprehensive Income (Loss)

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

millions	Interest-rate Derivatives Previously Subject to Hedge Accounting			Pension and Other Postretirement Plans			Total
Balance at December 31, 2014	$	(48	)	$	(469	)	$	(517	)
Reclassifications to Consolidated Statement of Income	4			26			30
Balance at September 30, 2015	$	(44	)	$	(443	)	$	(487	)

11. Noncontrolling Interests

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

WES, a publicly traded consolidated subsidiary, is a limited partnership that acquires, owns, develops, and operates midstream assets. During the nine months ended September 30, 2015, WES issued 874 thousand common units to the public under its continuous offering program and raised net proceeds of $57 million. In 2014, WES issued 11 million Class C units to Anadarko to partially fund the acquisition of DBM. These Class C units receive distributions in the form of additional Class C units until conversion into common units at the end of 2017, unless WES elects to convert the units earlier or Anadarko extends the conversion date. During the nine months ended September 30, 2015, WES distributed 317 thousand Class C units to Anadarko. At September 30, 2015, WGP’s ownership interest in WES consisted of a 34.6% limited partner interest, the entire 1.8% general partner interest, and all of the WES incentive distribution rights. At September 30, 2015, Anadarko also owned an 8.4% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 55.2% limited partner interest in WES was owned by the public.

12. Contingencies

Litigation  The following is a discussion of any material developments in previously reported contingencies and any other material matters that have arisen since the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

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

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

19

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. Contingencies (Continued)

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

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

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

20

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. Contingencies (Continued)

The actual amount of a CWA penalty is subject to uncertainty, including whether the Company will be able to reach a settlement with the DOJ or will await the Louisiana District Court’s opinion in the penalty phase trial. The CWA sets forth subjective criteria to be considered by the court in assessing the magnitude of any CWA penalty: economic benefit to the violator; degree of culpability; seriousness of the violation; the nature, extent, and degree of success of any efforts to minimize or mitigate the effects of the discharge; prior history of violations; other penalties for the same incident; economic impact of the penalty on the violator; and other matters as justice may require. For the Phase I and II trials (defined in Civil Litigation Damage Claims below) and again for the penalty phase trial in January 2015, the Louisiana District Court ruled that no evidence of Anadarko’s alleged culpability or fault could be presented. In addition, in its Phase I Findings of Fact and Conclusions of Law (Phase I Findings and Conclusions), the Louisiana District Court did not allocate any fault to Anadarko. Given the subjective nature of the CWA criteria used to determine penalty assessments and the Louisiana District Court’s prior rulings related to culpability and allocation of fault, the Company currently cannot reasonably estimate the amount of any such penalty to be assessed or determine a reasonable range of potential loss if the matter is resolved by the Louisiana District Court following trial. Furthermore, BP’s July 2015 announcement of a settlement agreement in principle with the DOJ and certain states regarding essentially all of the outstanding claims against BP related to the Deepwater Horizon event, including $5.5 billion to resolve CWA penalties, and the lodging of a proposed consent decree with the Louisiana District Court in October 2015, does not affect the Company’s current conclusion concerning its ability to estimate potential penalties and fines. The Company had no involvement with the settlement and has no information concerning the rationale for allocating certain settlement proceeds as CWA penalties. The lodged consent decree also provides no explanation as to why the United States and the various states and local government entities consider the penalty amount to be fair and reasonable.

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

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

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

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

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

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

As discussed below, numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. Certain state and local governments appealed, or provided indication of a likely appeal of, the Louisiana District Court’s decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. These appeals will be dismissed as part of BP’s settlement with the United States and various states and local government entities, provided that the consent decree is ultimately approved by the Louisiana District Court. 

21

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12. Contingencies (Continued)

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

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

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

The penalty phase of the trial began in January 2015. In March 2014, the Louisiana District Court ruled that no evidence of Anadarko’s alleged culpability or fault could be presented during the penalty phase trial. The parties rested their case in February 2015, post-trial briefing concluded in April 2015, and the matter is pending before the Louisiana District Court. The trial included Anadarko, BP, and the United States. As discussed above, in October 2015, a proposed consent decree was lodged with the Louisiana District Court that sets out a global settlement between (i) BP and (ii) the United States, certain states and local government entities resolving various claims for penalties and fines, including civil claims under the CWA and natural resources damage claims under OPA.

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

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

The Company will continue to monitor the MDL and other legal proceedings discussed above 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.

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

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

22

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

13. 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	2015			2014			2015			2014
Income tax expense (benefit)	$	(917	)	$	627		$	(2,232	)	$	1,719
Income (loss) before income taxes	(3,077		)	1,774			(7,520		)	506
Effective tax rate	30		%	35		%	30		%	340		%

The Company reported a loss before income taxes for the three and nine months ended September 30, 2015. As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The decrease from the 35% U.S. federal statutory rate for the three and nine months ended September 30, 2015, was primarily attributable to Algerian exceptional profits taxes and the tax impact from foreign operations.

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 nine months ended September 30, 2014, was primarily attributable to net changes in uncertain tax positions related to the settlement agreement associated with the Tronox Adversary Proceeding, the tax impact from foreign operations, Algerian exceptional profits taxes, and the non-deductible contingent CWA-penalty accrual.

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

At September 30, 2015, the Company’s Consolidated Balance Sheet included $959 million of income taxes receivable presented in accounts receivable—others.

14. Supplemental Cash Flow Information

For the nine months ended September 30, 2015, the Company’s Consolidated Statement of Cash Flows includes $887 million of taxes related to the Tronox settlement included in (increase) decrease in accounts receivable, offset by an $887 million uncertain tax position included in other items—net. The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing and financing activities:

	Nine Months Ended   September 30,
millions	2015			2014
Cash paid (received)
Interest, net of amounts capitalized (1)	$	1,916		$	600
Income taxes, net of refunds	(163		)	661
Non-cash investing activities
Fair value of properties and equipment from non-cash transactions	$	156		$	7
Asset retirement cost additions	139			149
Accruals of property, plant, and equipment	858			1,154
Net liabilities assumed (divested) in acquisitions and divestitures	(84		)	(126		)
Non-cash investing and financing activities
Floating production, storage, and offloading vessel construction period obligation	$	51		$	88

__________________________________________________________________

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

23

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15. Segment Information

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

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

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, such as operating income or cash flows from operating activities. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes:

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions	2015			2014			2015			2014
Income (loss) before income taxes	$	(3,077	)	$	1,774		$	(7,520	)	$	506
Exploration expense	1,074			199			2,260			1,000
DD&A	1,111			1,163			3,581			3,335
Impairments	758			394			3,571			514
Interest expense	199			204			616			573
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	360			(276		)	374			324
Deepwater Horizon settlement and related costs	—			3			4			96
Tronox-related contingent loss	—			19			5			4,338
Certain other nonoperating items	—			22			22			22
Less net income attributable to noncontrolling interests	75			60			154			142
Consolidated Adjusted EBITDAX	$	350		$	3,442		$	2,759		$	10,566

24

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15. Segment Information (Continued)

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

millions	Oil and Gas Exploration & Production			Midstream			Marketing			Other and Intersegment Eliminations			Total
Three Months Ended September 30, 2015
Sales revenues	$	1,067		$	195		$	968		$	—		$	2,230
Intersegment revenues	750			315			(832		)	(233		)	—
Gains (losses) on divestitures and other, net	(557		)	(22		)	—			37			(542		)
Total revenues and other	1,260			488			136			(196		)	1,688
Operating costs and expenses (1)	840			287			181			(14		)	1,294
Net cash from settlement of commodity derivatives	—			—			—			(79		)	(79		)
Other (income) expense, net (2)	—			—			—			47			47
Net income attributable to noncontrolling interests	—			75			—			—			75
Total expenses and other	840			362			181			(46		)	1,337
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—			(1		)	—			(1		)
Adjusted EBITDAX	$	420		$	126		$	(46	)	$	(150	)	$	350
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

 __________________________________________________________________

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

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

25

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

15. Segment Information (Continued)

millions	Oil and Gas Exploration & Production			Midstream			Marketing			Other and Intersegment Eliminations			Total
Nine Months Ended September 30, 2015
Sales revenues	$	3,493		$	560		$	3,399		$	—		$	7,452
Intersegment revenues	2,752			920			(2,977		)	(695		)	—
Gains (losses) on divestitures and other, net	(990		)	(19		)	—			202			(807		)
Total revenues and other	5,255			1,461			422			(493		)	6,645
Operating costs and expenses (1)	2,674			761			571			(110		)	3,896
Net cash from settlement of commodity derivatives	—			—			—			(251		)	(251		)
Other (income) expense, net (2)	—			—			—			87			87
Net income attributable to noncontrolling interests	—			154			—			—			154
Total expenses and other	2,674			915			571			(274		)	3,886
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement	—			—			—			—			—
Adjusted EBITDAX	$	2,581		$	546		$	(149	)	$	(219	)	$	2,759
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

 __________________________________________________________________

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

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

26

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

16. Pension Plans and Other Postretirement Benefits

The Company has contributory and non-contributory defined-benefit pension plans, which include both qualified and supplemental plans. The Company also provides certain health care and life insurance benefits for certain retired employees. Retiree health care benefits are funded by contributions from the retiree, and in certain circumstances, contributions from the Company. The Company’s retiree life insurance plan is noncontributory. The following summarizes the Company’s pension and other postretirement benefit cost:

	Pension Benefits						Other Benefits
millions	2015			2014			2015		2014
Three Months Ended September 30
Service cost	$	30		$	25		$	3	$	1
Interest cost	25			25			3		4
Expected return on plan assets	(27		)	(27		)	—		—
Amortization of net actuarial loss (gain)	13			9			—		(2		)
Amortization of net prior service cost (credit)	—			—			1		—
Net periodic benefit cost	$	41		$	32		$	7	$	3
Nine Months Ended September 30
Service cost	$	89		$	74		$	8	$	5
Interest cost	76			75			11		11
Expected return on plan assets	(82		)	(80		)	—		—
Amortization of net actuarial loss (gain)	39			26			—		(5		)
Amortization of net prior service cost (credit)	—			—			2		—
Net periodic benefit cost	$	122		$	95		$	21	$	11

27

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

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

• the Company’s assumptions about energy markets

• production and sales volume levels

• reserves levels

• operating results

• competitive conditions

• technology

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

• supply and demand for, the price of, and the commercialization and transporting of natural gas, oil, natural gas liquids (NGLs), and other products or services

• volatility in the commodity-futures market

• weather

• inflation

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

• drilling risks

• processing volumes and pipeline throughput

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

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

• legislative or regulatory changes, including changes relating to hydraulic fracturing; 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

28

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

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

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

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

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

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

• disruptions in international oil, NGLs, and condensate cargo shipping activities

• physical, digital, internal, and external security breaches

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

• other factors discussed below and elsewhere in “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, this Form 10-Q, and in the Company’s other public filings, press releases, and discussions with Company management

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Form 10-Q in Part I, Item 1; the information set forth in Risk Factors under Part II, Item 1A; the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Part II, Item 8 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2014; and the information set forth in the Risk Factors under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

OVERVIEW

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

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

Overall

• Anadarko’s third-quarter sales volumes averaged 787 thousand barrels of oil equivalent per day (MBOE/d), representing a 7% decrease from the third quarter of 2014.

• Oil and NGLs (liquids) third-quarter sales volumes decreased by 2%, or 10 thousand barrels per day (MBbls/d) from the third quarter of 2014. This decrease was primarily the result of a 12 MBbls/d decrease in sales volumes related to the April 2015 divestiture of certain enhanced oil recovery (EOR) assets in the Rocky Mountains Region (Rockies).

• The Company’s overall sales product mix increased to 55% liquids in the third quarter of 2015 compared to 51% in the third quarter of 2014.

• Anadarko continued to lower its cost structure through operational efficiencies and reduced service costs.

U.S. Onshore

• U.S. onshore third-quarter liquids sales volumes decreased by 12 MBbls/d, representing a 4% decrease from the third quarter of 2014, primarily due to the April 2015 sale of certain EOR assets.

• U.S. onshore third-quarter natural-gas sales volumes decreased by 52 MBOE/d, representing a 13% decrease from the third quarter of 2014, primarily due to voluntary curtailments in the Marcellus shale and at Greater Natural Buttes, the September 2015 sale of certain coalbed methane properties in the Rockies, and the July 2015 sale of certain U.S. onshore oil and gas properties and related midstream assets in East Texas.

Gulf of Mexico

• Gulf of Mexico third-quarter sales volumes averaged 88 MBOE/d, representing a 14% increase from the third quarter of 2014, primarily due to the commencement of oil production from the Lucius development in January 2015, partially offset by natural-gas production declines at Independence Hub.

International

• International third-quarter sales volumes averaged 82 MBbls/d, representing a 10% decrease from the third quarter of 2014, primarily due to the timing of cargo liftings in Algeria.

• The Kronos-1 prospect in deepwater Colombia encountered 130 to 230 net feet of natural-gas pay in the upper objective. The well finished drilling during the third quarter after testing a deeper objective where it encountered non-commercial hydrocarbons.

• Anadarko wrote off approximately $600 million of suspended exploratory costs in Brazil, where the Company does not expect to have substantive exploration and development activities for the foreseeable future given the current oil-price environment and other considerations.

Financial

• Anadarko’s net loss attributable to common stockholders for the third quarter of 2015 totaled $2.2 billion, including certain exploration expenses of $787 million primarily associated with the write-off of suspended exploratory well costs in Brazil, impairment expense of $758 million primarily related to certain U.S. onshore and Gulf of Mexico properties, and losses on divestitures of $578 million primarily related to the divestiture of certain coalbed methane properties in the Rockies.

• The Company generated $1.1 billion of cash flow from operations and ended the quarter with $2.1 billion of cash on hand.

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

RESULTS OF OPERATIONS

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions except per-share amounts	2015			2014			2015			2014
Financial Results
Revenues and other	$	1,688		$	5,010		$	6,645		$	15,293
Costs and expenses	4,237			3,312			13,312			9,411
Other (income) expense	528			(76		)	853			5,376
Income tax expense (benefit)	(917		)	627			(2,232		)	1,719
Net income (loss) attributable to common stockholders	$	(2,235	)	$	1,087		$	(5,442	)	$	(1,355	)
Net income (loss) per common share attributable to common stockholders—diluted	$	(4.41	)	$	2.12		$	(10.73	)	$	(2.69	)
Average number of common shares outstanding—diluted	508			508			508			505
Operating Results
Adjusted EBITDAX (1)	$	350		$	3,442		$	2,759		$	10,566
Sales volumes (MMBOE)	73			78			234			229

 ________________________________________________________________________________________________________

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
2014 sales revenues	$	830		$	2,637		$	424		$	3,891
Changes associated with sales volumes	(103		)	(22		)	(26		)	(151		)
Changes associated with prices	(243		)	(1,386		)	(215		)	(1,844		)
2015 sales revenues	$	484		$	1,229		$	183		$	1,896
Increase (decrease) vs. 2014	(42		)%	(53		)%	(57		)%	(51		)%
	Nine Months Ended September 30,
millions except percentages	Natural Gas			Oil and Condensate			NGLs			Total
2014 sales revenues	$	3,038		$	7,766		$	1,221		$	12,025
Changes associated with sales volumes	(210		)	783			180			753
Changes associated with prices	(1,216		)	(4,285		)	(757		)	(6,258		)
2015 sales revenues	$	1,612		$	4,264		$	644		$	6,520
Increase (decrease) vs. 2014	(47		)%	(45		)%	(47		)%	(46		)%

Anadarko’s sales revenues decreased for the three months ended September 30, 2015, due to lower average commodity prices and lower sales volumes for all commodities. Anadarko’s sales revenues decreased for the nine months ended September 30, 2015, due to lower average commodity prices and lower natural-gas sales volumes, partially offset by higher sales volumes for oil and NGLs. Sales volumes for the three and nine months ended September 30, 2015, also included decreases associated with asset divestitures.

	Three Months Ended   September 30,				Nine Months Ended   September 30,
Sales Volumes	2015	Inc/(Dec) vs. 2014		2014	2015	Inc/(Dec) vs. 2014		2014
Barrels of Oil Equivalent    (MMBOE except percentages)
United States	65	(7	)%	70	209	2	%	204
International	8	(10	)	8	25	(2	)	25
Total barrels of oil equivalent	73	(7	)	78	234	2		229
Barrels of Oil Equivalent per Day    (MBOE/d except percentages)
United States	705	(7	)%	758	765	2	%	747
International	82	(10	)	91	90	(2	)	92
Total barrels of oil equivalent per day	787	(7	)	849	855	2		839

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

32

Natural-Gas Sales Volumes, Average Prices, and Revenues

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2015		Inc/(Dec) vs. 2014		2014		2015		Inc/(Dec) vs. 2014		2014
United States
Sales volumes—Bcf	201		(12	)%	230		662		(7	)%	711
MMcf/d	2,186		(12	)	2,494		2,424		(7	)	2,603
Price per Mcf	$	2.41	(33	)	$	3.62	$	2.44	(43	)	$	4.27
Natural-gas sales revenues (millions)	$	484	(42	)	$	830	$	1,612	(47	)	$	3,038

 _______________________________________________________________________________

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

Mcf—thousand cubic feet

The Company’s natural-gas sales volumes decreased by 308 MMcf/d for the three months ended September 30, 2015, and 179 MMcf/d for the nine months ended September 30, 2015.

• Sales volumes in the Southern and Appalachia Region decreased by 203 MMcf/d for the three months ended September 30, 2015, and 119 MMcf/d for the nine months ended September 30, 2015, primarily due to voluntary curtailments in the Marcellus shale and the July 2015 sale of certain U.S. onshore oil and gas properties and related midstream assets in East Texas. These decreases were partially offset by higher sales volumes as a result of continued horizontal drilling in the Eagleford shale. In addition, sales volumes for the nine months ended September 30, 2015, decreased in the Marcellus shale due to third-party infrastructure downtime.

• Sales volumes in the Rockies decreased by 109 MMcf/d for the three months ended September 30, 2015, and 23 MMcf/d for the nine months ended September 30, 2015, due to voluntary curtailments at Greater Natural Buttes, natural production declines at Powder River basin, and the September 2015 sale of certain coalbed methane properties, partially offset by higher sales volumes in the Wattenberg field as a result of continued horizontal drilling.

• Sales volumes in the Gulf of Mexico were essentially flat for the three months ended September 30, 2015, and decreased by 37 MMcf/d for the nine months ended September 30, 2015, primarily due to a natural production decline at Independence Hub.

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

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Oil and Condensate Sales Volumes, Average Prices, and Revenues

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2015		Inc/(Dec) vs. 2014		2014		2015		Inc/(Dec) vs. 2014		2014
United States
Sales volumes—MMBbls	21		5	%	20		64		19	%	54
MBbls/d	224		5		213		233		19		197
Price per barrel	$	43.48	(53	)	$	92.59	$	47.37	(50	)	$	95.30
International
Sales volumes—MMBbls	7		(15	)%	8		23		(8	)%	25
MBbls/d	77		(15	)	90		84		(8	)	91
Price per barrel	$	47.30	(52	)	$	99.24	$	54.13	(49	)	$	105.58
Total
Sales volumes—MMBbls	28		(1	)%	28		87		10	%	79
MBbls/d	301		(1	)	303		317		10		288
Price per barrel	$	44.45	(53	)	$	94.56	$	49.16	(50	)	$	98.57
Oil and condensate sales revenues (millions)	$	1,229	(53	)	$	2,637	$	4,264	(45	)	$	7,766

 _______________________________________________________________________________

MMBbls—million barrels

Anadarko’s oil and condensate sales volumes decreased by 2 MBbls/d for the three months ended September 30, 2015, and increased by 29 MBbls/d for the nine months ended September 30, 2015.

• International sales volumes decreased by 13 MBbls/d for the three months ended September 30, 2015, primarily due to the timing of cargo liftings in Algeria. For the nine months ended September 30, 2015, international sales volumes decreased by 7 MBbls/d, primarily due to the timing of cargo liftings in Algeria and the sale of the Company’s Chinese subsidiary in August 2014, partially offset by higher sales volumes due to the timing of liftings in Ghana.

• Sales volumes in the Rockies decreased by 4 MBbls/d for the three months ended September 30, 2015, primarily as a result of the sale of certain EOR assets in April 2015, partially offset by higher sales volumes in the Wattenberg field due to continued horizontal drilling. Sales volumes in the Rockies increased by 17 MBbls/d for the nine months ended September 30, 2015, primarily in the Wattenberg field due to continued horizontal drilling, partially offset by lower sales volumes due to the sale of certain EOR assets in April 2015.

• Southern and Appalachia Region sales volumes increased by 6 MBbls/d for the three months ended September 30, 2015, and 11 MBbls/d for the nine months ended September 30, 2015, primarily in the Eagleford shale as a result of continued horizontal drilling and in the Delaware basin due to increased drilling and wells brought online as a result of added infrastructure.

• Sales volumes in the Gulf of Mexico increased by 9 MBbls/d for the three and nine months ended September 30, 2015, primarily from the Lucius development, which achieved first oil in January 2015, partially offset by a natural production decline at Marco Polo.

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

34

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

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2015		Inc/(Dec) vs. 2014		2014		2015		Inc/(Dec) vs. 2014		2014
United States
Sales volumes—MMBbls	11		(10	)%	11		35		10	%	31
MBbls/d	117		(10	)	129		128		10		116
Price per barrel	$	15.83	(55	)	$	35.11	$	17.08	(55	)	$	38.21
International
Sales volumes—MMBbls	1		NM		—		2		NM		—
MBbls/d	5		NM		1		6		NM		1
Price per barrel	$	25.18	(62	)	$	65.55	$	29.79	(55	)	$	66.14
Total
Sales volumes—MMBbls	12		(6	)%	11		37		15	%	31
MBbls/d	122		(6	)	130		134		15		117
Price per barrel	$	16.26	(54	)	$	35.35	$	17.63	(54	)	$	38.38
Natural-gas liquids sales revenues (millions)	$	183	(57	)	$	424	$	644	(47	)	$	1,221

_________________________________________________________________________

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 decreased by 8 MBbls/d for the three months ended September 30, 2015, and increased by 17 MBbls/d for the nine months ended September 30, 2015.

• Sales volumes in the Rockies decreased by 11 MBbls/d for the three months ended September 30, 2015, primarily due to the Company’s economic decision to reject ethane, partially offset by an increase due to continued horizontal drilling in the Wattenberg field. Sales volumes in the Rockies increased by 8 MBbls/d for the nine months ended September 30, 2015, primarily in the Wattenberg field due to continued horizontal drilling and the Lancaster plant coming online in April 2014, partially offset by ethane rejection.

• Sales volumes in the Southern and Appalachia Region decreased by 3 MBbls/d for the three months ended September 30, 2015, primarily due to voluntary curtailments in the Haynesville shale. Sales volumes in the Southern and Appalachia Region increased by 3 MBbls/d for the nine months ended September 30, 2015, as a result of continued horizontal drilling in the Eagleford shale, partially offset by voluntary curtailments in the Haynesville shale.

• International NGLs sales volumes increased by 4 MBbls/d for the three months ended September 30, 2015, and 5 MBbls/d for the nine months ended September 30, 2015, as volumes increased in Algeria since the commencement of sales at the Company’s El Merk facility during the second quarter of 2014.

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

35

Gathering, Processing, and Marketing

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions except percentages	2015		Inc/(Dec) vs. 2014		2014		2015		Inc/(Dec) vs. 2014		2014
Gathering, processing, and marketing sales	$	334	(1	)%	$	339	$	932	—		$	928
Gathering, processing, and marketing expense	289		7		269		798		4	%	771
Total gathering, processing, and marketing, net	$	45	(36	)	$	70	$	134	(15	)	$	157

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 decreased by $25 millionfor the three months ended September 30, 2015, and $23 million for the nine months ended September 30, 2015, primarily resulting from lower processing revenues due to decreased commodity prices. These decreases were partially offset by the impact of Western Gas Partners, LP’s (WES) November 2014 acquisition of Nuevo Midstream, LLC, which following the acquisition was renamed Delaware Basin Midstream, LLC (DBM), and higher gathering revenue related to higher throughput volumes and an increase in transportation rates.

Gains (Losses) on Divestitures and Other, net

	Three Months Ended   September 30,					Nine Months Ended   September 30,
millions	2015			2014		2015			2014
Gains (losses) on divestitures and other, net	$	(542	)	$	780	$	(807	)	$	2,340

For the three months ended September 30, 2015, gains (losses) on divestitures and other, net decreased by $1.3 billion.

• The Company recognized a loss of $440 million on the divestiture of certain oil and gas coalbed methane properties in the Rockies, which closed in September 2015, and a loss on assets held for sale of $100 million for the related midstream assets, which is expected to close in the fourth quarter of 2015.

• The Company recognized 2014 gains of $510 million associated with the divestiture of its Chinese subsidiary and $216 million associated with the divestiture of its interest in certain unproved properties in the Gulf of Mexico.

For the nine months ended September 30, 2015, gains (losses) on divestitures and other, net decreased by $3.1 billion.

• The Company recognized losses of $1.0 billion on divestitures and assets held for sale during the nine months ended September 30, 2015. These losses were comprised of a $440 million loss on the September 2015 divestiture of certain coalbed methane properties in the Rockies and a loss of $100 million on the related midstream properties, a loss of $344 million associated with certain EOR assets in the Rockies, and a $110 million loss on certain East Texas oil and gas properties and related midstream assets.

• The Company recognized income of $130 million in 2015 related to the settlement of a royalty lawsuit associated with a property in the Gulf of Mexico.

• The Company recognized gains on divestitures of $2.2 billion in 2014. These gains were comprised of a $1.5 billion gain associated with its divestiture of a 10% working interest in Offshore Area 1 in Mozambique, a gain of $510 million associated with the divestiture of its Chinese subsidiary, and a gain of $216 million associated with the divestiture of its interest in certain unproved properties in the Gulf of Mexico.

36

Costs and Expenses

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2015		Inc/(Dec) vs. 2014		2014		2015		Inc/(Dec) vs. 2014		2014
Oil and gas operating (millions)	$	262	(5	)%	$	275	$	784	(9	)%	$	861
Oil and gas operating—per BOE	3.62		3		3.53		3.36		(11	)	3.76
Oil and gas transportation and other (millions)	271		(16	)	322		921		6		869
Oil and gas transportation and other—per BOE	3.75		(9	)	4.12		3.94		4		3.79

_________________________________________________________________________

BOE—barrel of oil equivalent

Oil and gas operating expense decreased by $13 million for the three months ended September 30, 2015, due to lower 2015 expenses of $33 million as a result of divestitures, partially offset by higher workover costs of $17 million primarily in the Gulf of Mexico. Oil and gas operating expenses per BOE increased by $0.09 for the three months ended September 30, 2015, primarily due to higher workover costs.

Oil and gas operating expense decreased by $77 million for the nine months ended September 30, 2015, due to lower 2015 expenses of $92 million as a result of divestitures and lower workover costs of $28 million as a result of reduced activity primarily in the Southern and Appalachia Region and the Rockies, partially offset by higher costs in Ghana of $44 million primarily associated with increased workovers. Oil and gas operating expenses per BOE decreased by $0.40 for the nine months ended September 30, 2015, primarily due to higher sales volumes in 2015.

Oil and gas transportation and other expense decreased by $51 million for the three months ended September 30, 2015, primarily attributable to lower natural-gas sales volumes in the Rockies and the Southern and Appalachia Region.

Oil and gas transportation and other expense increased by $52 million for the nine months ended September 30, 2015, primarily attributable to a $50 million expense for the early termination of a drilling rig.

Oil and gas transportation and other expense per BOE decreased by $0.37 for the three months ended September 30, 2015, due to lower costs discussed above, partially offset by lower sales volumes. Oil and gas transportation and other expense per BOE increased by $0.15 for the nine months ended September 30, 2015, as higher costs were only partially offset by higher oil and NGLs sales volumes. Oil and gas transportation and other expense per BOE for the nine months ended September 30, 2015, included $0.21 related to the early termination of the drilling rig.

37

	Three Months Ended   September 30,				Nine Months Ended   September 30,
millions	2015		2014		2015		2014
Exploration Expense
Dry hole expense	$	817	$	104	$	859	$	527
Impairments of unproved properties	136		30		1,134		216
Geological and geophysical expense	67		13		105		93
Exploration overhead and other	54		52		162		164
Total exploration expense	$	1,074	$	199	$	2,260	$	1,000

For the three months ended September 30, 2015, total exploration expense increased by $875 million.

• Dry hole expense increased by $713 million, which included the 2015 write-off of suspended exploratory well costs of $668 million, primarily related to Brazil, where the Company does not expect to have substantive exploration and development activities for the foreseeable future given the current oil-price environment and other considerations. The Company also recognized $149 million of expenses due to unsuccessful drilling activities primarily associated with Gulf of Mexico properties and the deeper objective of a well in Colombia. The Company recognized $104 million of expenses during the three months ended September 30, 2014, due to unsuccessful drilling activities primarily associated with wells in Mozambique, Côte d’Ivoire, and the Gulf of Mexico.

• Impairments of unproved properties increased by $106 million primarily due to a $109 million impairment of the Company’s unproved Utica properties resulting from an assignment of mineral interests in settlement of a legal matter.

• Geological and geophysical expense increased by $54 million primarily due to seismic purchases in Colombia in 2015.

For the nine months ended September 30, 2015, total exploration expense increased by $1.3 billion.

• Impairments of unproved properties increased by $918 million primarily due to a $935 million impairment related to the Company’s unproved Greater Natural Buttes properties as a result of lower commodity prices and the $109 million impairment for unproved Utica properties. In 2014, the Company recognized impairments of $54 million primarily related to the expiration of leases in the Gulf of Mexico, $50 million due to the decision not to pursue further drilling in Sierra Leone, and $33 million as a result of changes in the Company’s drilling plans for certain U.S. onshore oil and gas properties.

• Dry hole expense increased by $258 million, which included the 2015 write-off of suspended exploratory well costs of $668 million, primarily related to Brazil as discussed above. The Company also recognized $191 million of expenses due to unsuccessful drilling activities primarily associated with Gulf of Mexico properties and the deeper objective of a well in Colombia. The Company recognized $527 million during the nine months ended September 30, 2014, due to unsuccessful drilling activities associated with wells in the Gulf of Mexico, New Zealand, the Rockies, and Côte d’Ivoire.

• Geological and geophysical expense increased by $12 million due to 2015 seismic purchases in Colombia, partially offset by 2014 seismic purchases in Côte d’Ivoire.

38

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions except percentages	2015		Inc/(Dec) vs. 2014		2014		2015		Inc/(Dec) vs. 2014		2014
General and administrative	$	345	(9	)%	$	381	$	933	(5	)%	$	984
Depreciation, depletion, and amortization	1,111		(4	)	1,163		3,581		7		3,335
Other taxes	127		(58	)	306		460		(53	)	981
Impairments	758		92		394		3,571		NM		514

General and administrative expense (G&A) decreased by $36 million for the three months ended September 30, 2015, and by $51 million for the nine months ended September 30, 2015, primarily due to lower employee-related expenses associated with lower bonus plan expense. For the three months ended September 30, 2015, G&A expense was partially offset by higher legal fees.

Depreciation, depletion, and amortization (DD&A) expense decreased by $52 million for the three months ended September 30, 2015, primarily due to lower 2015 sales volumes associated with U.S. onshore properties, partially offset by increased costs associated with additional gathering and processing facilities and increased asset retirement costs for wells in the Gulf of Mexico.

DD&A expense increased by $246 million for the nine months ended September 30, 2015, primarily due to costs associated with U.S. onshore properties and additional gathering and processing facilities, higher 2015 sales volumes associated with U.S. onshore properties, increased costs associated with additional gathering and processing facilities, and increased asset retirement costs for wells in the Gulf of Mexico.

Other taxes decreased by $179 million for the three months ended September 30, 2015, primarily due to lower U.S. severance taxes of $72 million, lower Algerian exceptional profits taxes of $70 million, and lower ad valorem taxes of $38 million. These decreases were primarily caused by lower commodity prices and lower sales volumes.

Other taxes decreased by $521 million for the nine months ended September 30, 2015, primarily due to lower U.S. severance taxes of $216 million, lower Algerian exceptional profits taxes of $180 million, and lower ad valorem taxes of $100 million. These decreases were primarily due to lower commodity prices. Also, Chinese windfall profits taxes decreased by $24 million for the nine months ended September 30, 2015, as a result of the sale of the Company’s Chinese subsidiary in August 2014.

Impairment expense for the three months ended September 30, 2015, included $641 million for U.S. onshore oil and gas properties primarily in the Southern and Appalachia Region and $101 million for an oil and gas property in the Gulf of Mexico, all due to lower forecasted commodity prices. Impairment expense for the three months ended September 30, 2014, included $387 million for a U.S. onshore oil and gas property in the Southern and Appalachia Region due to lower forecasted natural-gas prices.

Impairment expense for the nine months ended September 30, 2015, included $2.3 billion related to the Company’s Greater Natural Buttes oil and gas properties and $449 million for related midstream properties in the Rockies, $662 million for other U.S. onshore oil and gas properties primarily in the Southern and Appalachia Region, and $126 million for oil and gas properties in the Gulf of Mexico, all due to lower forecasted commodity prices. Impairment expense for the nine months ended September 30, 2014, included $387 million for the U.S. onshore oil and gas property discussed above and $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.

39

	Three Months Ended   September 30,				Nine Months Ended   September 30,
millions	2015		2014		2015		2014
Deepwater Horizon settlement and related costs	$	—	$	3	$	4	$	96

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

Other (Income) Expense

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions except percentages	2015			2014			2015			2014
Interest Expense
Debt and other	$	245		$	250		$	743		$	723
Capitalized interest	(46		)	(46		)	(127		)	(150		)
Total interest expense	$	199		$	204		$	616		$	573

Interest expense for the three months ended September 30, 2015, was essentially flat compared to the three months ended September 30, 2014. Interest expense for the nine months ended September 30, 2015, increased by $43 million primarily due to a decrease in capitalized interest related to lower construction-in-progress balances for long-term capital projects and an increase in interest expense due to higher debt outstanding during 2015.

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions	2015			2014			2015			2014
(Gains) Losses on Derivatives, net
(Gains) losses on commodity derivatives, net	$	(125	)	$	(419	)	$	(177	)	$	(40	)
(Gains) losses on interest-rate derivatives, net	407			96			300			493
Total (gains) losses on derivatives, net	$	282		$	(323	)	$	123		$	453

(Gains) losses on derivatives, net represents the changes in fair value of the Company’s derivative instruments as a result of changes in commodity prices and interest rates. Anadarko enters into commodity derivatives to manage the risk of changes in the market prices for its anticipated sales of production. Anadarko also enters into interest-rate swaps to fix or float interest rates on existing or anticipated indebtedness to manage exposure to interest-rate changes. For additional information, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

40

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions	2015			2014			2015			2014
Other (Income) Expense, net
Interest income	$	(2	)	$	(13	)	$	(9	)	$	(20	)
Other	49			37			118			32
Total other (income) expense, net	$	47		$	24		$	109		$	12

For the three months ended September 30, 2015, other expense, net increased by $23 million.

• Losses associated with certain equity investments increased by $17 million as a result of lower commodity prices.

• Changes in foreign currency gains/losses of $12 million reflect the unfavorable impact of exchange-rate changes primarily applicable to foreign currency held in escrow pending final determination of the Company’s Brazilian tax liability attributable to the 2008 divestiture of the Peregrino field offshore Brazil.

• Interest income from short-term investments decreased by $11 million.

• Decommissioning costs of $22 million were recorded in the third quarter of 2014. As a result of a Chapter 11 bankruptcy declaration by a third party, the U.S. Department of the Interior ordered Anadarko to perform the decommissioning of a production facility and related wells, previously sold to the third party. The Company accrued the costs to decommission the facility and the wells in prior years.

For the nine months ended September 30, 2015, other expense, net increased by $97 million.

• Losses associated with certain equity investments increased by $48 million as a result of lower commodity prices.

• Changes in foreign currency gains/losses of $42 million reflect the unfavorable impact of exchange-rate changes primarily applicable to foreign currency held in escrow as discussed above.

• Interest income from short-term investments decreased by $11 million.

	Three Months Ended   September 30,				Nine Months Ended   September 30,
millions	2015		2014		2015		2014
Tronox-related contingent loss	$	—	$	19	$	5	$	4,338

In April 2014, Anadarko and Kerr-McGee Corporation and certain of its subsidiaries (collectively, Kerr-McGee) entered into a settlement agreement for $5.15 billion, resolving all claims asserted in the Tronox Adversary Proceeding. In addition, the Company agreed to pay interest on that amount from April 3, 2014, through the payment of the settlement, and in January 2015, paid $5.2 billion after the settlement agreement became effective.

Anadarko recognized a Tronox-related contingent loss of $4.3 billion during the nine months ended September 30, 2014, settlement-related interest expense of $19 million for the three months ended September 30, 2014, $38 million for the nine months ended September 30, 2014, and additional settlement-related interest expense of $5 million until the settlement payment was made in late January 2015. See Note 12—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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Income Tax Expense

	Three Months Ended   September 30,						Nine Months Ended   September 30,
millions except percentages	2015			2014			2015			2014
Income tax expense (benefit)	$	(917	)	$	627		$	(2,232	)	$	1,719
Income (loss) before income taxes	(3,077		)	1,774			(7,520		)	506
Effective tax rate	30		%	35		%	30		%	340		%

The Company reported a loss before income taxes for the three and nine months ended September 30, 2015. As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The decrease from the 35% U.S. federal statutory rate for the three and nine months ended September 30, 2015, was primarily attributable to Algerian exceptional profits taxes and the tax impact from foreign operations.

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 nine months ended September 30, 2014, was primarily attributable to net changes in uncertain tax positions related to the settlement agreement associated with the Tronox Adversary Proceeding, the tax impact from foreign operations, Algerian exceptional profits taxes, and the non-deductible contingent CWA-penalty accrual.

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

Net Income Attributable to Noncontrolling Interests

The Company’s net income attributable to noncontrolling interests for the three and nine months ended September 30, 2015 and 2014, related to public ownership interests in WES and Western Gas Equity Partners, LP (WGP). Public ownership in WES consisted of a limited partnership interest of 55.2% at September 30, 2015, and 56.8% at September 30, 2014. Public ownership in WGP consisted of a limited partnership interest of 12.7% at September 30, 2015, and 11.7% at September 30, 2014. In June 2015, Anadarko issued 9.2 million tangible equity units (TEUs), which include an equity component that may be settled in WGP common units, and sold 2.3 million WGP common units to the public. See Note 7—Tangible Equity Units and Note 11—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

42

OPERATING RESULTS

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

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

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Adjusted EBITDAX

	Three Months Ended   September 30,								Nine Months Ended   September 30,
millions except percentages	2015			Inc/(Dec) vs. 2014		2014			2015			Inc/(Dec) vs. 2014		2014
Income (loss) before income taxes	$	(3,077	)	NM		$	1,774		$	(7,520	)	NM		$	506
Exploration expense	1,074			NM		199			2,260			126	%	1,000
DD&A	1,111			(4	)%	1,163			3,581			7		3,335
Impairments	758			92		394			3,571			NM		514
Interest expense	199			(2	)	204			616			8		573
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives	360			NM		(276		)	374			15		324
Deepwater Horizon settlement and related costs	—			(100	)	3			4			(96	)	96
Tronox-related contingent loss	—			(100	)	19			5			(100	)	4,338
Certain other nonoperating items	—			(100	)	22			22			—		22
Less net income attributable to noncontrolling interests	75			25		60			154			8		142
Consolidated Adjusted EBITDAX	$	350		(90	)	$	3,442		$	2,759		(74	)	$	10,566
Adjusted EBITDAX by reporting segment
Oil and gas exploration and production	$	420		(88	)%	$	3,430		$	2,581		(76	)%	$	10,817
Midstream	126			(28	)	175			546			11		492
Marketing	(46		)	(5	)	(44		)	(149		)	(15	)	(130		)
Other and intersegment eliminations	(150		)	(26	)	(119		)	(219		)	64		(613		)

Oil and Gas Exploration and Production  Adjusted EBITDAX decreased for the three months ended September 30, 2015, primarily due to lower commodity prices, lower sales volumes, and net losses on divestitures in 2015 compared to net gains on divestitures in 2014. Adjusted EBITDAX decreased for the nine months ended September 30, 2015, primarily due to lower commodity prices and net losses on divestitures in 2015 compared to net gains on divestitures in 2014, partially offset by higher oil and NGLs sales volumes.

MidstreamAdjusted EBITDAX decreased for the three months ended September 30, 2015, primarily due to lower processing revenues as a result of decreased commodity prices, partially offset by increased processing volumes primarily related to WES’s November 2014 acquisition of DBM. Adjusted EBITDAX increased for the nine months ended September 30, 2015, primarily due to higher gathering revenue resulting from higher throughput volumes and an increase in transportation rates, partially offset by higher operating expenses associated with WES’s acquisition of DBM.

MarketingMarketing earnings primarily represent the margin earned on sales of natural gas, oil, and NGLs purchased from third parties. Adjusted EBITDAX decreased for the three months ended September 30, 2015, primarily due to higher transportation expenses as a result of increased third-party volumes, partially offset by higher marketing margins for NGLs. Adjusted EBITDAX decreased for the nine months ended September 30, 2015, due to higher transportation expenses as a result of increased volumes.

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

44

LIQUIDITY AND CAPITAL RESOURCES

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

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

At September 30, 2015, Anadarko’s scheduled debt maturities during the next year consisted of $547 million of borrowings under the commercial paper program, $1.750 billion of 5.950% Senior Notes scheduled to mature in September 2016, and $33 million of senior amortizing notes associated with the TEUs as discussed in Sources of Cash—Financing Activities below. The Company classified the outstanding commercial paper notes and the 5.950% Senior Notes as long-term debt on the Company’s Consolidated Balance Sheet, as the Company currently intends to refinance these obligations at maturity with either new long-term debt issuances or the Company’s $3.0 billion five-year senior unsecured revolving credit facility (Five-Year Facility), which is expandable to $4.0 billion, or additional commercial paper notes supported by the Five-Year Facility.

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. None of the Zero Coupons, which had an accreted value of $796 million, were put to the Company in October 2015. The Zero Coupons can be put to the Company in October 2016, in whole or in part, for the then-accreted value of $839 million.

During the third quarter of 2015, the Company extended the reference-period start dates on interest-rate swaps with an aggregate notional principal amount of $1.0 billion to align the portfolio with anticipated debt refinancing. The Company also amended the mandatory termination dates to 2018 for interest-rate swaps with an aggregate notional principal amount of $450 million, to 2020 for interest-rate swaps with an aggregate notional principal amount of $600 million, and to 2021 for interest-rate swaps with an aggregate notional principal amount of $750 million. At the start of the reference period, Anadarko will receive quarterly payments based on the floating rate and make semi-annual payments based on the fixed interest rate. The interest-rate swaps are required to be settled in full at the mandatory termination date. For additional information, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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

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

During the first quarter of 2015, the Company initiated a commercial paper program, which allows a maximum of $3.0 billion of unsecured commercial paper notes and is supported by the Five-Year Facility. At September 30, 2015, the Company had $547 million of commercial paper notes outstanding at a weighted-average interest rate of 0.51%. During the nine months ended September 30, 2015, maximum outstanding borrowings under the commercial paper program were $1.4 billion and the average borrowings outstanding were $790 million with a weighted-average interest rate of 0.59%.

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

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

At September 30, 2015, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $180 million at an interest rate of 1.5%, had outstanding letters of credit of $13 million, and had available borrowing capacity of $1.0 billion. See Sources of Cash—Financing Activities below.

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

Sources of Cash

Operating ActivitiesAnadarko’s cash flow used in operating activities during the nine months ended September 30, 2015, was $2.1 billion, compared to cash flow provided by operating activities of $6.5 billion for the same period of 2014. The decrease is primarily due to the $5.2 billion Tronox settlement payment and decreased sales revenues resulting from lower commodity prices.

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

Investing ActivitiesDuring the nine months ended September 30, 2015, Anadarko received pretax proceeds of $1.2 billion primarily related to the April 2015 sale of certain EOR assets in the Rockies, the July 2015 sale of certain East Texas oil and gas properties and related midstream assets, and the September 2015 sale of certain oil and gas coalbed methane properties in the Rockies.

Financing ActivitiesDuring the nine months ended September 30, 2015, the Company borrowed $1.8 billion under the 364-Day Facility, which was primarily used to repay $1.5 billion of borrowings entered into in January 2015 under its $5.0 billion senior secured revolving credit facility. The remaining proceeds were used for partial payment of the settlement related to the Tronox Adversary Proceeding and for general corporate purposes. The Company also had net borrowings of $547 million of commercial paper notes and sold 2.3 million WGP common units to the public, which raised net proceeds of $130 million, with proceeds from both used for general corporate purposes.

During the second quarter of 2015, Anadarko issued 9.2 million TEUs at a stated amount of $50.00 per TEU and raised net proceeds of $445 million. Each TEU is comprised of a prepaid equity purchase contract for WGP common units, subject to Anadarko’s right to elect to issue and deliver shares of Anadarko’s common stock in lieu of WGP common units, and a senior amortizing note due in June 2018, which bears interest at the rate of 1.50% per year. For additional information, see Note 7—Tangible Equity Units in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

WES borrowed $280 million under its RCF primarily for general partnership purposes, including the funding of capital expenditures. In addition, during the second quarter of 2015, WES completed a public offering of $500 million aggregate principal amount of 3.950% Senior Notes due 2025. Net proceeds from the offering were used to repay a portion of the borrowings under WES’s RCF. During the nine months ended September 30, 2015, WES also issued 874 thousand of its common units to the public under its continuous offering program and raised net proceeds of $57 million.

Uses of Cash

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

46

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

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

	Nine Months Ended   September 30,
millions	2015		2014
Property acquisitions
Exploration	$	78	$	110
Development	56		108
Exploration	561		1,040
Development	3,038		4,636
Capitalized interest	110		137
Total oil and gas capital expenditures	3,843		6,031
Gathering, processing, and marketing and other (1)	732		1,056
Total capital expenditures (2)	$	4,575	$	7,087

 ________________________________________________________________________________________

⁽¹⁾  Includes WES capital expenditures of $405 million for the nine months ended September 30, 2015, and $490 million for the nine months ended September 30, 2014.

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

The Company’s capital spending decreased by $2.5 billion for the nine months ended September 30, 2015, due to decreased development costs of $1.6 billion primarily in the Rockies and the Southern and Appalachia Region and lower exploration costs of $479 million primarily in the Gulf of Mexico and the Southern and Appalachia Region. Also, development acquisitions in 2014 included a spar lease buyout of $110 million in the Gulf of Mexico and gathering, processing, and marketing and other decreased $328 million primarily due to lower expenditures for plants and gathering in the Rockies. In September 2015, the Company acquired certain oil and gas properties in the Delaware basin for $79 million.

In the third quarter of 2014, the Company entered into a carried-interest arrangement that requires a third party to fund $442 million of Anadarko’s capital costs in exchange for a 34% working interest in the Eaglebine development, located in Southeast Texas. The third-party funding is expected to cover Anadarko’s future capital costs in the development through 2020. At September 30, 2015, $85 million of the total $442 million obligation had been funded.

In the second quarter of 2013, the Company entered into a carried-interest arrangement that requires a third-party partner to fund $860 million of Anadarko’s capital costs in exchange for a 12.75% working interest in the Heidelberg development, located in the Gulf of Mexico. The third-party funding is expected to cover the substantial majority of Anadarko’s expected future capital costs through first production, which is expected to occur by mid-2016. At September 30, 2015, $701 million of the total $860 million obligation had been funded.

Investments  During the nine months ended September 30, 2015, the Company made capital contributions of $101 million for equity investments, which are included in Other—net under Investing Activities in the Consolidated Statements of Cash Flows. These contributions were primarily associated with joint ventures for a gas processing plant, marine well containment, and pipelines.

Debt Retirements and Repayments  During the nine months ended September 30, 2015, the Company repaid $1.5 billion of borrowings under the $5.0 billion senior secured revolving credit facility, $1.8 billion under the 364-Day Facility, and $8 million of senior amortizing notes associated with the TEUs. WES also repaid $610 million of borrowings under its RCF primarily from proceeds from WES’s debt offering.

47

Derivative Instruments  The Company’s derivative instruments are subject to individually negotiated credit provisions that may require the Company or the counterparties to provide collateral of cash or letters of credit depending on the derivative portfolio valuation versus negotiated credit thresholds. These credit thresholds may also require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered, such as if the Company’s credit rating from major credit rating agencies declines to below investment grade. The Company provided cash collateral of $67 million as of September 30, 2015, in connection with its derivative instruments.

For additional information, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Common Stock Dividends and Distributions to Noncontrolling Interest Owners  Anadarko paid dividends of $415 million to its common stockholders during the nine months ended September 30, 2015, and $368 million during the nine months ended September 30, 2014. During the second quarter of 2014, Anadarko increased the quarterly dividend paid to common stockholders from $0.18 per share to $0.27 per share. Anadarko has paid a dividend to its common stockholders on a quarterly basis since becoming a public company in 1986. The amount of future dividends paid to Anadarko common stockholders will be determined by the Board of Directors on a quarterly basis and will depend on earnings, financial condition, capital requirements, the effect a dividend payment would have on the Company’s compliance with relevant financial covenants, and other factors.

WES distributed to its unitholders other than Anadarko and WGP an aggregate of $170 million during the nine months ended September 30, 2015, and $128 million during the nine months ended September 30, 2014. WES has made quarterly distributions to its unitholders since its initial public offering in the second quarter of 2008, and has increased its distribution from $0.30 per common unit for the third quarter of 2008 to $0.775 per common unit for the third quarter of 2015 (to be paid in November 2015).

WGP distributed to its unitholders other than Anadarko an aggregate of $27 million during the nine months ended September 30, 2015, and $16 million during the nine months ended September 30, 2014. WGP has made quarterly distributions to its unitholders since its initial public offering in December 2012, and has increased its distribution from $0.17875 per common unit for the first quarter of 2013 to $0.38125 per unit for the third quarter of 2015 (to be paid in November 2015).

Outlook

The Company’s revenues, operating results, cash flows from operations, capital spending, and future growth rates are highly dependent on the prices the Company receives for oil, natural gas, and NGLs, which can fluctuate significantly. During the last 12 months, New York Mercantile Exchange West Texas Intermediate oil prices have been volatile and ranged from a high of $91.01 per barrel in October 2014 to a low of $38.24 in August 2015. New York Mercantile Exchange Henry Hub natural-gas prices have also been volatile and, during the last 12 months, ranged from a high of $4.49 per MMBtu in November 2014 to a low of $2.49 in April 2015. The duration and magnitude of the decline in oil and natural-gas prices cannot be predicted. The decline in oil and natural-gas prices has caused the Company to recognize significant impairment expenses during the nine months ended September 30, 2015, and additional impairments may be recognized in the fourth quarter of 2015 if commodity prices decline further. See Note 4—Impairments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. In addition, while the rolling 12-month average SEC price used to determine the Company’s reported reserve quantities has decreased from December 31, 2014, to September 30, 2015, by approximately 38% for oil, 30% for natural gas, and 47% for NGLs, such commodity price decreases have not had a material impact on DD&A expense for the three or nine months ended September 30, 2015. The Company is unable to predict the amount of future reserve revisions or impairments, if any.

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

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The Company is committed to the execution of its worldwide exploration, appraisal, and development programs. The Company estimates a 2015 capital spending range of $6.0 billion to $6.2 billion. This amount includes approximately $570 million to $610 million of WES capital expenditures, excluding any acquisitions made by WES. The Company has currently allocated approximately 65% of its 2015 capital spending budget to development activities, 15% to exploration activities, and 20% to gathering and processing activities and other business activities. The Company currently expects its 2015 capital spending by area to be approximately 55% for the U.S. onshore region and Alaska, 10% for the Gulf of Mexico, 20% for Midstream and other, and 15% for International.

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

The Company continuously monitors its liquidity needs, coordinates its capital expenditure program with its expected cash flows and evaluates available funding alternatives in light of current and expected conditions. Anadarko enters into strategic derivative positions to reduce commodity-price risk and increase the predictability of cash flows. At September 30, 2015, Anadarko had derivative positions covering approximately 40% of its remaining 2015 anticipated natural-gas sales volumes. In addition, the Company has certain derivative positions in place for 2016. See Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Recent Accounting Developments 

See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

The Company’s primary market risks are attributable to fluctuations in energy prices and interest rates. In addition, foreign-currency exchange-rate risk exists due to anticipated foreign-currency denominated payments and receipts. These risks can affect revenues and cash flows, and the Company’s risk-management policies provide for the use of derivative instruments to manage these risks. Both exchange- and over-the-counter-traded derivative instruments may be subject to margin-deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

COMMODITY-PRICE RISK  The Company’s most significant market risk relates to prices for natural gas, oil, and NGLs. Management expects energy prices to remain unpredictable and potentially volatile. As energy prices decline or rise significantly, revenues and cash flows are likewise affected. In addition, a non-cash write-down of the Company’s oil and gas properties or goodwill may be required if commodity prices experience a significant decline. The types of commodity derivative instruments used by the Company include futures, swaps, options, and fixed-price physical-delivery contracts. The volume of commodity derivatives entered into by the Company is governed by risk-management policies and may vary from year to year. Below is a sensitivity analysis for the Company’s commodity-price-related derivative instruments.

Derivative Instruments Held for Non-Trading Purposes  The Company had derivative instruments in place to reduce the price risk associated with future production of 149 Bcf of natural gas and 10 MMBbls of oil at September 30, 2015, with a net derivative asset position of $168 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $42 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $35 million. However, any cash received or paid to settle these derivatives would be substantially offset by the sales value of production covered by the derivative instruments.

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Derivative Instruments Held for Trading Purposes  At September 30, 2015, the Company had a net derivative asset position of $14 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  Borrowings under each of the 364-Day Facility, the Five-Year Facility, the commercial paper program, and WES’s RCF are subject to variable interest rates. The balance of Anadarko’s long-term debt on the Company’s Consolidated Balance Sheets has fixed interest rates. The Company has $2.9 billion of obligations based on the London Interbank Offered Rate (LIBOR) that are presented on the Company’s Consolidated Balance Sheets net of preferred investments in two non-controlled entities. These obligations give rise to minimal net interest-rate risk because coupons on the related preferred investments are also LIBOR-based. While a 10% change in LIBOR would not materially impact the Company’s interest cost, it would affect fair value of outstanding fixed-rate debt.

At September 30, 2015, the Company had a net derivative liability position of $1.5 billion related to interest-rate swaps. A 10% increase (decrease) in the three-month LIBOR interest-rate curve would increase (decrease) the aggregate fair value of outstanding interest-rate swap agreements by $100 million. However, any change in the interest-rate derivative gain or loss could be substantially offset by changes in actual borrowing costs associated with future debt issuances. For a summary of the Company’s outstanding interest-rate derivative positions, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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

The Company has risk related to exchange-rate changes applicable to cash held in escrow pending final determination of the Company’s Brazilian tax liability for its 2008 divestiture of the Peregrino field offshore Brazil. The Brazilian tax matter is currently under consideration by the Brazilian courts. At September 30, 2015, cash of $86 million was held in escrow. A 10% increase or decrease in the foreign-currency exchange rate would not materially impact the Company’s gain or loss related to foreign currency.

Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (Exchange Act). The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and to ensure that the information required to be disclosed by the Company in reports that it files under the Exchange Act is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of September 30, 2015.

Changes in Internal Control over Financial Reporting

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

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PART II. OTHER INFORMATION

Item 1.  Legal Proceedings

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

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

See Note 12—Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q, which is incorporated herein by reference, for material developments with respect to matters previously reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, and material matters that have arisen since the filing of such report.

Item 1A.  Risk Factors

There have been no material changes from the risk factors included under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

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

The following sets forth information with respect to repurchases by the Company of its shares of common stock during the third quarter of 2015.

Period	Total number of shares purchased (1)	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs	Approximate dollar value of shares that may yet be purchased under the plans or programs
July 1 - 31, 2015	2,407	$	75.76	—
August 1 - 31, 2015	774	$	73.93	—
September 1 - 30, 2015	2,852	$	66.24	—
Total	6,033	$	71.03	—	$	—

 ____________________________________________________________

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

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Item 6.  Exhibits

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

Exhibit Number			Description
	3	(i)	Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated May 21, 2009, filed as Exhibit 3.3 to Form 8-K filed on May 22, 2009
		(ii)	By-Laws of Anadarko Petroleum Corporation, amended and restated as of September 15, 2015, filed as Exhibit 3.1 to Form 8-K filed on September 21, 2015
*	31	(i)	Rule 13a-14(a)/15d-14(a) Certification—Chief Executive Officer
*	31	(ii)	Rule 13a-14(a)/15d-14(a) Certification—Chief Financial Officer
**	32		Section 1350 Certifications
*	101	.INS	XBRL Instance Document
*	101	.SCH	XBRL Schema Document
*	101	.CAL	XBRL Calculation Linkbase Document
*	101	.DEF	XBRL Definition Linkbase Document
*	101	.LAB	XBRL Label Linkbase Document
*	101	.PRE	XBRL Presentation Linkbase Document

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SIGNATURES

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

		ANADARKO PETROLEUM CORPORATION
		(Registrant)
October 27, 2015	By:	/s/ ROBERT G. GWIN
		Robert G. Gwin Executive Vice President, Finance and Chief Financial Officer

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